changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Nicaragua, there is potential labor unrest and strengthening of labor unions, which may adversely affect our Momotombo project. In Kenya, the new government elected in 2002 is making an effort to deliver on campaign promises to reduce the price of electricity and is applying pressure on independent power producers, such as our Olkaria III project, to lower their tariffs. In addition, Kenya's new government is considering a further restructuring and privatization of the electricity industry and may divide Kenya Power & Lighting Co. Ltd., the power purchaser for our Olkaria III project, into separate entities and then privatize one or more of such resulting entities. A material tariff reduction or any break-up and potential privatization of Kenya Power & Lighting Co. Ltd. may adversely affect our Olkaria III project. We have recently held discussions with the Kenyan government and Kenya Power & Lighting Co. Ltd. regarding, among other things, the construction of Phase II of the Olkaria III project in Kenya and the provision of certain collateral and government support. We must notify Kenya Power & Lighting Co. Ltd., by April 17, 2005, whether we will proceed to construct Phase II of the Olkaria III project and, if we notify Kenya Power & Lighting Co. Ltd. that we will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to provide such notification we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. In addition, if we do not proceed with the construction of Phase II, we may lose some or all of our investment relating to Phase II, which is approximately $22.4 million as of June 30, 2004.

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 lenders to a project 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 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 Company, Hawaii Electric Light Company, PNOC-Energy Development Corporation and Sierra Pacific Power Company have accounted for 48.3%, 9.2%, 6.2% and 5.6% of our pro forma revenues, respectively, for the fiscal year ended December 31, 2003. 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 prospectus 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 Company withheld payments it owed under various of its power purchase agreements with a number of power generators (such as the Ormesa, Heber 1, Heber 2, and Mammoth projects) payable for certain energy delivered between November 2000 and March 2001 under such power purchase agreements until March 2002. In the case of our Ormesa project (which we acquired in April 2002), the payment withheld by Southern California Edison Company totaled $21.2 million. 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 Company 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 for auxiliary purposes. We have commenced discussions with Southern California Edison Company to resolve the dispute. In the interim period, Southern California Edison Company has tentatively agreed to pay a lower fixed price for such power. We cannot evaluate the potential long-term financial impact of a failure to reach a resolution with Southern California Edison Company, among other things because the current contract rates will fluctuate as of May 2007, however, financial loss at the reduced price paid by Southern California Edison Company for our fiscal year ended December 31, 2005 may be in the range of $1 million.

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 thereunder may result in the imposition of penalties.

Pursuant to the terms of the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements that we have entered into and under which we will sell electricity from the Galena, Desert Peak 2 and Desert Peak 3 projects that are currently under development and construction, 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. These three power purchase agreements are expected to phase-in and commence generating revenues starting in 2006. When all three are generating revenues, measured against our revenues from the sale of electricity for the period ending June 30, 2004 and assuming no other changes in our revenues, the revenues from such agreements would have constituted, collectively, less than 8% 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 to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant power purchase agreement. 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. The minimum performance requirements are described in "Description of Certain Material Agreements—Project-related Agreements." 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 Puna project was not in compliance with the minimum performance requirements of its power purchase agreement at the time we acquired such project and is currently not in compliance with such requirements. Such non-compliance has resulted in the imposition of sanctions that have reduced, and as long as such non-compliance continues to exist, will continue to reduce, the aggregate amount of revenues payable to us from the power purchaser by approximately $6,000 per month. Further, the temperature of the geothermal resource at our Heber 1 project has declined from the date on which the project commenced operations and, as a result, the project currently operates at a level that is close to the minimum performance requirements set forth in the project's power purchase agreement. If we fail to upgrade the project's facilities and the project's performance deteriorates below the minimum capacity requirements, we will be obligated to pay a one-time penalty to the power purchaser of approximately $500,000 per each MW of reduced capacity.

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 Company 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 Company and a number of Qualifying Facility power generators in California, including our subsidiaries, the energy price component payable by Southern California Edison Company has been fixed through April 2007, and thereafter will be based on Southern California Edison Company's short run avoided costs, as determined by the California Public Utilities Commission, which we refer to as CPUC. These short run avoided costs are made available by Southern California Edison Company to the public and may vary substantially on a monthly basis, based primarily on gas prices and other factors. The levels of short run avoided cost prices paid by Southern California Edison Company may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison Company under our power purchase agreements with it and could materially and adversely affect our business, financial condition, future results and cash flow.

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 its short run avoided costs. These short run avoided costs, and in turn the rates payable by Sierra Pacific Power Company, may decline, which in turn would reduce the aggregate amount of project revenues recovered by our Nevada projects pursuant to the relevant power purchase agreements. Such a decrease in project revenues could adversely affect our business, financial condition, future results and cash flow.

In response to an order issued by a California State Court of Appeal, the CPUC has commenced an administrative proceeding in order to address short run avoided cost pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The court directed the CPUC to modify short run avoided cost pricing on a retroactive basis to the extent that the CPUC determined that short run avoided cost prices were not sufficiently "accurate" or "correct." If the short run avoided cost prices charged during the period in question were determined by the CPUC not to be "accurate" or "correct," retroactive price adjustments could be required for any of our Qualifying Facilities in California whose payments are tied to short run avoided cost pricing, including the Heber 1, Mammoth and Ormesa projects. Currently, it is not possible to predict the outcome of such proceeding, however, any retroactive price adjustment required to be made in relation to any of our projects may require such projects to make refund payments or charge less for future sales, which could materially and adversely affect our business, financial condition, future results and cash flow.

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

The operations of most of our domestic projects are subject to, and benefit from, the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, are subject to limited provisions of the Federal Power Act, which we refer to as FPA, and are potentially subject to the provisions of various other energy laws and regulations, including the Public Utility Holding Company Act of 1935, as amended, which we refer to as PUHCA, other provisions of the FPA and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.

Qualifying Facility status under PURPA exempts our projects from PUHCA, most of the provisions of the FPA, and certain state laws concerning rates and the financial and organizational regulation of electric utilities. If any of our domestic projects in which we have an interest loses its Qualifying Facility status and no regulatory exemptions apply, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded Qualifying Facilities, our operations could be adversely affected.

In the event that one of our domestic projects loses its Qualifying Facility status, such project and we would become subject to PUHCA and such project would become subject to the full scope of the FPA and applicable state regulations unless an exemption or waiver applies, such as "exempt wholesale generator" ("EWG", as defined under PUHCA) status or "utility geothermal small power production facility" (as defined under PURPA regulations) status, for such project. The application of PUHCA and such other regulations to our projects would require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. In the unlikely event that none of the PUHCA exemptions or waivers are available, we could become a public utility holding company under PUHCA, which could be deemed to occur prospectively or retroactively to the date that any of our projects lost its Qualifying Facility status. In addition, our other domestic projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the 50% limit on ownership of Qualifying Facilities by electric utilities or electric utility holding companies. As a result of such loss of Qualifying Facility status, and in the absence of an applicable exemption or waiver, the Federal Energy Regulatory Commission, which we refer to as FERC, or relevant state regulators, whichever has jurisdiction, may order partial refunds of past amounts paid by the relevant power purchaser or order a reduction of the rate pursuant to the power purchase agreement prospectively, or both, and thus could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects.

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 agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our project. 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.

The United States Congress is considering proposed legislation that would amend PURPA by limiting the mandatory purchase obligations of power purchasers under new power purchase agreements. The enactment of such legislation could adversely affect our new projects or enhancements of existing projects that do not have a current power purchase agreement.

An adverse FERC ruling related to the use by a project of power generated from another Qualifying Facility for auxiliary purposes may adversely affect our operations and financial results.

According to a recent FERC decision, a geothermal Qualifying Facility that obtains electricity for the operation of its reinjection pumps from an electric utility must reduce its net capacity available for sale by an equivalent amount. However, if the electricity for reinjection pumping is provided by Qualifying Facilities that are cogeneration or small power production facilities, no reduction in net capacity is required. Two of our projects obtain electricity from an electric utility for the operation of their reinjection pumps. In the past, these projects did not reduce their net capacity available for sale by an equivalent amount. The application of FERC's recent ruling to such projects could have an adverse effect on their revenues received from power sales and their operations and financial condition.

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 is currently, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We and our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.

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 approximately 10% of the construction cost of each new geothermal power plant as a credit against our consolidated federal income taxes. We are also permitted to deduct, as a depreciation expense on our consolidated federal tax returns, up to 95% of the cost of the power plant over five years on an accelerated basis, which results in more of the cost being deducted in the first few years than during the remainder of the depreciation period. In addition, we have the ability to obtain value from these tax incentives through lease financing transactions even when we are not in a position to use them directly. Any reduction in such tax incentives or any restrictions on such lease financing transactions would materially and adversely 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, which currently are significant, may increase in the future and could materially and adversely affect our business, financial condition, future results and cash flow and 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 a result of which the operation of the projects may 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.

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 liability exposure 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 that we have acquired or which we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.

We recently acquired our Heber 1, Heber 2, Mammoth, Steamboat 2/3, Steamboat Hills and Puna projects. 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 with a capacity price component 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.

If a project experiences a force majeure event, our subsidiary owning 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 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 Heber 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 pro forma revenues in 2003 from the projects utilizing the Imperial Irrigation District transmission system were approximately $98.6 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 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 flows.

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 each 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.

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

Our success is largely dependent on the skills, experience and efforts of our senior management team and other key personnel. In particular, our success depends on the continued efforts of Lucien Bronicki, Yehudit Bronicki, 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, Yehudit 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 120 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. If our project subsidiaries default on their obligations under such limited- or non-recourse debt, 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. Non-recourse project finance debt refers to debt that is repaid solely from the project's revenues and is 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 central 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. 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 counterparties in transactions.

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

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

Operations in Israel accounted for approximately 61.3%, 56.3%, and 51.0% of our operating expenses in fiscal year 2001, fiscal year 2002 and fiscal year 2003, 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, and more recently Israel has experienced a significant increase in terrorist incidents within its borders. As a result, negotiations between Israel and representatives of the 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 by the Government of Israel as an "approved enterprise" may require us to refund such tax benefits and pay future taxes in Israel at higher rates.

Our subsidiary, Ormat Systems, has received "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 reduced Israeli income tax rates 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 rates, 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 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, extendable to twenty-five years (which includes the initial term) should our parent obtain the approval of the Israel Land Administration, to the extent necessary. If such an approval is required and our parent fails to obtain the Israel Land Administration's approval, our sublease will terminate on June 1, 2009, at which time we will have to renegotiate the terms of a new sublease. We may not be successful in reaching an agreement with our parent as to the terms of a new sublease or in obtaining such sublease on favorable terms, both of which would adversely affect our manufacturing activities and our financial position. Additionally, if our parent were to breach its obligations to the Israel Land Administration under its lease agreement, the Israel Land Administration could terminate the lease agreement and, consequently, our sublease would terminate as well.

As part of the acquisition described in the preceding paragraph, we also entered into a patent license agreement with Ormat Industries, pursuant to which we were granted an exclusive license for certain patents and trademarks relating to certain technologies that are used in our business. If a bankruptcy case were commenced by or against our parent, it is possible that performance of all or

part of the agreements entered into in connection with such acquisition (including the lease of land and facilities described above) could be stayed by the bankruptcy court in Israel or rejected by a liquidator appointed pursuant to the Bankruptcy Ordinance in Israel and thus not be enforceable. Any of these events could have a material and adverse effect on our business, financial condition, future results and cash flow.

We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the 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.

Risks Relating to this Offering

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

Immediately following this offering, 79.6% of our common stock will be held by Ormat Industries, Ltd. (77.2% if the underwriters exercise their over-allotment option in full), which is controlled by Bronicki Investments Ltd. Bronicki Investments Ltd. is a privately held Israeli company and is controlled by Lucien and Yehudit Bronicki. Because of these holdings, our parent company and its controlling stockholders 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.

Some of our directors that also hold positions with our parent may have conflicts of interest with respect to matters involving both companies.

Two of our three directors are directors and/or officers of Ormat Industries. These directors will have 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 Chairman, Director and Chief Technology Officer, Mr. Bronicki, will continue to be Chairman of our parent following the offering. In addition, our Chief Executive Officer and Director, Mrs. Bronicki, will continue to be the Chief Executive Officer of our parent following the offering.

There has been no prior market for our common stock and an active trading market may not develop.

Prior to this offering, there has been no public market for our common stock. An active trading market may not develop following the closing of this offering or, if developed, may not be sustained.

The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. The lack of an active market may also reduce the fair market value and increase the volatility of your shares of common stock. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or technologies by using our shares of common stock as consideration.

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

The initial public offering price for the shares of our common stock sold in this offering will be determined by negotiation between the representative of the underwriters and us. This price may not reflect the market price of our common stock following this offering. In addition, 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.

Our management team may invest or spend the proceeds of this offering in ways with which you may not agree or in ways that may not yield a positive return.

Presently, anticipated uses of the proceeds to us of this offering include funding business growth and expansion, providing additional working capital, and for other general corporate purposes. We cannot specify with certainty how we will use the net proceeds of this offering. Accordingly, our management will have considerable discretion in the application of these proceeds, and you will not have the opportunity to assess whether these proceeds are being used appropriately. These proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce income or that lose value.

Future sales of our common stock may depress our share price.

After this offering, we will have 30,624,996 shares of common stock outstanding. The 6,250,000 shares sold in this offering (or 7,187,500 shares if the underwriters' over-allotment option is exercised

in full) will be freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. The remaining shares of common stock outstanding after this offering are subject to lock-up agreements, will be available for sale in the public market beginning 180 days after the date of this prospectus, and will be subject to certain volume limitations under Rule 144 of the Securities Act of 1933, as amended. Lehman Brothers Inc. may waive the lock-up provisions in its sole discretion.

Sales of substantial amounts of our common stock in the public market following this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. At or prior to the closing of this offering, we will enter into a registration rights agreement with Ormat Industries. See "Certain Relationships and Related Transactions" for more information.

This offering will cause substantial dilution in the net tangible book value of your shares of common stock.

The initial public offering price of our common stock is considerably more than the net tangible book value per share of our outstanding common stock. Accordingly, investors purchasing shares of common stock in this offering will contribute 78.8% of the total amount invested to fund our company, but will own only 20.4% of the shares of common stock outstanding after this offering. To the extent outstanding stock options are exercised, there will be further dilution to new investors. See "Dilution" for more information.

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 will be classified into three classes of directors serving staggered, three-year terms and may be removed only for cause. Any vacancy on the board of directors may be filled only by the vote of the majority of directors then in office. Our board of directors has the right to issue preferred stock without stockholder approval, which could be used to institute a "poison pill" that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by our board of directors. Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the statements made in this prospectus are forward-looking statements. These forward looking statements are based upon our current expectations and projections about future events. When used in this prospectus, the words "believe", "anticipate", "intend", "estimate", "expect", "should", "may" and similar expressions, or the negative of such words and expressions, are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this prospectus are primarily located in the material set forth under the headings "Prospectus Summary", "Risk Factors", "Capitalization", "Management's Discussion and Analysis of Financial Condition and Results of Operations", and "Business", 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 prospectus completely and with the understanding that actual future results may be materially different from what we expect. 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 or may affect the value of our common stock include, but are not limited to:

•	significant considerations and risks discussed in this prospectus;

•	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;

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

•	current and future litigation;

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

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

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

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

•	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.

USE OF PROCEEDS

We estimate that the net proceeds we will receive from this offering will be approximately $89.9 million, or approximately $103.8 million if the underwriters exercise their over-allotment option in full, in each case after deducting the underwriting discounts and commissions and estimated expenses of this offering payable by us. We expect to use all of the net proceeds from this offering for general corporate purposes, which may include making investments or acquisitions. We have no present understanding or agreement relating to any specific acquisition. Accordingly, management will have significant flexibility in applying the net proceeds of the offering. Pending the use of such proceeds as described above, we intend to invest such proceeds in interest-bearing investment-grade instruments or bank deposits.

DIVIDEND POLICY

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

Notwithstanding this policy, dividends will be paid only when, as and if approved by our board of directors out of funds legally available therefor. The actual amount and timing of dividend payments will depend upon our financial condition, results of operations, business prospects and such other matters as the board may deem relevant from time to time. Even if profits are available for the payment of dividends, the board of directors could determine that such profits should be retained for an extended period of time, used for working capital purposes, expansion or acquisition of businesses or any other appropriate purpose. As a holding company, we are dependent upon the earnings and cash flow of our subsidiaries in order to fund any dividend distributions, and, as a result, we may not be able to pay dividends in accordance with our policy. Our board of directors may, from time to time, examine our dividend policy and may, in its absolute discretion, change such policy. In accordance with this policy, conditional upon, and effective as of, the effectiveness of the registration statement of which this prospectus forms a part, we will pay an interim dividend for 2004 of $2.5 million to our parent company, Ormat Industries.

CAPITALIZATION

The following table summarizes our capitalization as of June 30, 2004 on:2004:

•	on a historical basis; and

•

(a) on a pro forma basis to give effect to (i) an interim dividend for 2004 of $2.5 million to our parent company pursuant to our dividend policy that is conditional upon, and effective as of the effectiveness of this registration statement, and (ii) the $4.8 million cash payment and the reclassification of the divisional deficit of $10.3 million to retained earnings related to the purchase on July 1, 2004 of our parent's power generation business; and (b) as adjusted to give effect to the completion of this offering, including the application of the estimated net proceeds to us from this offering as described under "Use of Proceeds."

You should read the following table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Description of Capital Stock" and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

				As of June 30, 2004										As of June 30, 2004
				Actual				Pro Forma As Adjusted						Actual				Pro Forma As Adjusted
				(unaudited)										(unaudited)
				(in thousands)										(in thousands)
Cash and cash equivalents	Cash and cash equivalents			$	21,170			$	108,542		Cash and cash equivalents			$	21,170			$	103,742
Debt:	Debt:										Debt:
Parent company loans	Parent company loans				193,852				193,852		Parent company loans				193,852				193,852
Long-term debt	Long-term debt				442,300				442,300		Long-term debt				442,300				442,300
Total debt	Total debt				636,152				636,152		Total debt				636,152				636,152
Shareholders' equity:	Shareholders' equity:			Shareholders' equity:
Common stock, $0.001 par value; 200,000,000 shares authorized and 24,374,996 shares issued and outstanding, historical; 200,000,000 shares authorized and 30,624,996 shares issued and outstanding, pro forma as adjusted	Common stock, $0.001 par value; 200,000,000 shares authorized and 24,374,996 shares issued and outstanding, historical; 200,000,000 shares authorized and 30,624,996 shares issued and outstanding, pro forma as adjusted				24				30		Common stock, $0.001 par value; 200,000,000 shares authorized and 24,374,996 shares issued and outstanding, historical; 200,000,000 shares authorized and 30,624,996 shares issued and outstanding, pro forma as adjusted				24				30
Additional paid-in capital	Additional paid-in capital				27,001				116,867		Additional paid-in capital				27,001				116,867
Divisional deficit	Divisional deficit				(10,293	)			(10,293	)	Divisional deficit				(10,293	)			—
Unearned stock-based compensation	Unearned stock-based compensation				(51	)			(51	)	Unearned stock-based compensation				(51	)			(51	)
Retained Earnings	Retained Earnings				46,551				44,051		Retained Earnings				46,551				28,958
Total shareholders' equity	Total shareholders' equity				63,232				150,604		Total shareholders' equity				63,232				145,804
Total capitalization	Total capitalization			$	699,384			$	787,484		Total capitalization			$	699,384			$	781,956

The discussion and tables above exclude (i) 230,000 shares of our common stock issuable upon the exercise of stock options that will be outstanding as of the effective date of the registration statement, and (ii) 1,020,000 shares of our common stock reserved for future issuance under our 2004 Incentive Compensation Plan. See "Management—Stock Option Plan."

DILUTION

At June 30, 2004, the net tangible book value of our common stock was approximately $13.5 million, or approximately $0.56 per share of our common stock. After giving effect to the sale of shares of our common stock in this offering at an assumed initial public offering price of $16.00 per share, and after deducting estimated underwriting discounts and commissions paid by us and the estimated expenses of this offering, the net tangible book value at June 30, 2004 attributable to common stockholders would have been approximately $103.8 million, or approximately $3.38 per share of our common stock. This represents an immediate increase in net tangible book value of $2.82 per share, and an immediate dilution in net tangible book value of $12.62 per share to new stockholders. The following table illustrates this per share dilution to new stockholders:

Assumed initial public offering price per share								$	16.00
Net tangible book value per share before the offering				$	0.56
Net increase in tangible book value per share attributable to new stockholders					2.82
Net tangible book value per share after the offering									3.38
Dilution in net tangible book value per share to new stockholders								$	12.62

The table below summarizes, as of June 30, 2004, the differences for our existing stockholders and new stockholders in this offering, with respect to the number of shares of common stock purchased from us, the total consideration paid and the average price per share paid before deducting fees and expenses.

				Shares Issued								Total Consideration								Average Price Per Share
				Number				Percentage				Amount				Percentage
				(dollars in thousands, except per share data)
Our existing stockholders					24,374,996				79.6	%		$	26,862				21.2	%		$	1.10
New stockholders in this offering					6,250,000				20.4	%			100,000				78.8	%			16.00
Total					30,624,996				100.0	%		$	126,862				100.0	%

The discussion and tables above exclude (i) 230,000 shares of our common stock issuable upon the exercise of stock options that will be outstanding as of the effective date of the registration statement, and (ii) 1,020,000 shares of our common stock reserved for future issuance under our 2004 Incentive Compensation Plan. See "Management—Stock Option Plan."

SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA

The following table sets forth our selected consolidated financial and other data for the periods ended and at the dates indicated. We have derived the selected consolidated financial and other data as of and for the periods ended December 31, 2001, 2002 and 2003 from our audited consolidated financial statements included elsewhere in this prospectus. We have derived the selected consolidated financial data as of and for the periods ended December 31, 1999 and 2000 from our unaudited consolidated financial statements not included in this prospectus. We have derived the selected consolidated financial and other data as of and for the six months ended June 30, 2003 and June 30, 2004 from our unaudited consolidated financial statements included elsewhere in this prospectus. In the opinion of our management, our unaudited consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of our financial position, results of operations and cash flows. The results of operations for the six months ended June 30, 2003 and June 30, 2004 are not necessarily indicative of the operating results to be expected for the full fiscal years encompassing such periods.

The information set forth below should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements included elsewhere in this prospectus.

				Year Ended December 31,																				Six Months Ended June 30,
				1999				2000				2001				2002				2003				2003				2004
				(unaudited)								(in thousands, except per share data)												(unaudited)
Statement of Operations Data:
Revenues:
Electricity Segment:
Energy and capacity				$	15,169			$	20,780			$	33,956			$	65,491			$	77,752			$	35,651			$	48,048
Lease					—				—				—				—				—				—				22,167
Total Electricity Segment					15,169				20,780				33,956				65,491				77,752				35,651				70,215
Products Segment					64,388				27,780				13,959				20,138				41,688				16,022				29,491
					79,557				48,560				47,915				85,629				119,440				51,673				99,706
Cost of revenues:
Electricity Segment:
Energy and capacity					6,847				8,556				12,536				33,482				46,726				22,165				29,440
Lease					—				—				—				—				—				—				11,172
Total Electricity Segment					6,847				8,556				12,536				33,482				46,726				22,165				40,612
Products Segment					40,644				22,709				17,454				17,293				29,494				10,306				23,122
					47,491				31,265				29,990				50,775				76,220				32,471				63,734
Gross Margin					32,066				17,295				17,925				34,854				43,220				19,202				35,972
Operating Expenses:
Research and development expenses					3,289				2,260				1,729				1,503				1,391				871				1,202
Selling and marketing expenses					6,593				3,624				6,535				6,051				7,087				2,666				3,946
General and administrative expenses					7,614				6,632				5,444				7,073				9,252				4,053				5,219
Operating income					14,570				4,779				4,217				20,227				25,490				11,612				25,605
Other income (expense):
Interest income					961				1,499				1,323				609				607				299				431
Interest expense					(3,793	)			(3,700	)			(4,333	)			(6,179	)			(8,120	)			(3,835	)			(19,475	)
Foreign currency translation and transaction gain (loss)					(9	)			25				305				(323	)			(316	)			(151	)			(397	)
Other non-operating income					223				7,884				300				1,195				464				278				145
Income from continuing operations before income taxes, minority interest and equity in income of investees					11,952				10,487				1,812				15,529				18,125				8,203				6,309
Income tax provision					(3,226	)			(494	)			(3,065	)			(6,135	)			(2,506	)			(2,173	)			(1,957	)
Minority interest in earnings of subsidiaries					(277	)			(550	)			(645	)			(1,194	)			(519	)			(399	)			(108	)
Equity in income of investees					4				69				166				314				559				188				2,035
Income (loss) from continuing operations					8,453				9,512				(1,732	)			8,514				15,659				5,819				6,279
Discontinued operations:
Loss from operations of discontinued activities in Kazakhstan					(3,374	)			(2,911	)			(4,681	)			(3,114	)			—				—				—
Loss on sale of Kazakhstan operations					—				—				—				(6,444	)			—				—				—

				Year Ended December 31,																				Six Months Ended June 30,
				1999				2000				2001				2002				2003				2003				2004
				(unaudited)								(in thousands, except per share data)												(unaudited)
Income (loss) before cumulative effect of change in accounting principle					5,079				6,601				(6,413	)			(1,044	)			15,659				5,819				6,279
Cumulative effect of change in accounting principle (net of tax benefit of $125)					—				—				—				—				(205	)			(205	)			—
Net income (loss)				$	5,079			$	6,601			$	(6,413	)		$	(1,044	)		$	15,454			$	5,614			$	6,279
Basic and diluted income (loss) per share:
Income (loss) from continuing operations				$	0.36			$	0.41			$	(0.07	)		$	0.37			$	0.67			$	0.25			$	0.27
Loss from discontinued operations					(0.14	)			(0.13	)			(0.20	)			(0.41	)			—				—				—
Cumulative effect of change in accounting principle					—				—				—				—				(0.01	)			(0.01	)			—
Net income (loss)				$	0.22			$	0.28			$	(0.27	)		$	(0.04	)		$	0.66			$	0.24			$	0.27
Weighted average number of shares outstanding					23,214,281				23,214,281				23,214,281				23,214,281				23,214,281				23,214,281				23,227,036
Balance Sheet Data (at end of period):
Cash and cash equivalents				$	7,803			$	10,071			$	13,202			$	36,684			$	8,873			$	17,719			$	21,170
Working capital (deficit)(1)					(6,037	)			(23,392	)			(50,459	)			(79,853	)			2,677				(76,975	)			11,124
Property, plant and equipment, net					60,167				90,946				132,369				152,342				344,015				160,697				472,217
Total assets(1)					139,266				167,940				226,617				287,378				543,138				275,463				778,183
Long-term debt					51,118				61,358				91,321				95,807				260,488				101,041				442,300
Notes payable to Parent					—				—				—				—				177,004				—				193,852
Stockholder's equity(1)					21,335				29,001				22,966				27,837				36,975				35,096				63,232

(1) As described in Note 20 to the financial statements, the balance sheets as of December 31, 1999, 2000, 2001, 2002 and 2003 have been revised to reclassify certain amounts due to/from our parent, originally reported as an asset/liability, as a component of stockholder's equity. As a result of such revision, the (i) working capital increased (reduced) by $(5,173), $(4,716), $(592), $1,806, and $(4,549); (ii) total assets increased (reduced) by $0, $0, $7,227, $0, and $(4,398); and (iii) stockholder's equity increased (reduced) by $(5,514), $(4,449), $(2,938), $1,806, and $(4,549), as of December 31, 1999, 2000, 2001, 2002, and 2003, respectively.

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL DATA

The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2003 and for the six months ended June 30, 2004 are based on our consolidated financial statements and the financial statements of the Puna, Heber 1, Heber 2 and Mammoth projects, which Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project were acquired on December 18, 2003, and the Puna project was acquired on June 3, 2004 and adjusted to give effect to the acquisitions thereof as if each had occurred on January 1, 2003.

The unaudited pro forma condensed combined financial data gives effect to the acquisitions of the Puna, Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project, which are accounted for using the purchase method of accounting. Pursuant to such method, the purchase price has been allocated to the principal categories of assets and liabilities based on independent valuations. It should be noted that because the acquisitions of the (i) Steamboat 1/1A project on June 30, 2003, (ii) Steamboat 2/3 project on February 11, 2004, and (iii) Steamboat Hills project on May 20, 2004 are not material under applicable Securities Act rules, such transactions have not been included in the accompanying pro forma balance sheet or results of operations. The historical unaudited combined revenues and combined net income of the Steamboat 1/1A, Steamboat 2/3 and Steamboat Hills projects for the twelve months ended December 31, 2003 amounted to revenues of $19.7 million and combined net income of $1.7 million.

The unaudited pro forma condensed combined financial data also give effect to (i) Ormat Funding's issuance of 8¼% senior secured notes in the amount of $190 million, which offering was completed on February 13, 2004, and (ii) Orcal Geothermal's entering into a loan agreement with Beal Bank amounting to $154.5 million in connection with the acquisition of the Heber 1, Heber 2 and Mammoth projects.

The unaudited pro forma condensed combined financial data presented herein does not necessarily reflect what our actual results of operations would have been had the transactions occurred at the dates indicated, or project our results of operations for any future date or period.

The unaudited pro forma condensed combined financial data should be read in conjunction with our historical consolidated financial statements and the historical financial statements of the Heber 1, Heber 2, Mammoth and Puna projects included elsewhere in this prospectus.

Unaudited Pro Forma Condensed
Combined Statement of Operations
For the Six Months Ended June 30, 2004
(in thousands, except per share data)

				Ormat Technologies Consolidated				Puna Project for the period from January 1, 2004 to June 2, 2004				Pro Forma Adjustments				Pro Forma Combined
Revenues:
Electricity Segment				$	70,215			$	9,759							$	79,974
Products Segment					29,491				—								29,491
					99,706				9,759								109,465
Cost of revenues:
Electricity Segment					40,612				8,353				(1,337	)(a)			47,941
													313	(b)
Products Segment					23,122				—								23,122
					63,734				8,353								71,063
Gross margin					35,972				1,406								38,402
Operating expenses:
Selling, general and administrative					10,367				842								11,209
Operating income					25,605				564								27,193
Other income (expense):
Interest income					431				—								431
Interest expense					(19,475	)			(4,147	)			4,147	(c)			(23,498	)
													(2,098	)(d)
													(1,925	)(f)
Foreign currency translation and transaction loss					(397	)			—								(397	)
Miscellaneous income					145				—								145
Income before income taxes, minority interest and equity in income of investees					6,309				(3,583	)							3,874
Income tax provision					(1,957	)			1,362				(459	)(g)			(1,054	)
Minority interest in earnings of subsidiaries					(108	)			—								(108	)
Equity in income of investees					2,035				—								2,035
Net income				$	6,279			$	(2,221	)						$	4,747
Pro forma net income per share — basic and diluted				$	0.27											$	0.20
Shares used in computing pro forma net income per share — basic and diluted					23,227,036												23,227,036

Unaudited Pro Forma Condensed
Combined Statement of Operations
For the Year Ended December 31, 2003
(in thousands, except per share data)

				Ormat Technologies Consolidated				Heber Projects for the period from January 1, 2003 to December 17, 2003				Puna Project				Pro Forma Adjustments				Pro Forma Combined
Revenues:
Electricity Segment				$	77,752			$	66,131			$	18,737							$	162,620
Products Segment					41,688				—				—								41,688
					119,440				66,131				18,737								204,308
Cost of revenues:
Electricity Segment					46,726				37,483				14,735				(1,588	)(a)			98,901
																	1,545	(b)
Products Segment					29,494				—				—								29,494
					76,220				37,483				14,735								128,395
Gross margin					43,220				28,648				4,002								75,913
Operating expenses:
Selling, general and administrative					17,730				29				1,605								19,364
Operating income					25,490				28,619				2,397								56,549
Other income (expense):
Gain on discharge of liabilities subject to compromise					—				31,460				—								31,460
Reorganization costs					—				(4,029	)			—								(4,029	)
Interest income					607				99				—								706
Interest expense					(8,120	)			(1,794	)			(3,423	)			5,217	(c)			(40,363	)
																	(16,785	)(d)
																	(11,608	)(e)
																	(3,850	)(f)
Foreign currency translation and transaction loss					(316	)			—				—								(316	)
Miscellaneous income					464				—				—								464
Income from continuing operations before income taxes, minority interest and equity in income of investees					18,125				54,355				(1,026	)							44,471
Income tax provision					(2,506	)			(20,655	)			390				10,793	(g)			(11,978	)
Minority interest in earnings of subsidiaries					(519	)			—				—								(519	)
Equity in income of investees					559				—				—				967	(h)			1,526
Income before cumulative effect of change in accounting principle				$	15,659			$	33,700			$	(636	)						$	33,500
Pro forma income per share — basic and diluted				$	0.67															$	1.44
Shares used in computing pro forma income per share — basic and diluted					23,214,281																23,214,281

Notes to Unaudited Pro Forma
Condensed Combined Financial Data

The following adjustments were applied to our historical financial statements and those of the Puna, Heber 1, Heber 2 and Mammoth projects in order to prepare the pro forma condensed combined financial data.

Statements of Operations Footnotes:

The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2003 and for the six months ended June 30, 2004 are based on our consolidated financial statements and the financial statements of the Puna, Heber 1, Heber 2 and Mammoth projects, and adjusted to give effect to the acquisitions as if they had occurred as of January 1, 2003 by: (1) combining our results of operations for the year ended December 31, 2003 and the six months ended June 30, 2004, with (i) the Puna project's operations for the year ended December 31, 2003 and for the period from January 1, 2004 to June 2, 2004, and (ii) the Heber 1 and Heber 2 projects' operations for the period from January 1, 2003 to December 17, 2003, and (2) recording our 50% equity in the income of the Mammoth project for the period from January 1, 2003 to December 17, 2003, with our results for the year ended December 31, 2003.

(a)    Represents the recording of the change in depreciation resulting from the (step-down)/step-up in basis of $(80.3) million and $110 million of property, plant and equipment to their respective fair values related to the acquisitions of the Puna, Heber 1, and Heber 2 projects, respectively. Property, plant and equipment are being depreciated using the straight-line method over the estimated service period of 15 to 23 years. The step-down of $80.3 million related to the Puna project represents the difference between the net book value of the Puna project's long-lived assets prior to our purchase and the fair value allocated to the Puna project's power plant based on an independent valuation. Despite the step-down upon our purchase of the Puna project, no impairment charge was recorded as detailed impairment analysis during periods prior to our purchase concluded that the sum of the undiscounted expected future cash flows were more than the carrying amount of the Puna project's long-lived assets.

(b)    Represents the recording of the change in amortization resulting from the step-up in basis of $14.4 million and $25.3 million of power purchase agreements to their respective fair values related to the acquisition of the Puna, Heber 1 and Heber 2 projects, respectively, using the straight-line method over the estimated contract periods of 15 to 23 years.

(c)    Represents the elimination of interest expense related to (i) the Puna project of $4.1 million (which includes $2.8 million related to the termination of an interest rate swap agreement discussed below) for the six months ended June 30, 2004 and $3.4 million for the year ended December 31, 2003 and (ii) the Heber 1 and Heber 2 projects of $1.8 million for the period from January 1, 2003 to December 17, 2003. The Puna project included $43.3 million of indebtedness which was repaid on June 3, 2004. The average interest rate on approximately 75% of such indebtedness was 8.17% and 3% on approximately 25% of such indebtedness. In addition, an interest rate swap agreement in connection with the Puna project indebtedness was terminated on June 3, 2004. Notes payable in connection with the Heber 1 and Heber 2 projects in the amount of $12.5 million, which notes payable were terminated as part of the acquisition thereof, accrued interest at LIBOR plus 4.75% per annum from January 31, 2002 through July 31, 2003. Such indebtedness was extinguished as of December 17, 2003. Capital leases related to the Heber 1 and Heber 2 projects, which were also terminated as part of the acquisition thereof, in the amount of $19.7 million, accrued interest at 5.34% per annum. Such indebtedness was extinguished as of January 30, 2004.

(d)    Represents the recording of interest expense, prior to February 13, 2004, associated with the gross proceeds of $190 million pursuant to the issuance by Ormat Funding of the senior secured notes with an interest rate of 8.25%, in the amount of $1.9 million for the period from January 1, 2004 to February 13, 2004 and $15.7 million for the fiscal year ended December 31, 2003, and the amortization of debt issue costs in the amount of $0.2 million for the period from January 1, 2004 to February 13, 2004 and $1.1 million for the fiscal year ended December 31, 2003.

(e)    Represents the recording of interest expense associated with the gross proceeds of $154.5 million from Beal Bank with an interest rate of 7.125% in the amount of $11.0 million for the fiscal year ended December 31, 2003, and the amortization of debt issue costs in the amount of $0.6 million for the fiscal year ended December 31, 2003. Such debt was incurred for the acquisition of the Heber 1 and Heber 2 projects.

(f) Represents the recording of interest expense in the amount of $1.1 million for the six months ended June 30, 2004 and $2.3 million for the fiscal year ended December 31, 2003 related to shareholder loans in the amount of $32.8 million bearing an interest rate of 7.5% and interest expense of $0.8 million for the six months ended June 30, 2004 and $1.6 million for the fiscal year ended December 31, 2003, related to short-term loans of $40 million bearing an interest rate of 4%. The shareholder loans and short-term loans were incurred in connection with the acquisition of the Puna project.

(g)    Represents the recording of income tax expenses to reflect an effective tax rate of 40% on the pro forma adjustments, which is our expected effective tax rate.

(h)    Represents the recording of our 50% equity in the income of the Mammoth project (net of taxes in the amount of $645), increased by the amortization of the equity basis difference, and has been presented as "Equity in income of investee." As the purchase price is less than the underlying net equity of the Mammoth project by $9.5 million, the equity basis will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements, which is approximately 12 to 17 years.

Summarized statement of operations information of the Mammoth project for the period from January 1, 2003 to December 17, 2003 is as follows (in thousands):

Revenues				$	16,353
Gross margin					4,288
Net income					2,024
Company's equity in income of the Mammoth project:
50% of the Mammoth project net income				$	1,012
Plus amortization of the equity basis difference					600
				$	1,612

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 prospectus, 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 "Special Note Regarding Forward-Looking Statements." You should also review the "Risk Factors" section of this prospectus 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. Unless specifically stated otherwise, references to balances and results of operations in this section are to our continuing operations and do not include our discontinued operations discussed below. For a discussion of the effect of our significant acquisitions, please see "Unaudited Pro Forma Condensed Combined Financial Data" included elsewhere in this prospectus, which does not include the acquisition of the Steamboat 2/3 project and Steamboat Hills project.

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 power plants, and we also design, develop and build, and plan to own and operate, recovered energy-based power plants, in each case, 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 principal business segments. The first consists of the sale of electricity from our power plants, which we refer to as the Electricity Segment, while 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 currently consists of our investment in power plants producing electricity from geothermal resources. It will also include our planned investment in power plants producing electricity from recovered energy resources. Our geothermal power plants include both power plants that we have built and power plants that we have acquired. 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 six months ended June 30, 2004, our Electricity Segment represented approximately 70.4% of our total revenues, while our Products Segment represented approximately 29.6% of our total revenues during such period.

Our Electricity Segment operations are conducted in the United States and throughout the world. We are the fastest growing geothermal power generation company in the United States, measured by growth in generating capacity. We have increased our net ownership interest in generating capacity by 164 MW between December 31, 2002 and June 30, 2004, of which 152 MW was attributable to our acquisition of geothermal power plants from third parties and 12 MW was attributable to increased generating capacity of our existing geothermal power plants resulting from plant technology upgrades and improvements to our geothermal reservoir operations, which include improving methods of heat source supply and delivery. Since January 1, 2001, we have completed various acquisitions of geothermal power plants in the United States with an aggregate acquisition cost, net of cash received, of $502.3 million. We also own and operate or control and operate geothermal projects in Guatemala, Kenya, Nicaragua and the Philippines. In 2003, pro forma revenues from the sale of electricity by our

power plants were $162.6 million. Our net ownership in our generating capacity has increased from 94 MW, as of December 31, 2001, to 305 MW, as of June 30, 2004. Such revenues do not include any revenues attributable to our Steamboat 2/3 project and Steamboat Hills project that were acquired in 2004, which we estimate (based on, in the case of the Steamboat 2/3 project, $14.0 million of revenues generated by such project in 2003 and, in the case of the Steamboat Hills project, $3.0 million based on the current revenue generation of such project, computed on an annualized basis) to be approximately $17.0 million for the fiscal year ended December 31, 2003.

Our Products Segment operations are also conducted in the United States and throughout the world. For the fiscal year ended December 31, 2003, revenues attributable to our Products Segment were $41.7 million. Such revenues included approximately $5.0 million received from the construction of a recovered energy-based power plant in a gas processing plant in the United States. We expect that an important component of our Products Segment will be the design, manufacturing and sale of recovered energy products, which is a market opportunity we have identified that we expect will allow us (in our Electricity Segment) and potential customers (in our Products Segment) to utilize waste heat for the purpose of producing electricity.

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. By contrast, revenues attributable to our Products Segment, which are based on the sale of equipment and the provision of various services to our customers are far less predictable and may vary significantly from period to period. 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. 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.

Recent Developments

In December 2003, we acquired our Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project for a total cost of approximately $256.8 million. The acquisition of our Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project was financed with a combination of parent company loans, project finance debt provided by Beal Bank and short-term loans. We accounted for such acquisition pursuant to the purchase method of accounting in accordance with Statement of Financial Accounting Standards (which we refer to as SFAS) No. 141.

In February 2004, we acquired the Steamboat 2/3 project for a total cost of approximately $82.8 million. The acquisition of the Steamboat 2/3 project was financed with a portion of the proceeds received from the issuance of the 8¼% senior secured notes by Ormat Funding. Such acquisition was accounted for pursuant to the purchase method of accounting in accordance with SFAS No. 141.

At the end of May 2004, we acquired the Steamboat Hills project for a total cost of approximately $20.3 million and in early June 2004, we acquired the Puna project for a total cost of approximately $71.2 million. The acquisition of the Steamboat Hills project was financed with internally generated cash while the acquisition of the Puna project was financed with parent company loans and short-term loans. We accounted for the acquisitions of both of the Puna and Steamboat Hills projects pursuant to the purchase method of accounting in accordance with SFAS No. 141.

As a result of our recent acquisitions, our results of operations for the various periods covered by our financial statements attached hereto may not be comparable with each other or indicative of future results.

Trends and Uncertainties

The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation due to increasing 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. Our operations and the trends that from time to time impact our operations are subject to market cycles.

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

•

We have experienced significant growth through the acquisition and enhancement of geothermal power plants. On a pro forma basis, the Heber 1 and Heber 2 projects and the Puna project accounted for 33.3% and 9.2% of our pro forma revenues, respectively, and 52.3% and 4.2% of our pro forma operating profits, respectively, for the fiscal year ended December 31, 2003. As a result of such acquisitions, we expect an increase in our revenues and operating profits for the current fiscal year, as compared to our consolidated revenues and operating profits for the fiscal year ended December 31, 2003. We also expect an increase in our revenues and operating profits for the current fiscal year as a result of the acquisition of the Steamboat 2/3 project and the Steamboat Hills project this year.

•

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 17 states, including California, Nevada and Hawaii (where we have been the most active in our geothermal development and in which all of our U.S. 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.

•

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.

•

We have identified recovered energy-based power generation as a significant market opportunity for us in the United States and throughout the world. We are initially targeting the North American market and, thereafter, we intend to leverage our success in such market in order to expand such operations throughout the world. If our expectations regarding the growth in demand for our recovered energy units are not met, we may not be able to generate the revenues we expect from such operations.

•	In the short term, we may experience a decline in our revenues attributable to our Products Segment as we currently do not have any new orders to replace large existing contracts. 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. While a decline in the revenues attributable to our Products Segment may have an adverse impact on our results of operations for the relevant periods, we do not expect that any such decline would have a material adverse effect on our liquidity and capital resources for the relevant periods over the short-term. Over the long-term, we intend to continue to pursue growth in our recovered energy business, which may help to offset any potential adverse impact on our results of operations for the relevant periods.

•	We expect to continue to generate the majority of our revenues from 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.

•	We expect that our financing expenses during the current fiscal year will increase, as compared to our financing expenses for the fiscal year ended December 31, 2003, as we financed the majority of our recent acquisitions with long-term non- and limited-recourse financing.

•

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.

•

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 and strengthening of unions 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 do not expect the current low interest rate environment to continue in the foreseeable future. Any increases in interest rates that impact our existing financings or future financings could increase the aggregate amount of our interest expenses and thus could have an adverse effect on our results of operations.

•	We have experienced recent increases in the cost of raw materials required for our equipment manufacturing activities, which we believe have resulted primarily from increased demand in the Chinese market for such raw materials and increases in the cost of transportation of our products. An increase in such costs may have an adverse effect on our financial condition and results of operations.

Revenues

We generate our revenues primarily from the sale of electricity from our geothermal power plants, the design, manufacturing and sale of equipment for electricity generation and the construction, installation and engineering of power plant equipment.

Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants pursuant to long-term power purchase agreements, however, such revenues are subject to seasonal variations, as more fully described below in the section entitled "Seasonality". 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). As required by Emerging Issues Task Force No. 01-8, Determining Whether an Arrangement Contains a Lease, we assessed all of our power purchase agreements acquired since July 1, 2003, and concluded that all such agreements related to our Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects contained a lease element requiring lease accounting. Accordingly, revenues related to the lease element of the agreements are presented as "lease" revenue, with the remaining revenue related to the production and delivery of the energy presented as "energy and capacity" revenue in our 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 unpredictable because larger customer orders for our products are typically a result of our participating in, and 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 such 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 periods indicated:

				Revenues																				% of revenues for period indicated
				(in thousands)
				Year ended December 31,												Six months ended June 30,								Year ended December 31,												Six months ended June 30,
				2001				2002				2003				2003				2004				2001				2002				2003				2003				2004
��																(unaudited)																				(unaudited)
Revenues
Electricity Segment				$	33,956			$	65,491			$	77,752			$	35,651			$	70,215				70.9	%			76.5	%			65.1	%			69.0	%			70.4	%
Products Segment					13,959				20,138				41,688				16,022				29,491				29.1				23.5				34.9				31.0				29.6
Total				$	47,915			$	85,629			$	119,440			$	51,673			$	99,706				100	%			100	%			100	%			100	%			100	%

Geographical breakdown

11.7%, 48.0% and 56.4% of the revenues attributable to our Electricity Segment were generated in the United States in 2001, 2002, and 2003, respectively. For the six months ended June 30, 2004, 80.7% of our revenues attributable to our Electricity Segment were generated in the United States, as compared to 52.2% for the same period in 2003. During the past three fiscal years, the percentage of our total revenues attributable to the sale of electricity in the United States has increased significantly, as compared to the percentage of our total revenues that is attributable to the sale of electricity by our foreign projects that has declined commensurately. Such increase is largely attributable to our recent acquisition of various projects in the United States. The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment for the periods indicated:

				Year ended December 31,												Six Months ended June 30,
				2001				2002				2003				2003				2004
United States					11.7	%			48.0	%			56.4	%			52.2	%			80.7	%
Foreign					88.3	%			52.0	%			43.6	%			47.8	%			19.3	%

Historically, revenues attributable to our Products Segment, after giving effect to the elimination of intercompany balances, have been derived primarily from outside of the United States, which is reflective of the historical demand in the United States described elsewhere in this prospectus. Since 2003, we have begun to generate revenues attributable to our Products Segment in the United States

as well. However, as a result of the volatility and unpredictability of the revenues attributable to our Products Segment and the impact that a few sales or EPC contracts can have on the geographic distribution of such revenues, the geographical distribution of such revenues may not be indicative of any developing trends or of our future results.

Seasonality

The demand for the electricity generated by our domestic projects and the prices paid for such electricity pursuant to our power purchase agreements are subject to seasonal variations. The demand for electricity from the Heber 1 project and Heber 2 project, 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 Company, 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 variation in Nevada. Similarly, 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 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 the power purchaser in California in the summer months as a result of the increase in demand and in prices has 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.

Expenses

Electricity Segment

The principal expenses attributable to our operating projects include operation and maintenance expenses such as salaries, equipment expenses, cost 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 and third- party services, 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.

Our partner in the Mammoth project reimburses us for 50% of the actual costs associated with the operation and maintenance of the project, plus certain general and administrative expenses.

Lease expenses are included as a component of operating expenses and principally consist of payments made to government agencies and private entities as compensation for the use of the relevant geothermal resources and site leases where plants are located.

Royalty payments are payments made as compensation for the right to use certain geothermal resources and are included as a component of operating expenses and are paid as a percentage of the revenues derived from the associated geothermal resources.

Products Segment

The principal expenses attributable to our Products Segment include materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses, sales commissions to sales representatives and royalties pertaining to government participation in our research and development programs at a rate of 3.5% of the proceeds recovered from the sale of products which were developed pursuant to such research and development programs.

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 and, in order to maintain our current production and construction capability, must be incurred, notwithstanding the revenues attributable to our Products Segment. As a result, the cost of revenues attributable to our Products Segment, expressed as a percentage of total revenues, is often very volatile. To date, our management has made the strategic decision to maintain our production and construction capacity and, therefore, maintain the fixed cost component of the total costs attributable to our Products Segment at the current level. Another reason for such volatility 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.

Critical Accounting Policies

Our critical accounting policies are more fully described in Note 1 to our audited consolidated financial statements. 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.    Revenues related to the sale of electricity from our geothermal power plants and capacity payments paid in connection with such sale are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant power purchase agreements. 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 power plant equipment, on behalf of third parties, is recognized on the percentage completion method, which is the relationship between costs 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. Selling, general and administrative costs are charged as and when incurred. 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 income and are recognized in the period in which the revisions are determined.

•

Impairment of Long-lived Assets and Long-lived Assets to Be Disposed of.    Long-lived assets 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 judgement 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 SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets. Pursuant to SFAS 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 capping 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 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 financial condition.

•

Derivative Instruments.    SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless such instruments are exempted from derivative treatment as a normal purchase and normal 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 is caused by interest rate volatility. Gain or loss on contracts that initially qualify for cash flow hedge accounting is included as a component of other comprehensive income and are subsequently reclassified into earnings when interest on the related debt is paid. Gain or loss on contracts that are not designated to qualify as a cash flow hedge is included as a component of interest expense.

We were required to adopt and have become subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15 (DIG Issue No. C15), Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also, pursuant to DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. We have power sales agreements that qualify as derivative instruments under DIG Issue No. C15 and do not meet the exception as they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. Our adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on our consolidated financial position and results of operations.

	In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 specified additional circumstances in which a

price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, or October 1, 2003 for us. DIG Issue No. C20 requires contracts that did not previously qualify for the normal purchases and normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortize such fair value over the remaining contract period. Upon our adoption of DIG Issue No. C20, we elected the normal purchase and normal sales scope exception under FAS No. 133 related to our power purchase agreements. Such adoption did not have a material impact on our consolidated financial position and results of operations.

•

Accounting for Income Taxes.    As part of the process of preparing our consolidated financial statements, 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 on our consolidated balance sheet. We must then assess the likelihood that our 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 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 carry-forwards for which a deferred tax valuation allowance has been established, we may be required to adjust our valuation allowance.

•

Stock-Based Compensation.    We account for stock-based compensation based on the provisions of Accounting Board Opinion No. 25, Accounting for Stock Issued to Employees, which we refer to as APB 25, which states that no compensation expense is required to be recorded for stock options or other stock-based awards to employees that are granted with an exercise price equal to or above the estimated fair value per share of common stock on the relevant grant date. In the event that stock options are granted at a price that is lower than the fair market value on the relevant date, the difference between the fair market value of the common stock and the exercise price of the stock options is recorded as unearned compensation. Unearned compensation is amortized to compensation expense over the vesting period applicable to the stock option. We have adopted the disclosure requirements of SFAS No. 123, Accounting for Stock-Based Compensation, as it relates to stock options granted to employees, which requires pro forma net income to be disclosed based on the fair value of the options granted at the date of the relevant grant.

•	New Accounting Pronouncements

Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Statements Board, which we refer to as FASB, issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB 51, which we refer to as FIN No. 46, 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 an 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., in which we have an 80% ownership

interest, should be deconsolidated. Ormat-Leyte Co. Ltd.'s operating results were accounted for using the consolidated method of accounting for the three-month period ended March 31, 2004 and, effective April 1, 2004, our ownership interest in Ormat-Leyte Co. Ltd. is accounted for using the equity method of accounting.

Derivative Instruments and Hedging Activities

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies the accounting and reporting treatment for derivative instruments, including certain derivatives embedded in other contracts, and hedging activities under SFAS No. 133. The amendments set forth in SFAS No. 149 require that contracts with comparable characteristics be accounted for as derivative instruments. SFAS No. 149 clarifies the circumstances under which a contract meets the characteristics of a derivative instrument according to SFAS No. 133 and clarifies when a derivative instrument contains a financing component that warrants special reporting in the statement of cash flows. The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging arrangements designated after June 30, 2003. We adopted the provisions of SFAS No. 149 effective July 1, 2003, which did not have a material impact on our consolidated results of operations and financial position as of December 31, 2003.

Accounting for Certain Financial Instruments with Characteristics of both Liability and Equity

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how a company classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that a company classify a financial instrument that is within its scope as a liability because that financial instrument embodies an obligation of the company. The requirements of SFAS No. 150 are effective for financial instruments entered into or modified after May 31, 2003, effective the first interim period beginning after June 15, 2003. For financial instruments created prior to the issuance date of SFAS No. 150, a transition is achieved by reporting the cumulative effect of a change in accounting principle. We adopted the provisions of SFAS No. 150 effective July 1, 2003, which did not have a material impact on our consolidated results of operations and financial position as of December 31, 2003.

Determining Whether an Arrangement Contains a Lease

In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EIFT Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. The adoption of EITF No. 01-8 effective July 1, 2003 did not have a material effect on our financial position or results of operations. Power purchase agreements acquired as part of the projects purchased since July 1, 2003 (Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects), contain lease elements within the scope of SFAS 13. Accordingly, for the six months ended June 30, 2004, revenues and costs associated with the lease element of the power purchase agreements that were acquired since July 1, 2003 have been presented as "lease" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in our financial statements. Lease revenue related to the Heber 1 and 2 projects from the date we acquired it (December 18, 2003) to December 31, 2003 was not material.

Obligations Associated with the Retirement of Long-Lived Assets.

For a discussion of SFAS No. 143, please see the discussion set forth above.

Results of Operations

Our historical operating results as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited value, as a result of the effects that (i) our recent acquisitions and enhancements of acquired projects, (ii) the sale of our investment in Karaganda Holding Company, which we refer to as KHC, in the third quarter of 2002, which owned and operated two coal fired power plants in Kazakhstan, and (iii) volatility in revenues of our Products Segment, in each case, have had on our historical operating results.

				Year ended December 31,												Six Months ended June 30,
				2001				2002				2003				2003				2004
								(in thousands)								(inthousands) (unaudited)
Statements of Operations Data:
Revenues:
Electricity Segment					70.9				76.5				65.1				69.0				70.4
Products Segment					29.1				23.5				34.9				31.0				29.6
					100.0	%			100.0	%			100.0	%			100.0	%			100.0	%
Cost of revenues:
Electricity Segment					36.9				51.1				60.1				62.2				57.8
Products Segment					125.0				85.9				70.7				64.3				78.4
					62.6				59.3				63.8				62.8				63.9
Gross margin:
Electricity Segment					63.1				48.9				39.9				37.8				42.2
Products Segment					(25.0	)			14.1				29.3				35.7				21.6
					37.4				40.7				36.2				37.2				36.1
Operating expenses:
Research and development					3.6				1.8				1.2				1.7				1.2
Selling and marketing					13.6				7.1				5.9				5.2				4.0
General and administrative					11.4				8.3				7.7				7.8				5.2
Operating income					8.8				23.5				21.4				22.5				25.7
Other income (expense):
Interest income					2.8				0.7				0.5				0.6				0.4
Interest expense					(9.1	)			(7.2	)			(6.8	)			(7.4	)			(19.5	)
Foreign currency translation and transaction gain (loss)					0.6				(0.4	)			(0.3	)			(0.3	)			(0.4	)
Miscellaneous income					0.6				1.5				0.4				0.5				0.1
Income (loss) from continuing operations before income taxes, minority interest and equity in income of investees					3.7				18.1				15.2				15.9				6.3
Income tax provision					(6.4	)			(7.2	)			(2.1	)			(4.2	)			(2.4	)
Minority interest in earnings of subsidiaries					(1.2	)			(1.4	)			(0.5	)			(0.8	)			(0.1	)
Equity of income of investees					0.3				0.4				0.5				0.4				2.5
Income (loss) from continuing operations					(3.6	)			9.9				13.1				11.3				6.3
Discontinued operations:
Loss from operations of discontinued activities in Kazakhstan					(9.8	)			(3.6	)			—				—				—
Loss of sale of Kazakhstan operations					—				(7.5	)			—				—				—
Income (loss) before cumulative effect of change in accounting principle					(13.4	)			(1.2	)			13.1				11.3				6.3
Cumulative effect of change in accounting principle net of tax benefit					—				—				(0.2	)			(0.4	)			—
Net income (loss)					(13.4	)			(1.2	)			12.9				10.9				6.3

Comparison of the Six Months Ended June 30, 2004 and the Six Months Ended June 30, 2003

Total Revenues

Total revenues for the six months ended June 30, 2004 were $99.7 million, as compared with $51.7 million for the six months ended June 30, 2003, which represented a 92.8% increase in total revenues. Such increase was attributable to additional revenues being generated from the Heber 1 project and the Heber 2 project that were acquired in December of 2003 and the Steamboat 2/3 project that was acquired on February 13, 2004. Such increase in revenues was also due to an additional $13.5 million received from the sale of products during such period.

Electricity Segment

				Six Months ended June 30,
				2003				2004
				(in millions)
Heber 1 and Heber 2 Project				$	—			$	27.4
Steamboat Project					—				6.9
Puna Project					—				1.8
Steamboat Hills Project					—				0.5
Other Projects					35.7				33.6
Total				$	35.7			$	70.2

Revenues attributable to our Electricity Segment for the six months ended June 30, 2004 were $70.2 million, as compared with $35.7 million for the six months ended June 30, 2003, which represented a 96.6% increase in such revenues. Such period included $27.4 million of revenues generated by the Heber 1 project and Heber 2 project, $6.9 million of revenues generated by the Steamboat 1/1A and Steamboat 2/3 projects, $1.8 million of revenues generated by the Puna project and $0.5 million of revenues generated by Steamboat Hills project, as compared to the same period in 2003, during which we did not record any revenues from such projects. Revenues from other projects decreased due to the deconsolidation of the Leyte project as of April 1, 2004.

Products Segment

Revenues attributable to our Products Segment for the six months ended June 30, 2004 were $29.5 million, as compared with $16.0 million for the six months ended June 30, 2003, which represented an 84.4% increase in such revenues. This increase resulted from added revenues of $13.5 million, principally attributable to two large projects (Mokai and Wairakei) during the six-month period ended June 30, 2004. Such increase reflects the volatility of the revenues generated from our Products Segment.

Total Cost of Revenues

Total cost of revenues for the six months ended June 30, 2004 was $63.7 million, as compared with $32.5 million for the six months ended June 30, 2003, which represented an 96.0% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the six months ended June 30, 2004 and the six months ended June 30, 2003 were 63.9% and 62.8%, respectively.

Electricity Segment

Total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2004 was $40.6 million, as compared with $22.2 million for the six months ended June 30, 2003, which represented a 82.9% increase in cost of revenues for such segment. The six months ended June 30, 2004 included $17.3 million, $3.7 million $1.1 million and $0.3 million, respectively, of cost of revenues attributable to the Heber 1 project and the Heber 2 project and the Steamboat 1/1A and Steamboat 2/3 projects, as compared to the six months ended June 30, 2003, during which such projects were not

included in our results of operations. As a percentage of total electricity revenues, total cost of revenues attributable to our Electricity Segment for the six months ended June 30, 2004 (57.8%) was slightly lower than the percentage for the six months ended June 30, 2003 (62.2%) because as a percentage of revenues, total cost of revenues for our newly acquired projects were slightly lower than the projects in our portfolio prior to such acquisitions.

Products Segment

Total cost of revenues attributable to our Products Segment for the six months ended June 30, 2004 was $23.1 million, as compared with $10.3 million for the six months ended June 30, 2003, which represented a 124.3% increase in cost of revenues related to such segment. Such $12.8 million increase in cost of revenues was attributable to an increase in revenues recognized during the relevant period in 2004 as a result of an increase in the volume of sales, as compared to the relevant period in 2003. As a percentage of total products revenues, our total cost of revenues attributable to our Products Segment for the six months ended June 30, 2004 was 78.4% and for the six months ended June 30, 2003 was 64.3%. The lower percentage of cost of revenues in 2003 resulted from the cancellation of a provision recorded in 2002 for the construction of a project following negotiations with a customer.

Research and Development Expenses

Research and development expenses for the six months ended June 30, 2004 were $1.2 million, as compared with $0.9 million for the six months ended June 30, 2003, which represented a 33.3% increase in research and development expenses. Such increase was in the ordinary course of our operations and does not represent any significant change in our research and development program or our ability to maintain and continue to develop our technologies and operations and reflects fluctuations in the period in which actual expenses were incurred.

Selling and Marketing Expenses

Selling and marketing expenses for the six months ended June 30, 2004 were $3.9 million, as compared with $2.7 million for the six months ended June 30, 2003, which represented a 44.4% increase in selling and marketing expenses. Selling and marketing expenses for the six months ended June 30, 2004 constituted 4.0% of total revenues for such period, as compared with 5.2% for the six months ended June 30, 2003. Such 1.2% decrease is attributable to the fixed cost nature of certain of our selling and marketing expenses as compared to a larger revenue base. The larger revenue base was principally attributable to an increase in the revenues generated by our Electricity Segment. Once a project is in operation and generates electricity, selling and marketing expenses attributable to such project are relatively insignificant.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2004 were $5.2 million, as compared with $4.1 million for the six months ended June 30, 2003, which represented a 26.8% increase in general and administrative expenses. Such increase was principally attributable to an increase in professional services fees related to our business development activities in the United States. General and administrative expenses for the six months ended June 30, 2004 constituted 5.2% of total revenues for such period, as compared with 7.8% for the six months ended June 30, 2003. Such 2.6% decrease is attributable to the fixed cost nature of certain of our general and administrative expenses as compared to a larger revenue base.

Interest Expense

Interest expense for the six months ended June 30, 2004 was $19.5 million, as compared with $3.8 million for the six months ended June 30, 2003, which represented a 413.2% increase in such interest expense. Approximately $5.9 million of such increase was attributable to the interest expenses incurred by certain of our subsidiaries in connection with the Beal Bank financing and approximately

$6.3 million of such increase was attributable to the interest expenses incurred in connection with the issuance by Ormat Funding, on February 13, 2004, of $190.0 million of senior secured notes. The remaining $3.5 million increase was attributable to an increase in parent company loans.

Income Taxes

Income taxes for the six months ended June 30, 2004 were $2.0 million, as compared with $2.2 million for the six months ended June 30, 2003, which represented a 9.1% decrease in such income taxes. The effective tax rate for six months ended June 30, 2004 and June 30, 2003 was 31.0% and 26.5%, respectively. The lower effective rate for the six months ended June 30, 2003 was primarily due to the tax holiday in the Philippines that was applicable in 2003, but not in 2004.

Equity in Income of Investees

Our participation in the income generated from our investees for the six months ended June 30, 2004 was $2.0 million (net of tax expense in the amount of $0.5 million), as compared with $0.2 million for the six months ended June 30, 2003, which represented a 900.0% increase. Such increase was principally attributable to the income generated in connection with our 50.0% equity interest in the Mammoth project, which was acquired in December, 2003 and which accounted for $0.7 million of such income for the six months ended June 30, 2004, and from income generated in connection with our 80% equity interest in the Ormat Leyte project which was deconsolidated as of April 1, 2004 (as a result of the application of FIN No. 46) and which accounted for $1.0 million.

Net Income

Net income for the six months ended June 30, 2004 was $6.3 million, as compared with $5.6 million for the six months ended June 30, 2003, which represented an increase of 12.5% in our net income. Net income as a percentage of our total revenues for the six months ended June 30, 2004 was 6.3%, as compared with 10.9% for the six months ended June 30, 2003. Such decrease in percentage was principally attributable to an increase in our financing expenses relating to the financing of the acquisition of the Heber 1 project, Heber 2 project and Steamboat 2/3 project.

Comparison of the Year Ended December 31, 2003 and the Year Ended December 31, 2002

Total Revenues

Total revenues for the year ended December 31, 2003 were $119.4 million, as compared with $85.6 million for the year ended December 31, 2002, which represented a 39.5% increase in our total revenues. Such increase was principally attributable to the receipt of additional revenues generated by the Ormesa project that was acquired on April 15, 2002 and the increase in revenues generated from the sale and installation of equipment to power plants worldwide.

Electricity Segment

				Year ended December 31,
				2002				2003
				(in millions)
Ormesa Project				$	21.8			$	30.5
Heber 1 and Heber 2 Projects					—				2.0
Steamboat 1/1A Project					—				1.0
Leyte Project					15.6				12.6
Momotombo Project					9.2				11.6
Other Projects					18.9				20.1
Total				$	65.5			$	77.8

Revenues from the sale of electricity for the year ended December 31, 2003 were $77.8 million, as compared with $65.5 million for the year ended December 31, 2002, which represented a 18.8%

increase in such revenues. Such increase was a result of: (i) the acquisition of the Ormesa project in April of 2002, which for the full fiscal year ended December 31, 2003 generated $30.5 million of revenues, as compared to $21.8 million for the eight months of operation in 2002 following its acquisition; (ii) $2.0 million of revenues generated by the Heber 1 project and the Heber 2 project for the 13-day period ended December 31, 2003, as compared with no revenues attributable to such projects in 2002; and (iii) $1.0 million of revenues generated by the Steamboat 1/1A project as compared with no revenues attributable to such project in 2002. The increase in our revenues for the fiscal year ended December 31, 2003, as compared to the fiscal year ended December 31, 2002, would have been higher but for the one-time addition to the revenues received in 2002 in the amount of $2.7 million, as a result of a disputed performance bonus that was resolved and recognized in 2002.

Products Segment

Revenues from our Products Segment for the year ended December 31, 2003 were $41.7 million, as compared with $20.1 million for the year ended December 31, 2002, which represented a 107.5% increase in such revenues. Such increase resulted primarily from $14.0 million of revenues primarily attributable to two large projects (Mokai and Miravalles) and the sale of products, services and parts for the year ended December 31, 2003. Such increase reflects the volatility of the revenues generated from our Products Segment.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2003 was $76.2 million, as compared with $50.8 million for the year ended December 31, 2002, which represented a 50.0% increase. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2003 was 63.8%, as compared to 59.3% for the year ended December 31, 2002. This increase is explained below.

Electricity Segment

Cost of revenues attributable to our Electricity Segment for the year ended December 31, 2003 was $46.7 million, as compared with $33.5 million for the year ended December 31, 2002, which represented a 39.4% increase for such cost of revenues. Such increase was principally attributable to the acquisition of the Ormesa project, as cost of revenues for the year ended December 31, 2003 included expenses of the Ormesa project in the amount of $23.3 million, as compared to $15.7 million for the year ended December 31, 2002. The Ormesa project had higher operating expenses than the other projects we operated at such time due to additional transmission costs relating to the transmission of electricity over the Imperial Irrigation District transmission system and the type of equipment used in the Ormesa project, which is more costly to operate and maintain than the equipment used in our other projects that existed at the time of such acquisition. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment was 60.1% for the year ended December 31, 2003 as compared to 51.1% for the year ended December 31, 2002. Such increase, on a percentage basis, was partially attributable to $2.7 million of revenues received as a result of a one-time disputed performance bonus that was resolved and recognized in 2002.

Products Segment

Cost of revenues attributable to our Products Segment for the year ended December 31, 2003 was $29.5 million, as compared with $17.3 million for the year ended December 31, 2002, which represented a 70.5% increase in such cost of revenues. Such $12.2 million increase in cost of revenues was attributable to the generation of additional revenues from the sale of our equipment during the year ended December 31, 2003. As a percentage of our total Products Segment revenues, our cost of revenues attributable to our Products Segment for the year ended December 31, 2003 was 70.7% as compared to 85.9% for the year ended December 31, 2002. Such 15.2% decrease was primarily attributable to a 107.5% increase in our Products Segment revenues as compared to the fixed nature of much of our cost of revenues, such as salaries, depreciation, expenses related to maintaining operations, utilities and property expenses.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2003 were $1.4 million, as compared with $1.5 million for the year ended December 31, 2002, which represented a 6.7% decrease in such research and development expenses. Such decrease reflects a fluctuation in the ordinary course of our business and does not represent a significant change in our research and development program or our ability to maintain and continue to develop our technologies and operations.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2003 were $7.1 million, as compared with $6.1 million for the year ended December 31, 2002, which represented a 16.4% increase in such selling and marketing expenses. Selling and marketing expenses for the year ended December 31, 2003 represented 5.9% of our total revenues, as compared to 7.1% for the year ended December 31, 2002. Such 1.2% decrease is a result of the effect of the fixed cost component of our selling and marketing expenses over a larger revenue base. The larger revenue base was principally attributable to an increase in the revenues generated by our Electricity Segment. Once a project is in operation and generates electricity, selling and marketing expenses are relatively insignificant.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2003 were $9.3 million, as compared with $7.1 million for the year ended December 31, 2002, which represented a 31.0% increase in general and administrative expenses. Such increase was attributable to costs related to an increase in our personnel, wages and professional services and other costs related to our business development activities in the United States which were primarily related to the pursuit and consummation of the acquisition of the Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project. As a percentage of our total revenues, general and administrative expenses were 7.7% of such revenues for the year ended December 31, 2003 and 8.3% of such revenues for the year ended December 31, 2002.

Interest Expense

Interest expense for the year ended December 31, 2003 was $8.1 million, as compared with $6.2 million for the year ended December 31, 2002, which represented an increase of 30.6% in our total interest expense. Such increase resulted from $1.9 million of interest expense incurred in connection with the United Capital project finance loan incurred on December 31, 2002 by our project subsidiary to refinance the Ormesa acquisition, $0.8 million of interest expense incurred in connection with outstanding parent company loans, and $0.4 million of interest expense incurred in connection with the Beal Bank loan incurred on December 18, 2003, in order to finance the acquisition of the Heber 1 project, the Heber 2 project and the Mammoth project. Interest expenses related to certain other bank loans decreased by $1.2 million for the fiscal year ended December 31, 2003 due to a decrease in outstanding corresponding balances.

Income Taxes

Income taxes for the year ended December 31, 2003 were $2.5 million, as compared with $6.1 million for the year ended December 31, 2002, which represented a decrease of 59.0% in such income taxes. The effective tax rate for the years ended December 31, 2003 and 2002 was 13.8% and 39.5%, respectively. For the year ended December 31, 2003, our effective tax rate was reduced by approximately 8.4% as a result of the application of investment tax credits. In addition, our foreign tax rates were substantially lower than our U.S. tax rates due primarily to the tax holiday in the Philippines that applied to us and the reversal of a deferred tax valuation allowance related to the realization of net operating losses in Ormat Systems which decreased our effective tax rate by approximately 5.6%. For the year ended December 31, 2002, our effective tax rate was reduced by approximately 2.5% as a result of the application of investment tax credits and increased by approximately 8.0% related to a deferred tax valuation allowance applied to the net operating losses in Ormat Systems.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2003 was $0.6 million, as compared with $0.3 million for the year ended December 31, 2002, which represented an increase of 100%. Such increase was principally attributable to an increase in our income derived from our 21.0% ownership of the Zunil project, which had lower debt service and therefore higher net income.

Discontinued Operations

Losses from operations of discontinued activities in Kazakhstan and losses from the sale of our Kazakhstan operations were $3.1 million and $6.4 million, respectively for the year ended December 31, 2002. The sale of our Kazakhstan operations (consisting of coal fired power plants and related assets), occurred on September 16, 2002. Such losses were recorded and reflected in our financial statements for the fiscal year ended December 31, 2002.

Net Income

Our income from continuing operations was $15.7 million in the fiscal year ended December 31, 2003, as compared to $8.5 million in fiscal year ended December 31, 2002, representing 13.1% of revenues in 2003 as compared to 9.9% of revenues in 2002. Such increase was attributable to increased revenues in both segments. Net income in 2002 was equal to a loss of $1.0 million as a result of the loss from discontinued operations in Kazakhstan and the loss from the sale of our Kazakhstan assets. Net income in 2003 was $15.5 million.

Comparison of the Year Ended December 31, 2002 and the Year Ended December 31, 2001

Total Revenues

Total revenues for the year ended December 31, 2002 were $85.6 million, as compared with $47.9 million for the year ended December 31, 2001, which represented a 78.7% increase in such total revenues. Such increase in total revenues was principally attributable to the revenues generated by the acquired Ormesa project and Brady project and is also due to an increase in the revenues generated by our Products Segment.

Electricity Segment

				Year ended December 31,
				2001				2002
				(in millions)
Brady Project				$	4.0			$	9.6
Ormesa Project					—				21.8
Leyte Project					12.5				15.6
Other Projects					17.5				18.5
Total				$	34.0			$	65.5

Revenues attributable to our Electricity Segment for the year ended December 31, 2002 were $65.5 million, as compared with $34.0 million for the year ended December 31, 2001, which represented a 92.6% increase in such revenues. Such increase in revenues was principally attributable to the acquisition of the Ormesa project, as total revenues for the year ended December 31, 2002 included $21.8 million of revenues generated from the Ormesa project, as compared with the year ended December 31, 2001, during which no revenues from the Ormesa project were recorded. Additionally, the acquisition of the Brady project on June 29, 2001 also contributed additional revenues, as total revenues for the year ended December 31, 2002 included Brady project revenues in the amount of $9.6 million, while the period from June 29, 2001 to December 31, 2001 only included $4.0 million of Brady project revenues. Lastly, our increased revenues were partially attributable to $2.7 million of revenues received as a result of a one-time disputed performance bonus that was resolved and recognized in 2002.

Products Segment

Revenues from our Products Segment for the year ended December 31, 2002 were $20.1 million, as compared with $14.0 million for the year ended December 31, 2001, which represented a 43.6% increase in such revenues. Such increase resulted from revenues of $7.0 million attributable to the Miravalles power plant during the year ended December 31, 2002, as compared with no revenues from any large project during 2001. Such difference reflects the volatility of the revenues generated from our Products Segment.

Total Cost of Revenues

Total cost of revenues for the year ended December 31, 2002 was $50.8 million, as compared with $30.0 million for the year ended December 31, 2001, which represented a 69.3% increase in total cost of revenues. As a percentage of our total revenues, our total cost of revenues for the year ended December 31, 2002 was 59.3%, as compared with 62.6% for the year ended December 31, 2001.

Electricity Segment

Cost of revenues attributable to our Electricity Segment for the year ended December 31, 2002 was $33.5 million, as compared with cost of revenues of $12.5 million for the year ended December 31, 2001, which represented a 168.0% increase in such cost of revenues. Such increase was principally attributable to the acquisition of the Ormesa project, as cost of revenues for the year ended December 31, 2002 included expenses of the Ormesa project equal to $15.7 million, as compared to operating expenses relating to the Ormesa project during the year ended December 31, 2001. In addition to the acquisition of the Ormesa project, as a result of the acquisition of Brady project, operating expenses for the year ended December 31, 2002 included expenses for the Brady project equal to $5.3 million, as compared to the fiscal year ended December 31, 2001, which included $2.6 million of such expenses. As a percentage of our total Electricity Segment revenues, our cost of revenues attributable to our Electricity Segment was 51.1% for the fiscal year ended December 31, 2002, as compared with 36.9% for the fiscal year ended December 31, 2001. Such increase was primarily attributable to the cost of revenues for the Ormesa project which were substantially higher than the cost of revenues of our other existing projects at the time of such acquisition which are due to additional transmission costs relating to the transmission of electricity over the Imperial Irrigation District transmission system and the type of equipment used in the Ormesa project, which is more costly to operate and maintain than the equipment used in our other projects that existed at the time of such acquisition.

Products Segment

Cost of revenues attributable to our Products Segment for the year ended December 31, 2002 was $17.3 million, as compared with $17.5 million for the year ended December 31, 2001, which represented a 1.1% decrease in such cost of revenues. As a percentage of our total Products Segment revenues, our cost of revenues attributable to our Products Segment for the fiscal year ended December 31, 2002 was 85.9%, as compared with 125.0% for the fiscal year ended December 31, 2001. Such reduction was primarily attributable to a higher volume of product sales which was sufficient to decrease the related fixed costs, such as salaries, depreciation, expenses related to maintaining operations, utilities and property expenses, whereas in 2001, cost of revenues attributable to our Products Segment exceeded revenues generated from our Products Segment.

Research and Development Expenses

Research and development expenses for the year ended December 31, 2002 were $1.5 million, as compared with $1.7 million for the year ended December 31, 2001, which represented a 11.8% decrease in research and development expenses. Such decrease was in ordinary course of our operations and does not represent a significant change in our research and development program or our ability to maintain and continue to develop our technologies and operations.

Selling and Marketing Expenses

Selling and marketing expenses for the year ended December 31, 2002 were $6.1 million, as compared with $6.5 million for the year ended December 31, 2001, which represented a 6.2% decrease in such selling and marketing expenses. Selling and marketing expenses for the year ended December 31, 2002 represented 7.1% of our total revenues, as compared with 13.6% for the year ended December 31, 2001. Such 6.5% decrease is attributable to the fixed cost nature of certain of our selling and marketing expenses as compared to a larger revenue base. The larger revenue base was principally attributable to an increase in the revenues generated by our Electricity Segment. Once a project is in operation and generates electricity, selling and marketing expenses attributable to such project are relatively insignificant.

General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2002 were $7.1 million, as compared with $5.4 million for the year ended December 31, 2001, which represented a 31.5% increase in general and administrative expenses. Such increase was principally attributable to an increase in our business development activities in the United States, an increase in personnel and the retainer of professional consultants in connection with the acquisition of the Ormesa project. General and administrative expenses for the year ended December 31, 2002 constituted 8.3% of our total revenues, as compared to 11.3% for the year ended December 31, 2001.

Interest Expense

Interest expense for the year ended December 31, 2002 was $6.2 million, as compared with $4.3 million for the year ended December 31, 2001, which represented a 44.2% increase in our total interest expense. Such increase was primarily attributable to an increase in interest expense and related guarantee fees of $1.9 million relating to short term bank loans.

Income Taxes

Income taxes for the year ended December 31, 2002 were $6.1 million, as compared with $3.1 million for the year ended December 31, 2001, which represented an increase of 96.8% in such income taxes. The effective tax rate for the years ended December 31, 2002 and 2001 was 39.5% and 169.2%. For the year ended December 31, 2002, our effective tax rate was reduced by approximately 2.5% as a result of the application of investment tax credits and increased by approximately 8.0% related to a deferred tax valuation allowance applied to the net operating losses of Ormat Systems. For the year ended December 31, 2001, our effective tax rate was increased by a deferred tax valuation allowance applied to the net operating losses in Ormat Systems.

Equity in Income of Investees

Our participation in the income generated from our investees for the year ended December 31, 2002 was $0.3 million, as compared with $0.2 million for the year ended December 31, 2001, which represented an increase of 50.0%. Such increase was principally attributable to an increase in our income derived from our 21.0% ownership interest of the Zunil project, which had lower debt service and therefore higher net income.

Discontinued Operations

Losses from operations of discontinued activities in Kazakhstan and losses from the sale of our operations in Kazakhstan were $3.1 million and $6.4 million, respectively, for the year ended December 31, 2002. Losses from operations of discontinued activities in Kazakhstan for the year ended December 31, 2001 were $4.7 million.

Net Income (Loss)

Our income from continuing operations was $8.5 million in the fiscal year ended December 31, 2002, as compared to a loss of $1.7 million for the fiscal year ended December 31, 2001. Such increase

was attributable to increased revenues generated by both segments. Loss from discontinued operations amounted to $3.1 million compared with $4.7 million in 2001. In 2002, we also recorded a loss on the sale of our Kazakhstan assets of $6.4 million. The net income was a loss of $1 million in 2002, compared to a loss of $6.4 million in 2001.

Quarterly Results of Operations

The table below sets forth unaudited consolidated statement of operations data for each of the six consecutive quarters ended June 30, 2004. The unaudited consolidated financial statements have been prepared on the same basis as our audited consolidated financial statements included elsewhere in this prospectus and include all adjustments, consisting only of normal recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of such financial information. The operating results for any quarter described below are not necessarily indicative of our future results of operations for any fiscal quarter or year.

				Three Months ended
				March 31, 2003				June 30, 2003				Sept. 30, 2003				Dec. 31, 2003				March 31, 2004				June 30, 2004
				(unaudited) (inthousands,exceptsharedata)
Revenues:
Electricity Segment				$	17,604			$	18,047			$	21,494			$	20,607			$	33,459			$	36,756
Products Segment					7,812				8,210				10,907				14,759				14,146				15,345
					25,416				26,257				32,401				35,366				47,605				52,101
Cost of revenues:
Electricity Segment					10,148				12,017				10,837				13,724				19,390				21,222
Products Segment					6,317				3,989				8,973				10,215				11,328				11,794
					16,465				16,006				19,810				23,939				30,718				33,016
Gross margin					8,951				10,251				12,591				11,427				16,887				19,085
								��
Operating expenses:
Research and development					439				432				325				195				302				900
Selling and marketing					1,367				1,299				2,342				2,079				1,854				2,092
General and administrative					2,057				1,996				1,632				3,567				2,332				2,887
Operating income					5,088				6,524				8,292				5,586				12,399				13,206
Other income (expense):
Interest income					109				190				217				91				244				187
Interest expense					(1,720	)			(2,115	)			(2,277	)			(2,008	)			(8,523	)			(10,952	)
Foreign currency translation and transaction loss					(114	)			(37	)			(66	)			(99	)			(321	)			(76	)
Other non-operating income					133				145				48				138				(24	)			169
Income from continuing operations before income taxes, minority interest and equity in income of investees					3,496				4,707				6,214				3,708				3,775				2,534
Income tax provision					(1,397	)			(776	)			(2,134	)			1,801				(1,479	)			(478	)
Minority interest in earnings of subsidiaries					(201	)			(198	)			(161	)			41				(108	)			—
Equity in income of investees					89				99				106				265				549				1,486
Income before cumulative effect of change in accounting principle					1,987				3,832				4,025				5,815				2,737				3,542
Cumulative effect of change in accounting principle (net of tax benefit of $124,740)					(205	)			—				—				—				—				—
Net income				$	1,782			$	3,832			$	4,025			$	5,815			$	2,737			$	3.542
Net income per share—basic and diluted				$	0.08			$	0.17			$	0.17			$	0.25			$	0.12			$	0.15
Weighted average number of shares				23,214,281				23,214,281				23,214,281				23,214,281				23,214,281				23,239,791

Liquidity and Capital Resources

Since our inception, we have funded our operations through a combination of internally generated cash and parent company loans, supplemented with third party debt.

For a discussion regarding our parent company loans, see "Certain Relationships and Related Transactions." Our third-party debt is composed of two principal categories. The first consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing our projects or for the acquisition of our projects. The second consists of debt incurred by us or our subsidiaries for general corporate purposes. Orcal Geothermal, one of our subsidiaries, has incurred a non-recourse project finance loan from Beal Bank, for the purpose of financing, in part, the acquisition of the Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project, of which $153.7 million was outstanding as of June 30, 2004, bearing an interest rate of the greater of 7.125% or LIBOR plus 5.125% per annum. On February 13, 2004, Ormat Funding, one of our subsidiaries, issued 8¼% senior secured notes in a capital markets offering subject to Rule 144A and Regulation S of the Securities Act, for the purpose of the refinancing of 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, of which $189.8 million was outstanding as of June 30, 2004. The Bank Hapoalim project finance debt, of which $18.5 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 2.375% per annum on tranche one of the loan and 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 $16.5 million was outstanding as of June 30, 2004, bearing an interest rate of 6.54% per annum, were each incurred by our relevant subsidiaries to finance the Momotombo project and Leyte project, respectively. All of the agreements described in this section are described in more detail under "Description of Certain Material Agreements — Financing Agreements."

The second category of our third party debt includes the following loans: (i) a $20.0 million credit facility from United Mizrahi Bank, of which $20.0 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 1.2% per annum, (ii) a $20 million credit facility from Bank Leumi, of which $20.0 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 1.5% per annum, (iii) a medium term loans from Bank Continental, of which $6.8 million was outstanding as of June 30, 2004, and which we are obligated to repay no later than January 14, 2005 or otherwise refinance with Bank Continental or one of its affiliates, bearing an interest rate of LIBOR plus 1% per annum; (iv) a medium term loan from Bank Hapoalim, of which $4.0 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 1.7% per annum; (v) a medium term loan from Discount Bank, of which $4.6 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 1.7% per annum and (vi) a medium term loan from Israel's Industrial Development Bank, of which $5.0 million was outstanding as of June 30, 2004, bearing an interest rate of LIBOR plus 1.8% per annum. Our payment obligation under such credit facilities are all currently guaranteed by our parent.

From time to time, Bank Leumi has issued, as security for certain of our obligations, performance letters of credit in favor of our customers. Our parent is the counterparty with respect to such letters of credit. Pursuant to certain existing agreements described elsewhere in this prospectus, we are required to pay to our parent a guarantee fee with respect to such letters of credit (and other guarantees) and are responsible to reimburse our parent for any draw or payment made under these letters of credit or guarantees. As of June 30, 2004, the outstanding aggregate amount available to be drawn under these letters of credit was $10.5 million.

In connection with the acquisition transaction between Ormat Systems and our parent, we have entered into certain agreements with each of Bank Hapoalim, Bank Leumi, United Mizrahi Bank and Israel's Industry Development Bank. Under these agreements, in exchange for such banks' release of our parent's guarantee and a release of their security interest over the assets our subsidiary, Ormat Systems, acquired from our parent, we and Ormat Systems agreed to certain negative covenants, including, but not limited to, a prohibition on (1) creating any floating charge or any permanent pledge, charge or lien over its assets without obtaining the prior written approval of the lender,

(2) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender and (3) selling, assigning, transferring, conveying or disposing of all or substantially all of its assets and, in some cases, compliance with 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 will 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, will result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement. In addition, as part of the consideration for the acquisition transaction between Ormat Systems and our parent, we will assume approximately $5.4 million of our parent's outstanding loan with Continental Bank.

We have also entered into an agreement with Bank Hapoalim pursuant to which we have assumed our parent's existing obligations to Bank Hapoalim with respect to approximately $17.2 million of outstanding letters of credit.

Our subsidiary, Ormat Nevada, has also entered into a letter of credit agreement with Hudson United Bank, which is described in further detail under "—Off-Balance Sheet Arrangements" below.

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.

We currently intend to refinance the acquisition cost of the Puna project by the end of the year. In connection with such potential refinancing, we are currently in discussions with an international financial institution regarding the refinancing of the acquisition cost of the Puna project, which will involve our relevant project subsidiary's entering into a leveraged lease financing transaction. However, we have not ruled out alternative options such as the issuance by Ormat Funding of an additional tranche of its senior secured notes or the incurrence by our relevant project subsidiary of project finance debt or other form of third party financing. In anticipation of such financing, we have entered into a rate lock agreement with Lehman Brothers Special Financing, Inc., an affiliate of one of the underwriters of this offering, to provide interest rate protection for such financing. Such forward rate agreement and its implications are further described under "—Exposure to Market Risks" below.

In 2003, one of our lenders granted a waiver with respect to the failure of our parent company for its fiscal year 2001 and 2002 to meet certain financial ratios contained in its guarantee relating to our loan agreement with such lender. We provided no consideration for such waiver. As of June 30, 2004, the balance outstanding pursuant to such loan agreement was $4.0 million.

Other than the non-compliance noted above, our management believes that we are currently in compliance with our covenants with respect to our third-party debt.

In accordance with our dividend policy, conditional upon, and effective as of, the effectiveness of the registration statement of which this prospectus forms a part, we will pay an interim dividend for 2004 of $2.5 million to our parent company, Ormat Industries.

We estimate that the net proceeds we will receive from this offering will be approximately $89.9 million, or approximately $103.8 million if the underwriters exercise their over-allotment option in full, in each case, after deducting the underwriting discounts and commissions and estimated expenses of this offering payable by us.

We expect to use all of the net proceeds of this offering for general corporate purposes, which may include making other investments or acquisitions. However, we have no present understanding or agreement relating to any specific acquisition. Accordingly, management will have significant flexibility in applying the net proceeds of this offering. Pending the use of such proceeds, we intend to invest such proceeds in interest-bearing investment-grade instruments and bank deposits. Our management believes that the sources of liquidity described above, including, but not limited to, internally generated cash, existing parent company loans and third party debt, together with the proceeds of this

offering, will be sufficient to address our liquidity and other investment requirements for the next 24 months, however, we are not dependent on the proceeds of this offering to fund our continuing operations. In the long term, if we undertake additional acquisition or significant expansion, or incur other unexpected capital needs, we expect to have access to public capital markets not available to us before the offering.

Historical Cash Flows

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

				Year ended December 31,												Six months ended June 30,
				2001				2002				2003				2003				2004
				(in thousands)												(unaudited)
Net cash provided by operating activities				$	10,998			$	11,634			$	46,019			$	16,785			$	22,660
Net cash used in investing activities					(62,436	)			(60,521	)			(285,180	)			(16,059	)			(233,129	)
Net cash provided by (used in) financing activities					54,862				72,420				211,350				(19,692	)			222,766
Effect of foreign currency translation adjustments					(293	)			(51	)			—				—				—
Net increase (decrease) in cash and cash equivalents				$	3,131			$	23,482			$	(27,811	)		$	(18,966	)		$	12,297

For the Six Months Ended June 30, 2004

Net cash provided by operating activities for the six months ended June 30, 2004 was $22.7 million, as compared with $16.8 million for the six months ended June 30, 2003. Such increase was principally attributable to the addition of cash flows from the operating activities of the Heber 1 project, Heber 2 project and Steamboat 2/3 project, whose revenues during the six months ended June 30, 2004 amounted to $10.5 million, $16.9 million and $6.9 million, respectively.

Net cash used in investing activities for the six months ended June 30, 2004 was $233.1 million, as compared with $16.1 million for the six months ended June 30, 2003. The principal factors that affected the increase in the use of our cash flow for investing activities during such period were the aggregate amount of cash paid for acquisitions, net of cash received, which, for the six months ended June 30, 2004, as a result of the acquisitions of the Steamboat 2/3 project, the Puna project and the Steamboat Hills project, were equal to $82.8 million, $71.2 million and $20.3 million respectively, in addition to the increase in our restricted cash and cash equivalents during such period, which was equal to $50.7 million resulting primarily from the issuance by Ormat Funding of its 8¼% senior secured notes in the amount of $190.0 million. A portion of the proceeds from the issuance of the such senior secured notes was escrowed and reserved for additional investments for the Galena project and for the purpose of repayment of the loan extended by United Capital to fund the acquisition of the Ormesa project.

Net cash provided by financing activities for the six months ended June 30, 2004 was $222.8 million, as compared with $19.7 million used in financing activities for the six months ended June 30, 2003. The principal factors that affected the cash flow provided by financing activities during the six months ended June 30, 2004 were the proceeds from the issuance of the senior secured notes in order to finance the acquisition of the Steamboat 2/3 project and to refinance the acquisition of the Ormesa, Brady, Mammoth and Steamboat 1/A projects, the proceeds from United Mizrahi Bank loan and net proceeds from parent company loans in the amount of $36.8 million.

For the Year Ended December 31, 2003

Net cash provided by operating activities for the year ended December 31, 2003 was $46.0 million, as compared with $11.6 million for the year ended December 31, 2002. Such change was principally attributable to an increase in revenues, in an amount equal to $8.7 million, as a result of the acquisition of the Ormesa project and an increase in revenues, in an amount equal to $21.5 million, generated from our Products Segment.

Net cash used in investing activities for the year ended December 31, 2003 was $285.2 million, as compared with $60.5 million for the year ended December 31, 2002. The principal factors that affected the increase in the use of our cash flow for investing activities during such period included:

•	Cash paid for acquisitions (net of cash received) in the amount of $256.6 million, relating to the acquisition of the Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project; and

•	Capital expenditures spent in connection with the Ormesa project in an amount equal to $17.0 million for the installation of new power units and the modification of the geothermal fluid gathering and electrical systems, in order to increase the capacity, reliability and availability of the Ormesa project.

Net cash provided by financing activities for the year ended December 31, 2003 was $211.4 million, as compared with $72.4 million for the year ended December 31, 2002. The principal factors that impacted our cash flow provided by financing activities during the year ended December 31, 2003 were the incurrence of a loan by Orcal in an amount of $154.5 million from Beal Bank in December 2003, and the receipt of $126.3 million of proceeds from parent company loans, less a repayment of $55.0 million of short-term debt.

For the Year Ended December 31, 2002

Net cash provided by operating activities for the year ended December 31, 2002 was $11.6 million, as compared with $11.0 million for the year ended December 31, 2001. Such increase was principally attributable to the acquisition of the Ormesa project.

Net cash used in investing activities for the year ended December 31, 2002 was equal to $60.5 million, as compared to $62.4 million for the year ended December 31, 2001. The principal factors that impacted the use of our cash flow from investing activities during such period included:

•	Cash paid for acquisitions (net of cash received) in the amount of $39.7 million, relating to the acquisition of the Ormesa project in 2002, as compared to the cash paid for acquisitions (net of cash received) in the amount of $30.5 million, relating to the acquisition of the Brady project in 2001; and

•	Capital expenditures incurred in connection with the Brady project and the Momotombo project in the amount of $19.7 million and the Ormesa project in the amount of $1.7 million.

Net cash provided by financing activities for the year ended December 31, 2002 was $72.4 million, as compared with $54.9 million for the year ended December 31, 2001. The principal factors that impacted our cash flow provided by financing activities were $55.0 million of proceeds received pursuant to short term lines of credit and $18.4 million of proceeds received in connection with the loan made to the Ormesa project.

Capital Expenditures

Our capital expenditures primarily relate to two principal components, the enhancement of our existing power plants and the development of new power plants. In addition, we have budgeted approximately $5.0 million for purposes of the acquisition of machinery and equipment and for an office building for the next two to three years.

Enhancement of existing plants

To the extent not otherwise described below, we expect that the following enhancements of our existing power plants will be funded from internally generated cash or other available corporate resources, which we expect to subsequently refinance with non- or limited-resource debt at the project level.

Mammoth Project Enhancement.    Mammoth-Pacific, L.P. plans to commence a $5.0 million enhancement program of the Mammoth project, consisting primarily of drilling activities, which we

believe will result in an increase in such output of the project of 30,500 MWh per year and is expected to be completed by January of 2006. A substantial portion of the funds required for such enhancement have been earmarked by us and our partners for such enhancement program.

Heber Project Enhancement.    In connection with the Heber 1 and Heber 2 projects, we are currently pursuing an enhancement program consisting of geothermal field optimization and the drilling of an additional well at the Heber 2 project and the adding of additional OEC units at the Heber 1 and Heber 2 projects, in order to increase the generating capacity of the Heber 1 and Heber 2 projects by an estimated 18 MW, for a total budgeted investment of approximately $28.0 million. Such enhancement program will be funded from cash generated by the Heber 1 and Heber 2 projects and other liquidity sources.

Steamboat Hills Project Enhancement.    In connection with the Steamboat Hills project, we plan to add a further OEC unit and perform associated work in order to increase the output of the power plant by an estimated 7.5 MW for a total budgeted investment of approximately $10.0 million, which is currently scheduled to be completed in 2006.

Puna Project Enhancement.    In connection with the Puna project, an approximately $22.0 million enhancement program is currently planned and is intended to increase the output of the project by an estimated 6.5 MW and to improve its reliability. We expect that such enhancement program will be completed in 2007. We are currently exploring various financing options for the refinancing of the acquisition cost of the Puna project.

Ormesa Project Enhancement.    In connection with the Ormesa project, we plan to drill one additional well, add a further OEC unit and replace existing units in order to increase the output of the project by an estimated 10 MW. A preliminary budget is under preparation and we expect that any related capital expenditures will be funded by us from internally generated cash.

Construction of new projects

Initially, we intend to fund the construction projects described below from internally generated cash, existing parent company loans and short-term debt. We currently do not contemplate obtaining any new loans from our parent company.

Galena Re-Powering.    We have commenced the design and construction phase of the re-powering of the Galena project and expect to complete the project by the end of 2005. The estimated $23.0 million of costs attributable to such enhancement will be funded from proceeds received by Ormat Funding in connection with its issuance of its senior secured notes, which are currently deposited in an escrow account, and will be released in accordance with the progress of the construction phase for such enhancement. We expect that the investment will increase the total output of the Steamboat complex by 13 MW.

Desert Peak 2 and Desert Peak 3 Projects.    In connection with the Desert Peak 2 project, we have already drilled the necessary production wells and expect to begin the manufacturing and construction of the associated power plant shortly, which manufacturing and construction is expected to be completed in 2006. The total construction cost for the construction of the 15 MW power plant is estimated to be between $30.0 million and $35.0 million. The construction of the Desert Peak 3 project is expected to be completed in 2007.

Amatitlan Project.    The Amatitlan project, which is in its final engineering stage, is scheduled to be completed in 2006 and the aggregate construction cost related to such project is estimated at approximately $40.0 million.

Other than the enhancements described above and a possible enhancement to the Ormesa project which is in the early stages of conceptual design, we do not anticipate any other material capital expenditures in the near term for any of our operating projects, other than ordinary maintenance requirements, 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. Our exposure to such market risk is currently not significant, principally 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 2007, the energy payments payable under the power purchase agreements for the Heber 1 project and Heber 2 project, the Ormesa project and the Mammoth project will be determined by reference to the relevant power purchaser's short run avoided costs. In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierrra Pacific Power Company pays for energy and capacity is based upon its short run avoided costs. We estimate that energy payments will represent approximately two-thirds of those projects' revenues after 2007 and as a result, expect that there will be some volatility in the revenues received from such projects. As of June 30, 2004, 42.9% of our consolidated long-term debt (excluding amounts owed to our parent) was in the form of fixed rate securities and therefore not subject to interest rate fluctuation risk. However, as of such date, 57.1% of our debt was in the form of a floating rate exposing us to changes in interest rates in connection therewith. In order to mitigate such risks, we have acquired an interest rate cap of 6.0% with respect to the LIBOR component of the interest rate applicable to the Beal Bank loan from 2007 to 2011. Ormat Systems has also entered into an interest rate swap transaction relating to the Bank Continental loan in order to mitigate the risk of LIBOR fluctuations in connection with such loan. Pursuant to such swap, Ormat Systems pays a fixed interest rate of 2.26% instead of the three-month LIBOR rate applicable to the loan and receives a variable interest rate of the three-month LIBOR rate on specific transaction dates. Each transaction date occurs every three months for an additional eight periods beginning on August 23, 2004 through May 22, 2006. The LIBOR three-month interest rate is set on each transaction date. The method used in determining the expected cash flows is the Constant Maturity Swaps for future LIBOR rates. The outstanding balance of such loan and notional amount of such swap as of June 30, 2004 was $5.4 million. Giving effect to such financial instruments, as of June 30, 2004, $395.7 million of our debt, including $143.2 million owed to our parent, is subject to some floating rate risk. As such, we are exposed to changes in interest rates with respect to our long term obligations. The detrimental effect on our pre-tax earnings of a hypothetical 50 basis point increase in interest rates would be approximately $1.1 million. See "—Liquidity and Capital Resources" above for further discussion of our debt instruments.

In anticipation of our plans to refinance the acquisition cost of our Puna project, on October 12, 2004, we entered into a rate lock agreement with Lehman Brothers Special Financing, Inc., an affiliate of one of the underwriters of this offering, at a locked-in treasury rate of 4.2075%, with a notional amount of $62.5 million, and terminating on December 31, 2004 (referred to as the determination date). The rate lock is based on a 10-year treasury security (referred to as the base treasury rate) that matures in August 2004.2014. Pursuant to such agreement, if the base treasury rate, on the determination date is greater than 4.2075%, our counterparty will be required to pay us a floating amount; however, if the base treasury rate is less than 4.2075%, we will be required to pay to our counterparty the floating amount. If the base treasury rate equals 4.2075% on the determination date, no payment will be required to be made by either party. Based on treasury rates and the yield curve on October 16, 2004, each 1 basis point difference between the locked-in rate and the base treasury rate equalled approximately $50,000.

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. 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 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 contacts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. Currently, we have 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 Preferred Auctioned 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)). Upon completion of this offering, pending further application, we intend to invest all of the net proceeds we derive from this offering, pending the use of such proceeds as described in "Use of Proceeds," in interest-bearing investment-grade instruments or bank deposits. We do not expect that a 300 basis point increase or decrease from current interest rates would have a material adverse effect on our financial position, but will have an effect on our results of operations and cash flows.

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. As energy payments pursuant to the power purchase agreements for the Mammoth project (after April 2007), Ormesa project (after April 2007), Heber 1 project, Heber 2 project (after April 2007) and Steamboat 1/1A project change our power purchasers' underlying short run avoided cost, to the extent that inflation causes an increase in the short run avoided cost of our power purchaser, 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 Galena project increase every year through the end of the relevant terms of such agreements, however, 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.

The recent price increase in the cost of raw materials that we use in our Products Segment has not been due to inflation but rather to a high demand for such raw materials, which we believe mainly to result from demand generated by the Chinese market. This may cause a reduction in the profitability of our Products Segment, as well as an increase in the capital costs of our projects under construction and enhancement.

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 June 30, 2004, excluding interest (in thousands):

				Payment of Principal Due By Period
				Remaining Total				Q3-Q4/2004				2005				2006				2007				2008				Thereafter
Long-Term non-recourse & limited recourse debt				$	186,709			$	7,428			$	19,141			$	9,456			$	11,386			$	12,931			$	126,367
Long-Term recourse debt					65,806				4,745				50,490				5,771				1,700				1,700				1,400
Non-recourse Senior Notes due 2020					189,785				296				6,090				9,611				8,932				7,835				157,021
Ormat Industries notes payable					193,852				—				22,047				31,647				31,647				31,647				76,864
Total				$	636,152			$	12,469			$	97,768			$	56,485			$	53,665			$	54,113			$	361,652

The following table sets forth our interest payments payable in connection with our contractual obligations as of June 30, 2004 (in thousands):

				Payment of Interest Due By Period
				Remaining Total				Q3-Q4/2004				2005				2006				2007				2008				Thereafter
Long-Term non-recourse & limited recourse debt				$	124,912			$	6,356			$	12,354			$	12,548			$	12,151			$	11,322			$	70,181
Long-Term recourse debt					4,398				926				1,791				735				543				308				95
Non-recourse Senior Notes due 2020					154,468				8,381				15,725				15,144				14,354				13,629				87,235
Ormat Industries notes payable					52,657				5,150				10,562				9,713				7,834				5,777				13,621
Total				$	336,435			$	20,813			$	40,432			$	38,140			$	34,882			$	31,036			$	171,132

Interest on the Senior Notes due in 2020 is fixed at a rate of 8.25%. 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.

Off-Balance Sheet Arrangements

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. As of the date hereof, two letters of credit have been issued pursuant to this facility. The first was issued in favor of the trustee for the 8¼% senior secured notes, for a face amount of $8.1 million, which will be increased by an additional amount of $2.7 million as of December 31, 2004. The second was issued in favor of Beal Bank, for a face amount of $3.6 million. Such letters of credit have been issued to substitute for current cash balances in respective reserve accounts. We have used the available cash, in the amount of $11.8 million, that has been released from such reserve accounts for working capital and reductions of outstanding bank debt.

On July 15, 2004, we entered into a reimbursement agreement with Ormat Industries, pursuant to which we agreed to reimburse Ormat Industries for any draws made on any standby letter of credit issued by Ormat Industries that is subject to the guarantee fee agreement between us and Ormat Industries and any payments made under any guarantee provided by Ormat Industries subject to such agreement. Interest on any amounts owing pursuant to the reimbursement agreement is paid in U.S. dollars at a rate per annum equal to Ormat Industries' average effective cost of funds plus 0.3%.

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.

Bank Hapoalim has issued such performance letters of credit in favor of our customers from time to time. Initially, our parent, Ormat Industries, was Bank Hapoalim's counterparty 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 between Ormat Systems and our parent, we have assumed such letters of credit and are now the direct counterparty of Bank Hapoalim on such letters of credit. As of June 30, 2004, the aggregate amount available to be drawn under these letters of credit was $17.2 million. The amount that can be drawn under some of these letters of credit may be increased from time to time subject to the satisfaction of certain conditions.

As of the date hereof, we have not had a draw presented against any letter of credit issued or provided on our behalf and do not believe that it is likely that any claims will be made under a letter of credit in the foreseeable future.

Concentration of Credit Risk

Our credit risk is currently concentrated with a limited number of major customers, Sierra Pacific Power Company, Southern California Edison Company, Hawaii Electric Light Company,

PNOC-Energy Development Corporation, The Kenya Power and Lighting Company Limited and two electric distribution companies who are assignees of Empresa Nicaraguense de Electricidad. 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.

Historically, Southern California Edison Company accounted for 27.1%, 25.5% and 0% of our total revenues for the three years ended December 31, 2003, 2002 and 2001, respectively, and 41.9% and 25.3% of our total revenues for the six months ended June 30, 2004 and 2003, respectively. Southern California Edison Company 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 9.5%, 11.2% and 8.3% of our total revenues for the three years ended December 31, 2003, 2002 and 2001, respectively, and 12.6% and 10.6% of our total revenues for the six months ended June 30, 2004 and 2003, respectively.

PNOC-Energy Development Corporation accounted for 10.6%, 18.2% and 26.0% of our total revenues for the three years ended December 31, 2003, 2002 and 2001, respectively, and 3.1% and 12.3% of our total revenues for the six months ended June 30, 2004 and 2003, respectively.

The two electric distribution companies who are assignees of Empresa Nicaraguense de Electricidad accounted for 9.7%, 10.8% and 18.6% of our total revenues for the three years ended December 31, 2003, 2002 and 2001, respectively, and 6.1% and 11.6% of our total revenues for the six months ended June 30, 2004 and 2003, respectively.

The Kenya Power & Lighting Co. Ltd. accounted for 8.1%, 10.8% and 18.0% of our total revenues for the years ended December 31, 2003, 2002 and 2001, respectively, and 4.8% and 9.2% of our total revenues for the six months ended June 30, 2004 and 2003, respectively.

Following the acquisition of the Puna project, Hawaii Electric Light Company has become one of our key customers, and we expect that Hawaii Electric Light Company will account for approximately 4.0% of our total revenues in the year 2004.

Government Grants and Tax Benefits

Our subsidiary, 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. One such approval was received in 1996 and the other was received in May 2004. 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 reduced Israeli income tax rates of 25.0% for an additional five years. These benefits are subject to certain conditions set forth in the certificate of approval from Israel's Investment Center, that 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 offering) without the prior written approval of the Investment Center.

Prior to 2003, our research and development efforts were partially funded through grants from the Office of the Chief Scientist of the Israeli Ministry of Industry and Trade. We currently have no such grants available or outstanding. Under Israeli law, we are required to pay royalties to the Israeli government based on revenues derived from the sale of products developed with the assistance of such grants. The applicable royalty rate is between 3.0% to 5.0%, and the amount of royalties required to be paid are capped at the amount of the grants received (in U.S. dollars). The outstanding balance of grants provided after January 1, 1999 accrue interest at a rate equal to the 12-month LIBOR, as published on the first day of the calendar year in which the particular grant was approved. Because the royalties are payable only from revenues, if any, derived from the relevant products, we only recognize a royalty expense to the government upon delivery of the product to our customers.

BUSINESS

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 power plants, and we also design, develop and build, and plan to own and operate, recovered energy-based power plants, in each case using equipment that we design and manufacture. We conduct our business activities in two business segments. We develop, build, own and operate geothermal power plants in the United States and other countries around the world and sell the electricity they generate. In addition, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants.

All 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 power generation business, we have developed and continue to develop products that produce electricity from recovered energy or so-called "waste heat." Recovered energy or waste heat represents residual heat that is generated as a by-product of gas turbine-driven compressor stations and in 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, is captured in the recovery process and is used by recovered energy power plants to generate electricity without burning additional fuel and without emissions.

Our Power Generation Business

We are the fastest growing geothermal power generation company in the United States measured by growth in generating capacity. We increased our net ownership interest in generating capacity by 164 MW between December 31, 2002 and June 30, 2004, of which 152 MW was attributable to our acquisition of geothermal power plants from third parties and 12 MW was attributable to increased generating capacity of our existing geothermal power plants resulting from plant technology upgrades and improvements to our geothermal reservoir operations, which include improving methods of heat source supply and delivery. We also own and operate or control and operate geothermal projects in Guatemala, Kenya, Nicaragua and the Philippines and continue to pursue opportunities to acquire and develop similar projects elsewhere in the world, including in the United States. Most of our projects are located in regions where there is, or is expected to be, demand for additional generating capacity.

In 2003, pro forma revenues from the sale of electricity by our domestic projects were $128.7 million, constituting approximately 79.1% of our total pro forma revenues from the sale of electricity, and pro forma revenues from the sale of electricity by our foreign projects were $33.9 million, constituting approximately 20.9% of our total pro forma revenues from the sale of electricity. In 2003, our actual revenues from the sale of electricity by our domestic projects were $43.8 million and by our foreign projects were $34.0 million, respectively. Pro forma revenues from the sale of electricity constituted approximately 79.6% of our total pro forma revenues in 2003. As noted previously, such pro forma revenues do not include revenues generated from the Steamboat 2/3 project and Steamboat Hills project, two additional domestic projects that were acquired this year.

The table below summarizes key information relating to our projects that are currently in operation, under construction and/or subject to enhancement.

Project				Location				Ownership				Commercial Operation Date				Generating Capacity in MW(1)				Power Purchaser				Contract Expiration
Projects in Operation
Domestic
Ormesa				East Mesa, California					100	%		1986/1987					48			Southern California Edison Company				2016/2017
Heber 1				Heber, California					100	%		1985					38			Southern California Edison Company				2015
Heber 2				Heber, California					100	%		1993					36			Southern California Edison Company				2023
Steamboat(2)				Steamboat, Nevada					100	%		1986/1988/1992					34			Sierra Pacific Power Company				2006/2018/2022
Mammoth(3)				Mammoth Lakes, California					50	%		1984/1990					25			Southern California Edison Company				2014/2020
Puna				Puna, Hawaii					100	%		1993					25			Hawaii Electric Light Company				2027
Brady				Churchill County, Nevada					100	%		1985/1992					20			Sierra Pacific Power Company				2022
Steamboat Hills				Steamboat Hills, Nevada					100	%		1988					6			Sierra Pacific Power Company				2018
Total Domestic Projects in Operation:																	232
Foreign
Leyte(3)				Philippines					80	%		1997					49			PNOC - - Energy Development Corporation				2007
Momotombo(3)				Nicaragua					100	%		mid 1980's					28			DISNORTE/DISSUR				2014
Zunil(3)				Guatemala					21	%		1999					24			Instituto Nacional de Electrification				2019
Olkaria III				Kenya					100	%		2000					13			Kenya Power & Lighting Co. Ltd.				2020(4)
Total Foreign Projects in Operation:																	114
Total Projects in Operation:																	346
Projects under Construction
Desert Peak 2				Churchill County, Nevada					100	%		2006(5)					15			Nevada Power Company				n/a(7)
Galena				Steamboat Hills, Nevada					100	%		2005(5)					13	(6)		Sierra Pacific Power Company				n/a(7)
Amatitlan				Guatemala					100	%		2006(5)					20			Instituto Nacional de Electrification				n/a(8)
Total Projects under Construction:																	48

Project				Location				Ownership				Commercial Operation Date				Generating Capacity in MW(1)				Power Purchaser				Contract Expiration
Projects under Enhancement
Heber 1 and 2 Enhancement(9)				Heber, California					100	%							18	(11)
Puna Enhancement(10)				Puna, Hawaii					100	%							9	(12)
Steamboat Hills Enhancement(10)				Steamboat Hills, Nevada					100	%							7
Mammoth Enhancement(10)				Mammoth Lakes, California					50	%							4
Ormesa Enhancement(10)				East Mesa, California					100	%							10	(13)
Total Projects under Enhancement:																	48
Total Projects under Construction or Enhancement:																	96

(1)

References to generating capacity refer to the net amount of electrical energy available for sale to the power purchaser, 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). In the case of projects under construction or enhancement, references to generating capacity refer to the net amount of electrical energy that we expect will be available for sale to the relevant power purchasers. This column represents the net generating capacity of the project, not our net ownership in such generating capacity. Such net generating capacity is based on operational data for the previous 12 months.

(2)	Includes the Steamboat 1/1A project and the Steamboat 2/3 project.

(3)	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 project, Leyte project and Zunil project, in which we have a 50%, 80% and 21% ownership, respectively.

(4)	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 a proposed construction of additional facilities that we expect would add approximately 35 MW of generating capacity to this project.

(5)	Projected.

(6)	Incremental megawatts to the Steamboat complex.

(7)	The power purchase agreement will expire 20 years from the January 1 immediately following the commercial operation date.

(8)	The power purchase agreement will expire at the later of 20 years from the commencement of commercial operations and 23 years from the commencement of construction works.

(9)	We are currently in discussions with Southern California Edison Company, the power purchaser for this project, regarding the implementation of these proposed enhancements.

(10)	These enhancements are in their early engineering stage.

(11)	We expect that the enhancement will result in an additional 8 MW that can be sold under the existing power purchase agreement and another 10 MW that, subject to the negotiation of offtake arrangements, will be sold either to the existing power purchaser or a different power purchaser.

(12)	We expect that the enhancement will result in an additional 3 MW that can be sold under the existing power purchase agreement and another 6 MW that, subject to the negotiation of offtake arrangements, will be sold to with the existing power purchaser.

(13)	We expect that the enhancement will result in an additional 10 MW that, subject to negotiation of offtake arrangements, will be sold to a different power purchaser.

All of the revenues that we derive from the sale of electricity are from fully-contracted payments under long-term power purchase agreements. In the United States, the power purchasers under such agreements are all investor-owned electric utilities. More than 70% of our total pro forma revenues in 2003 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 recently privatized state-owned entities. We have obtained political risk insurance from the Multilateral Investment Guarantee Agency of the World Bank group 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. In December 2003, we acquired the Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project; in February 2004, we acquired the Steamboat 2/3 project; in May 2004, we acquired the Steamboat Hills project and in June 2004, we acquired the Puna project. In total, we have increased our net ownership interest in generating capacity from 94 MW as of December 31, 2001 to 305 MW as of June 30, 2004. 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; and

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

As part of these efforts, we regularly monitor requests for proposals from, and submit bids to, investor-owned electric utilities in the United States to provide additional generating capacity, primarily in the western United States where geothermal resources are generally concentrated. We also respond to international tenders issued by foreign state-owned electric 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 or construction of new projects and enhancement of existing projects. Based on our current development and construction schedule, which is subject to change at any time and which we may not achieve, we expect to have approximately 76 additional MW in generating capacity in the United States by the end of 2006 and approximately 20 additional MW in Guatemala by June 2006. In addition, we have obtained exclusive rights to develop the geothermal resources of a project in China, which, if implemented, is expected to produce approximately 50 MW in generating capacity. We have recently held discussions with the Kenyan government and Kenya Power & Lighting Co. Ltd. regarding, among other things, the construction of Phase II of the Olkaria III project in Kenya and the provision of certain collateral and government support. If implemented, we expect Phase II would add approximately 35 MW in generating capacity to the current Olkaria III project. We must notify Kenya Power & Lighting Co. Ltd., by April 17, 2005, whether we will proceed to construct Phase II of the Olkaria III project and, if we notify Kenya Power & Lighting Co. Ltd. that we will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to provide such notification we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. We intend to pursue these opportunities to the extent they continue to meet our investment criteria and business strategy.

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 inventory purposes.

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. We recently sold two of our OEC units, with a total gross output of approximately 18 MW, to Instituto Costarricense de Electricidad in Costa Rica, which is developing the Miravalles V geothermal power project in that country. We also recently sold one of our OEC units for approximately 2 MW for installation at Oserian Farm in Kenya, where farmers grow flowers for export.

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 have installed one of our recovered energy-based generation units at Enterprise Product's Neptune gas processing plant in Louisiana.

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

Engineering, Procurement and Construction of Power Plants.    We engineer, procure and construct (EPC), 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 Mokai and Wairakei geothermal power plants in New Zealand.

Operation and Maintenance of Power Plants.    We provide operation and maintenance services for geothermal power plants owned by us and by third parties.

In 2003, our actual revenues from our products business were $41.7 million, constituting approximately 20.4% of our total pro forma revenues and approximately 34.9% of our actual revenues.

Industry Background

Geothermal Energy

All of the projects we currently own 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 which result in redistributive costs. 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 as long as the wellfield is properly operated. Geothermal energy projects typically have higher capital costs (primarily as a result of the costs attributable to wellfield 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.

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 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 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.

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.

Electricity generation from geothermal resources in the United States currently constitutes a $1.5 billion-a-year industry (in terms of revenues) and accounts for 19% of all non-hydropower renewable energy-based electricity generation in the United States. 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 recent forecast of the U.S. Department of Energy projects the addition of geothermal installations with generating capacity totaling 6,840 MW by 2025, based on the assumption that natural gas prices will remain relatively stable at current levels. 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 Energy Information Administration*, Annual Energy Outlook 2004).

Much of this growth potential stems from growing global concerns 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, Connecticut, Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, Minnesota, Nevada, New Jersey, New Mexico, Pennsylvania, Rhode Island, Texas, and Wisconsin 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. Eleven of these seventeen states (including California, Nevada and Hawaii, where we have been the most active in our geothermal energy development and in which all of our U.S. projects are located) define geothermal resources as "renewables." Several other states are also considering the adoption of renewable portfolio standards, renewable portfolio goals or similar laws.

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 1% per year so that 20% of its retail sales are procured from eligible renewable energy sources by 2017. Presently, approximately 10% of the electricity generated in California is derived from renewable resources. Nevada's renewable portfolio standard requires each Nevada electric utility to obtain 5% of its annual energy requirements from renewable energy sources in 2004, which requirement increases to 7% in 2005 and thereafter increases by 2% every two years until 2013, when 15% of such annual energy requirements must be provided from renewable energy sources. 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, in some states an entity generating electricity from renewable resources, such as geothermal energy, is awarded renewable energy credits, which we refer to as RECs, that can be sold for cash. RECs have been sold for a wide range of prices during the past year, but because the markets for these RECs still remain limited, the prices have been volatile, and vary greatly from state to state. On October 14, 2004, we entered into agreements with Sierra Pacific Power Company, a utility company in the state of Nevada, to sell RECs resulting from electricity we generate for station use at our Desert Peak, Brady, Steamboat Hills and Steamboat 2/3 projects. The price for such RECs under such agreements is $0.005 per kWh, subject to a reduction to $0.0045 per kWh if we generate less than 80% or more than 120% of a baseline amount.

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 as a credit against our federal income taxes. We are also permitted to deduct up to 95% of the cost of the power plant over five years on an accelerated basis, which results in more

*	The Energy Information Administration is a governmental agency under the U.S. Department of Energy.

of the cost being deducted in the first few years than during the remainder of the depreciation period. These two tax benefits collectively offset approximately one-third of the capital cost of each new project.

Under the American Jobs Creation Act of 2004 that was passed by Congress on October 11, 2004, and which the President is expected to sign shortly, geothermal power companies would be allowed to claim a "production tax credit" of 1.8 cents per kWh on electricity produced from geothermal resources. According to such bill, credits could be claimed on such electricity sold during the first five years after a project achieves commercial operation. Only projects put into service during the period after the bill is signed into law and through December 31, 2005 would qualify for such production tax credits. The owner of the project would have to choose between this production tax credit and the 10% energy tax credit described above.

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. Different countries have also adopted active governmental programs designed to encourage clean renewable energy power generation. For example, China, where we are currently developing a project, has in place a five-year Plan for New and Renewable Energy Commercialization Development. The plan's goals include increasing production of geothermal energy as well as providing electricity in remote areas. Several Latin American countries have rural electrification programs and renewable energy programs. For example, Nicaragua, where we operate the Momotombo project, is currently developing a national rural electrification plan with the support of the World Bank. One of the plan's primary goals is the reduction of market barriers to renewable energy technologies useful for remote areas not connected to the main electricity grid. Nicaragua also has a national master plan for geothermal energy, which is intended to facilitate the awarding of concessions for geothermal exploration and development in the country. Guatemala, another country in which we have ongoing operations (the Zunil project) and development activities (the Amatitlan project), recently approved a law 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 power generation as a significant market opportunity for us in the United States and internationally. 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 and Hawaii allow electric utilities to include recovered energy-based power generation in calculating their compliance with the state's renewable portfolio standards. In addition, North Dakota, South Dakota and the 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.

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 rainfall), 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.    All of our existing 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 renewable 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 any of 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 more than 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.

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 and developing and constructing new geothermal and recovered energy-based power projects in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development and which 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;

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

•	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;

•	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; and

•	Long-term Contracts — entering into long-term contracts with energy purchasers that will provide stable cash flows.

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 EWG, are Qualifying Facilities and are eligible for regulatory exemptions from most provisions of the FPA, certain state laws and regulations, and PUHCA as set forth in 18 C.F.R. Section 292, Subpart F. As an EWG, the Puna project is exempt from regulation under PUHCA, and does not cause us to be regulated as a holding company under PUHCA. The Puna project is not subject to the FPA.

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. At times, the holder of rights in the geothermal resource is a governmental entity and at times, a private entity. Usually, the terms of the lease (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 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. 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 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 346 MW of generating capacity. Since our recent acquisitions in California 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 efficiency and performance of most of our acquired facilities and have been able to use the staff required to operate these facilities more efficiently. For example, we have been able to increase the output of the Brady project by approximately 50% since its acquisition by us.

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, 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.

Non-recourse debt refers to debt that is repaid solely from the project's revenues (rather than our revenues or revenues of any other project) and generally is secured by the project's physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in that project affiliate. This type of financing is 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 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 were 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 the Multilateral Investment Guarantee Agency (an institution that is part of the World Bank Group). From time to time, we also examine the possibility of purchasing political risk insurance from private sector providers, such as Zurich Re, AIG and other such companies, however, to date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency. Such insurance policies cover, in general and subject to the limitations and restrictions contained therein, 80%-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.

Description of Our Projects

In 2003, pro forma revenues from the sale of electricity by our domestic projects were $128.7 million, constituting 79.1% of our total pro forma revenues from the sale of electricity, and pro forma revenues from the sale of electricity by our foreign projects were $33.9 million, constituting 20.9% of our total pro forma revenues from the sale of electricity. In 2003, our actual revenues from the sale of electricity by our domestic projects were $43.8 million and by our foreign projects were $34.0 million, respectively. Pro forma revenues from the sale of electricity constituted approximately 79.6% of our total pro forma revenues in 2003. As noted previously, such pro forma revenues do not include revenues generated from the Steamboat 2/3 project and Steamboat Hills project, two additional domestic projects that were acquired this year.

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.

Domestic Projects

Our projects in operation in the United States have a generating capacity of approximately 232 MW. All of our current domestic projects are located in California, Nevada and Hawaii. We also have projects under construction and enhancement in California, Nevada and Hawaii.

The Ormesa Project

The Ormesa project is located in East Mesa, Imperial Valley, California. The Ormesa project consists of six plants, OG I, OG IE, OG IH (collectively, the OG I plants), OG II, GEM 2 and GEM 3. The various OG I plants commenced commercial operations between 1987 and 1989, and the OG II plant commenced commercial operations in 1988. The GEM 2 and GEM 3 plants commenced commercial operations in April 1989. The OG plants utilize a binary system, and the GEM plants utilize a flash system. The OG I plants have a generating capacity of 34 MW; the OG II plant has a generating capacity of 14 MW; and the GEM 2 and GEM 3 plants have a generating capacity of 28 MW. However, electricity generated by the GEM 2 and GEM 3 plants is not sold under a power purchase agreement because their power is used to provide auxiliary power for wellfield operations at the Ormesa project. The Ormesa project sells its electrical output to Southern California Edison Company under two separate power purchase agreements. In certain circumstances, Southern California Edison Company or its designee has a right of first refusal to acquire the OG I and OG II plants. The Ormesa project was acquired in April 2002, and was initially re-financed with project finance debt from United Capital. It is anticipated that on or before January 31, 2005, the United Capital loan will be paid off with a portion of the proceeds from the issuance by Ormat Funding of its senior secured notes on February 13, 2004.

In connection with the power purchase agreements for the Ormesa project, Southern California Edison Company 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 for auxiliary purposes. We have commenced discussions with Southern California Edison Company to resolve such dispute and, in addition, to combine the relevant power purchase agreements for the Ormesa project into one agreement, which would enhance our operating flexibility and would not otherwise adversely affect our operations. In the interim period, Southern California Edison Company has tentatively agreed to pay a lower fixed price for such power.

The Heber Projects

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 geothermal resources field. The plant utilizes a dual flash system and has a generating capacity of 38 MW. The Heber 1 project sells its electrical output to Southern California Edison Company under a power purchase agreement. In certain circumstances, Southern California Edison Company 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 Company purchase the power plant. The Heber 1 project was acquired in December 2003 and was financed with project finance debt from Beal Bank in December 2003.

The Heber 2 Project.    The Heber 2 project is 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 36 MW. The Heber 2 project sells its electrical output to Southern California Edison Company under a power purchase agreement. The Heber 2 project was acquired in December 2003, and was financed with project finance debt from Beal Bank in December 2003.

The Steamboat Projects

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

commercial operations in 1986 and 1988, respectively. The Steamboat 1/1A project utilizes a binary system and has a generating capacity of 5 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 re-financed with the proceeds from the issuance by Ormat Funding of its senior secured notes on February 13, 2004.

The Steamboat 2/3 Project.    The Steamboat 2/3 project is also located in Steamboat, 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 29 MW. 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 was financed with the proceeds from the issuance by Ormat Funding of its senior secured notes on February 13, 2004.

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 power purchase agreement capacity 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 additional drilling and certain other capital expenditures to take full advantage of the power purchase agreement. The Steamboat Hills project was acquired in May 2004 using internally generated cash.

The Mammoth Project

The Mammoth project is located in Mammoth Lakes, California. The Mammoth project is comprised of three plants, G-1, G-2 and G-3. The G-1 plant commenced commercial operations in 1985 and the G-2 and G-3 plants commenced commercial operations in 1990. The Mammoth project utilizes a binary system and has a generating capacity of 25 MW. Our project subsidiary owns a 50% partnership interest in Mammoth-Pacific, L.P., which owns 100% of the Mammoth project. The other 50% partnership interest is owned by an unrelated third party. The Mammoth project sells its electrical output to Southern California Edison Company under three separate power purchase agreements. Under the G-1 power purchase agreement, in certain circumstances, Southern California Edison Company or its affiliates has a right of first refusal to acquire the plant. Our 50% ownership interest in the Mammoth project was acquired in December 2003 using internally generated cash and was financed with project finance debt from Beal Bank in December 2003.

The Brady Project

The Brady project is located in Churchill County, Nevada and includes the Brady plant and the Desert Peak 1 plant. The Desert Peak 1 plant is approximately 4.5 miles southeast of the Brady plant. The Brady plant commenced commercial operations in 1992 and the Desert Peak 1 plant commenced commercial operations in 1985. The Brady project has a generating capacity of 20 MW and has in the past utilized a dual flash design. In August 2002, an additional 6 MW binary unit was added to the Brady plant to generate additional power from the brine before its reinjection. The Desert Peak 1 plant utilizes a dual flash design. The Brady project sells its electrical output from the Brady plant and Desert Peak 1 plant to Sierra Pacific Power Company under a power purchase agreement. Our project subsidiary is currently evaluating the replacement of the Desert Peak 1 plant with a new plant that would be more efficient. The new plant may be constructed on the same site as the existing Desert Peak 1 plant. Construction would likely begin in the first quarter of 2005 and be completed in early 2006, at an estimated total project cost of approximately $8 million. The Brady project was acquired in June 2001 using internally generated cash and was re-financed with the proceeds from the issuance by Ormat Funding of its senior secured notes on February 13, 2004.

The Puna Project

The Puna project is located in the Puna district, Hawaii. The Puna plant commenced commercial operations in 1993. The Puna plant utilizes a geothermal combined cycle system, and has a generating capacity of 25 MW, although the power purchase agreement is for 30 MW. 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. We intend to increase the output of the Puna project by upgrading the technology of the plant through the addition of Ormat Energy Converters, drilling another production well, and negotiating a new power purchase agreement for the additional generating capacity that will be available as a result of such activities. The Puna project was acquired in June 2004 with the proceeds of parent company loans and short-term bank loans.

Foreign Projects

Our foreign projects in operation have a generating capacity of approximately 114 MW. Our current foreign projects are located in the Philippines, Nicaragua, Kenya and Guatemala. We also have projects under development or construction in Guatemala, China, El Salvador and Kenya.

The Leyte Project (The Philippines)

The Leyte project is located in Leyte, Philippines, on the Isle of Leyte. The Leyte project consists of 4 power plants. The Leyte plants utilize steam systems and have a combined generating capacity of 49 MW. Our project subsidiary has 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, 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. Ormat-Leyte Co. Ltd. has an outstanding non-recourse loan to the Export-Import Bank of the United States the outstanding balance of which was $16.5 million as of June 30, 2004. The loan is due and payable in approximately equal quarterly installments until 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 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 demand 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 during the remaining term of the BOT agreement.

In July, 2004, a transformer for one of the plants at the Leyte project ceased operating for a period of three months. In addition, in August 2004, one of the generators at the Leyte project also ceased operations. We have replaced the transformer and have sent the generator for repair, which has not yet been completed. As a result of these events, for the nine-month period ended September 30, 2004, we experienced a $1.2 million reduction in revenues compared to our expected revenues for that period. We expect that our commercial and business interruption insurance policies will, subject to deductibles and applicable waiting periods, cover the costs associated with such replacement and repair as well as cover the reduction in revenues we experienced as a result of the reduced electricity generation.

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. In 2003, an additional 6 MW binary unit was added, bringing the generating capacity to approximately 28 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 $18.5 million as of June 30, 2004.

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 operations in August 2000, and a geothermal field. The plant currently has a generating capacity of approximately 13 MW (early generation commercial operation for Phase I). The parties contemplated the construction of Phase II (full generation commercial operation) of this project which we expect, upon completion, would 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 & Lighting Co. Ltd., which was further amended in July 2000 and April 2003. 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 by two additional five year terms. 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 the Kenya Power & Lighting Co. Ltd.

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. Our project subsidiary owns 21% of the outstanding partnership interests of Orzunil I de Electricidad, Limitada. 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 prospectus, 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 June 30, 2004, $31.0 million. The loans are due and payable in quarterly installments until November 2011. Each of the IFC and the CDC owns 14% of the issued and outstanding partnership interests of Orzunil I de Electricidad, Limitada.

Projects under Construction

We are in varying stages of development and construction of projects, both domestic and foreign. Based on our current construction schedule, we expect to have an additional generating capacity of approximately 28 MW in the United States by the end of 2006 and approximately 20 additional MW in Guatemala by June 2006.

The Desert Peak 2 Project

Our project subsidiary is currently constructing the Desert Peak 2 project in Churchill County, Nevada (near the Brady project). The Desert Peak 2 project is expected to have a generating capacity of up to 15 MW and will utilize our Ormat Energy Converters. The electrical output from the project will be sold, and renewable energy and environmental credits will be 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 such power plant. The Desert Peak 2 project is expected to be completed in early 2006.

The Amatitlan Project (Guatemala)

Our project subsidiary is currently constructing a geothermal power plant in Amatitlan, Guatemala on a "build, own and operate" or "BOO" basis. The project is comprised of one power plant which we expect will have a generating capacity of 20 MW, and has obtained the rights to various geothermal production and reinjection wells. The Amatitlan plant will use 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 works, 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 Instituto Nacional de Electrification and the result of a feasibility test, our project subsidiary may increase the power generating capacity of the power plant to up to an aggregate of 50 MW by drilling additional wells. We anticipate that the Amatitlan project will be completed in 2006.

The Galena Project

Our project subsidiary is in the process of replacing the equipment currently used in the Steamboat 1/1A project with new upgraded equipment. Our project subsidiary will augment the operation of the Steamboat 1/1A project with additional geothermal resources extracted from the Steamboat 2/3 project's leases that will be diverted for use by Steamboat 1/1A project. After such upgrade, we will rename the Steamboat 1/1A project as the Galena project. We believe that this upgrade will allow the Galena project to obtain a generating capacity of 20 MW (adding an incremental 13 MW to the existing Steamboat complex). We anticipate that the Galena project will achieve commercial operations by the end of 2005 and that the project will sell its electrical output and transfer its renewable energy credits to Sierra Pacific Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of such power plant. Our project subsidiary is coordinating the transition from the Steamboat 1/1A project to the Galena project with Sierra Pacific Power Company. We intend to replace the existing equipment at the Steamboat 1/1A project with current Ormat technology, which we believe will optimize the geothermal resources available.

Enhancement of Operating Projects

We are currently pursuing the addition of Ormat Energy Converters for the Heber 1 and Heber 2 projects, the drilling of additional wells with respect to the Heber 2 project, and other enhancement activities for the Heber 1 and Heber 2 projects. We believe that these enhancements could increase the generating capacity of the Heber 1 and Heber 2 projects collectively by 18 MW, and we are currently in discussion with Southern California Edison Company and others regarding these proposed enhancements. We are also in the early engineering stages of an enhancement program for the Mammoth, Steamboat Hills, Ormesa and Puna projects, which we believe could increase the generating capacity of each of these facilities by 4 MW, 7 MW, 10 MW and 9 MW, respectively.

Projects under Development

We also have projects under development in the United States, China, El Salvador and Kenya. In certain cases, we have obtained concession agreements and/or financing commitments, and in other

cases, the projects are in early development stages. 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 Desert Peak 3 Project

In the United States, the Desert Peak 3 project is currently under development and 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 that has a 20-year term commencing on the January 1 following the commercial operation date of the plant and which was signed as part of Nevada Power Company's efforts to comply with Nevada's renewable portfolio standards.

The Yunnan Project (China)

OrYunnan Geothermal Co., Ltd., which is a joint venture established between our project subsidiary and Yuan 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 48 MW, which we estimate will require a capital investment of approximately CNY 940,000,000 (approximately $112.8 million calculated at the prevailing exchange rate as at June 30, 2004). As of the date hereof, our project subsidiary is awaiting completion of the Chinese central government approval procedures, following which negotiations with the provincial utility company towards the signing of a power purchase agreement can conclude. 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 Yunan 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 estimates that the commercial operation date of the plant is to be January 1, 2006. However, we have been in the development stage of the OrYunnan Project for several years and there is no assurance that this date will not have to be extended.

The San Vicente/Chanameca Project (El Salvador)

One of our project subsidiaries has a concession over the geothermal field relating to the San Vicente project and the Chanameca project in El Salvador. However, we are currently discussing the sale of this concession with a potential buyer.

The Olkaria III Project — Phase II (Kenya)

As previously noted, our project subsidiary and Kenya Power & Lighting Co. Ltd. contemplated the construction of Phase II of the Olkaria III project. As of the date hereof, our project subsidiary has drilled the wells and commenced preliminary construction activities but has not begun any material construction activities with respect to Phase II. We halted our construction activities due to uncertainty relating to the form of government support that would be provided for the project and the related collateral package, both of which are pre-conditions for the financing of Phase II. Our project subsidiary has recently engaged in discussions with the Kenyan government and Kenya Power & Lighting Co. Ltd., as facilitated by the Multilateral Investment Guarantee Agency in connection with such matters. Pursuant to the power purchase agreement, our obligation to construct Phase II is contingent upon Kenya Power & Lighting Co. Ltd. providing to us (1) a letter of support from the Kenyan Government and (2) a certain deposit by April 17, 2004, a deadline which was not met. We

currently have until April 17, 2005 to notify Kenya Power & Lighting Co. Ltd. whether we will proceed to construct Phase II of the Olkaria III project, in which case the current power purchase agreement with respect to Phase I will remain valid until 2020. If we notify Kenya Power & Lighting Co. Ltd. that we will not proceed, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to make such notification that we will not proceed, we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement.

Geothermal Assets for Future Development in the United States

We have various geothermal leases for future development in the United States. These geothermal leases include the Meyberg lease near Steamboat, Nevada, the Newberry lease in Oregon, the Rhyolite Plateau lease near Mammoth, various leases for future development in Puna and various other leases for development in Nevada.

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. Recently, one of our 1.8 MW power units was installed at Oserian Farm in Kenya, where farmers grow flowers for export.

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.

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 we 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 enter into agreements to purchase industrial waste heat, and into long-term power purchase agreements with offtakers 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.

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. Our Neptune recovered energy project is an example of such a model. We have 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).

Our recovered energy generation units qualify as Qualifying Facilities for regulatory purposes and, if structured properly, may also 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 installed on a Pemex pipeline in Mexico. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.

Engineering, Procurement and Construction of Power Plants.    We engineer, procure and construct (EPC), 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 Mokai and Wairakei geothermal power plants in New Zealand.

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, our subsidiary, Ormat Pacific, Inc., is currently acting as EPC contractor for two geothermal projects in New Zealand owned by Contact Energy Limited and Tuaropaki Power Company Limited, respectively. Ormat Industries has guaranteed Ormat Pacific, Inc.'s obligations under both agreements. Ormat Systems will supply the equipment and products necessary for the construction and operation of these power plants.

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 constitute 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.

Operation and Maintenance of Power Plants.    We provide operation and maintenance services for geothermal power plants owned by us and by third parties. For example, we provide operations and management services to the Orzunil project in Guatemala, in which we have a minority ownership interest.

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.

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 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 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 range from one year to 18 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, and competition has contributed to a reduction in electricity prices.

In the geothermal power generation sector, our main competitors in the United States are CalEnergy, Calpine and Caithness. Some of these companies are also active outside of the United States. Outside of the United States, aside from these companies, we have not recently encountered competition from any private sector geothermal power developer, but may face competition from national electric utilities or state-owned oil companies.

In the products business, our main competitors are Mitsubishi, Fuji and Toshiba of Japan, GE/Nuevo Pignone and Ansaldo of Italy, Siemens of Germany, Alstom of France and Kaluga of Russia. In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets.

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 unit has technological and economical advantages over the Siemens/Kalina technology and the conventional steam technology. Recently, United Technologies announced the introduction of a small 200 kW Organic Rankine Cycle for recovered energy.

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

All of our revenues from the sale of electricity 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 Company, Hawaii Electric Light Company, PNOC-Energy Development Corporation and Sierra Pacific Power Company have accounted for 48.3%, 9.2%, 6.2% and 5.6% of our pro forma revenues, respectively, for the fiscal year ended December 31, 2003. Based on publicly available information, as of September 1, 2004, the issuer ratings of Southern California Edison Company, Sierra Pacific Power Company and Nevada Power Company (a potential power purchaser for the Desert Peak 2 and Desert Peak 3 projects) were Baa1 (stable outlook), B1 (negative outlook) and B1 (negative outlook), respectively, from Moody's Investors Services and BBB (stable outlook), B+ (negative outlook), and B+ (negative outlook), respectively, from Standard & Poor's Ratings Services and the issuer rating of Hawaii Electric Light Company was BBB+ (stable outlook) from Standard & Poor's Ratings Services. 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.

All of our revenues from the products business were derived from contractors or owners or operators of power plants, process companies and pipelines, including Miravalles and Mokai, which accounted for 25.8% and 24.8%, respectively, of our revenues from the sale of products in 2003.

Raw Materials

In connection with our manufacturing activities, we use raw materials such as steel and aluminium. 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.

Employees

As of July 1, 2004, we had 676 employees, of which 223 were in the United States, 294 were in Israel and 159 were located in other countries around the world. We expect that any future growth in the number of our employees would be mainly attributable to the purchase and/or development of new power plants.

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 Labor and Welfare, 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 coverages 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. The policies are issued by entities which specialize in such policies, such as Multilateral Investment Guarantee Agency (a member of the World Bank Group). From time to time, we also examine the possibility of purchasing political risk insurance from private sector providers, such as Zurich Re, AIG and other such companies, however, to date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency. Such insurance policies cover, in general, and subject to the limitations and restrictions contained therein, 80%-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.

Legal Proceedings

In August 2003, Ormesa LLC agreed to enter into binding arbitration with the Imperial Irrigation District, which we refer to as IID, in connection with IID's claim that Ormesa LLC is obligated to pay scheduling and transmission charges (including those applicable to the GEM 2 and GEM 3 plants) through the effective date of relinquishment of nominated capacity for the GEM 2 and GEM 3 plants. The amount in dispute is $529,000. Ormesa LLC contends that it is not obligated to pay the subject charges for the GEM 2 and GEM 3 plants after the January 1, 2003 effective date of the Energy Services Agreement that Ormesa LLC entered into with the IID. Settlement discussions are in progress. We believe that the dispute will be resolved in 2004 and that any outcome will not have a material impact on our operations or relationship with the IID.

As a result of our acquisition of the Steamboat 1 plant and Steamboat 1A plant, 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 1/1A project. The plaintiffs dispute amounts owing to them pursuant to an agreement, dated July 14, 1985, through 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 allege damages based upon three separate theories: (1) that the actions of the former owner in developing the Steamboat 1A plant have decreased the output of the Steamboat 1 plant; (2) 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 (3) 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. This case was originally set for trial in September 2003, but the trial date was continued in order to allow the plaintiffs to obtain substitute counsel. Prior to the continuance of the trial date, initial evidentiary disclosures had been made, as well as some initial discovery requests. No dispositive motions are pending before the court and the trial date has not been rescheduled. We have initiated settlement discussions with the plaintiffs. As part of such discussions, we received a letter from the plaintiffs in which they assert that, in addition to the amounts they claim are owed to them, they are also entitled to a reasonable net operating royalty from our Galena project. We believe such assertion is without merit and believe that any outcome of such litigation or settlement discussions will not have a material impact on our results of operations. We estimate that the aggregate amount of all claims subject to such litigation will not exceed $1 million.

From time to time, we (and 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 and cash flows.

Regulation of the Electric Utility Industry in the United States

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

PURPA

PURPA, in relevant part, exempts renewable electric generating projects that are "Qualifying Facilities" from various regulations under the FPA. There are two types of Qualifying Facilities: "Qualifying Small Power Production Facilities" and "Qualifying Cogeneration Facilities." Under PURPA and the regulations promulgated thereunder, a power production facility is a "Qualifying Small Power Production Facility" if (1) the facility produces no more than 80 MW (on a net capacity basis) or satisfies certain FERC certification and construction dates, (2) the primary energy source of the facility is biomass, waste, renewable resources, geothermal resources or any combination thereof, and at least 75% of the total energy input is from these sources, and (3) the facility is owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from cogeneration facilities or small power production facilities) (i.e., the project company cannot be controlled by, more than 50% of the equity interests of the facility may not be owned by, and more than 50% of the equity benefits cannot be received by an electric utility, an electric utility holding company or a combination thereof or their subsidiaries).

Under PURPA, Qualifying Facilities receive two primary benefits. First, PURPA exempts Qualifying Facilities, such as our domestic projects (other than the Puna project), from the definition

of "electric utility company" under PUHCA, most provisions of the FPA and state laws and regulations relating to financial, organization and rate regulation of electric utilities. Second, the regulations promulgated by FERC under PURPA require, in relevant part, that electric utilities (1) purchase energy and capacity made available by Qualifying Facilities, construction of which commenced on or after November 9, 1978, at a rate based on the purchasing utility's full "avoided costs" and (2) sell supplementary, back-up, maintenance and interruptible power to Qualifying Facilities on a just and reasonable and nondiscriminatory basis. FERC's regulations define "avoided costs" as the "incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source." Utilities may also purchase power at prices other than avoided cost pursuant to negotiations as provided by FERC's regulations. Under an amendment to PURPA and PURPA regulations, FERC has also provided that utility geothermal small power production facilities (that is, geothermal small power production facilities that would be Qualifying Facilities except that they are owned by a person primarily engaged in the generation or sale of electric energy) are exempt from PUHCA but not state regulation or, if applicable, the FPA.

We expect that our domestic projects will continue to meet all of the criteria required for Qualifying Facilities under PURPA. If any of our domestic projects in which we have an interest loses its Qualifying Facility status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded Qualifying Facilities, our operations could be adversely affected. Loss of Qualifying Facility status for one of our domestic projects for having more than 50% utility ownership would make that facility a utility geothermal small power production facility. Such facilities are exempt from PUHCA but are subject to state regulation and, if applicable, the FPA. Loss of Qualifying Facility status for any other reason would also make the facility subject to state regulation and, if applicable, the FPA. In addition, loss of Qualifying Facility status for any reason other than utility ownership would make the facility subject to PUHCA unless it has EWG status or falls within another exemption. If a facility lost Qualifying Facility status for any reason other than utility ownership and was ineligible for EWG status because it made retail sales, we would face the choice between discontinuing the retail sales and filing for EWG status or becoming subject to PUHCA. At present, none of our domestic projects makes retail sales of electricity (other than to affiliates). In the unlikely event that we become a public utility holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants lost its Qualifying Facility status (assuming that that plant was neither an EWG nor a utility geothermal small power production facility), our other domestic projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the Qualifying Facility ownership requirements. This could cause all of our projects to become subject to federal and state energy regulations. In addition, a loss of Qualifying Facility status could allow 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 contract revenues, result in significant liability for refunds of past amounts paid, or otherwise impair the value of a project. 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 refund payment. In addition, such a loss of 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.

In 2003, Congress proposed legislation that, among other provisions, would have had the practical effect of repealing PUHCA and shifting regulatory oversight of holding companies to FERC, and of repealing the mandatory purchase requirements of PURPA. Although the 2003 legislation would not affect existing power purchase agreements for Qualifying Facilities, such legislation or other legislation could (1) repeal or amend PURPA in a manner that substantially reduces the benefits currently afforded Qualifying Facilities, or (2) otherwise make more burdensome the requirements for the projects to maintain their status as Qualifying Facilities. In such event, operations at the projects or

compliance with the terms of the power purchase agreements could be adversely affected, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.

PUHCA

PUHCA, in relevant part, provides that any corporation, partnership or other entity or organized group that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public utility company" (which is defined to include an "electric utility company" or a "gas utility company"), or of a company that is a "holding company" of a public utility company or public utility holding company, is subject to registration with the Securities and Exchange Commission and to regulation under PUHCA, unless exempted by a Securities and Exchange Commission rule, regulation or order. An entity may also be deemed to be a holding company if the Securities and Exchange Commission determines, after providing notice and an opportunity for a hearing, that such entity exercises a controlling influence over the management or policies of any public utility or holding company as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that such entity be regulated as a holding company. Unless an exemption is obtained, PUHCA requires registration for a holding company of a public utility company and requires a public utility holding company to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. In addition, a public utility company that is a subsidiary of a registered holding company under PUHCA is subject to financial and organizational regulation, including approval by the Securities and Exchange Commission (SEC) of its financing transactions.

Under current federal law, we are not subject to regulation as a holding company under PUHCA and will not be subject to such regulation as long as the plants in which we have an interest are (1) Qualifying Facilities, (2) "Exempt Wholesale Generators" (as defined in PUHCA) or (3) subject to another exemption or waiver, such as status as an electric utility geothermal small power production facility.

FPA

Under the FPA, 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 through competitive bidding or negotiation. If a project were to lose its Qualifying Facility status, the rates set forth in its power purchase agreement would have to be filed with FERC and would be subject to review by FERC under the FPA, unless the project is located in Hawaii, Alaska or the parts of Texas that are not deemed to be interstate commerce, in which case state regulations would apply. Under FERC policy, the rates under those circumstances could be no higher than the rate or price the relevant power purchaser would have paid for energy had it not been required to purchase from such project under PURPA's mandatory purchase requirements, i.e., such power purchaser's economy energy (incremental) cost during the period of non-compliance with Qualifying Facility requirements, unless the applicable power purchase agreement otherwise provides for alternative rates to apply in the event of such loss of Qualifying Facility status and FERC accepts such alternative rates.

State Regulation

Our projects in California and Nevada, by virtue of being Qualifying Facilities and because they engage in wholesale sales of electricity to public electric utilities in California and Nevada, are not subject to rate, financial and organizational regulations applicable to public electric utilities in those states. The projects each sell or will sell their electrical output to public electric utilities (either Sierra Pacific Power Company, Nevada Power Company or Southern California Edison Company) which are regulated by their respective state public utility commission. Sierra Pacific Power Company and Nevada Power Company are regulated by the Public Utility Commission of Nevada, which we refer to as NPUC. Southern California Edison Company and a small portion of Sierra Pacific Power Company

in the Lake Tahoe area are regulated by the California Public Utility Commission, which we refer to as CPUC. Since the NPUC and the CPUC regulate the retail rates through which the purchasing utilities recover their payments to our facilities from the retail electric customers of the public electric utilities under their jurisdiction, it is important for the purchasing electric utilities to obtain approval by their respective public utility commissions of their agreements with our projects. It is also important for the public electric utilities to be allowed continued recovery in their retail electric rates of the cost paid to our projects for electricity.

The NPUC has previously approved the agreements for each of our existing projects located in Nevada and has continuously allowed recovery of the costs of the electricity from those projects in the retail electric rates charged by Sierra Pacific Power Company. The NPUC, pursuant to a delegation of authority from FERC, also sets the avoided cost basis for updating the rates in several of our contracts. While we have no reason to believe that the NPUC will not continue to allow such recovery and continue to set the appropriate avoided cost rate, we cannot guarantee a specific avoided cost rate level or recovery in rates by the regulated public utility. The inability to recover the full cost of the electricity from our project by a public utility could adversely impact the ability of the public utility to pay for the electricity from a project, but such adverse treatment is unlikely given the pre-approval of the agreements. Further, we believe that federal law requires the state commissions to permit full recovery of PURPA-based wholesale rates by the purchasing utility, but we are aware of no judicial decisions in California, Nevada, or Hawaii upholding this principle.

Under Hawaii law, non-fossil generators are not 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 full avoided cost.

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.    Two recently approved laws, Law No. 272-98 and Law No. 271-98, define the structure of the new energy sector in Nicaragua. Law No. 272-98 provides for the establishment of a National Energy Commission, which we refer to as CNE, that 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. The Nicaraguan government currently owns all of the commercial activities in the energy sector through Empresa Nacional de Electricidad (ENEL), a vertically integrated utility. The Nicaraguan energy sector has recently 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, which will be 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 and is currently scheduled to be privatized. In addition, a National Dispatch Center was created to work with ENTRESA and provide for dispatch and wholesale market administration.

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 (AMM), 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 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 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. The Kenya Power & Lighting Co. Ltd. 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 Kenya Power & Lighting Co. Ltd., which is owned by various private and government entities and which purchases energy and capacity from three 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. Kenya Power & Lighting Co. Ltd.'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 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.

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 fines or penalties, however, the Heber 1 and Heber 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 and the Colorado River Basin Region has notified the Heber 1 and Heber 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 permit. In order to address the pressure levels at the Heber 1 and Heber 2 projects, the Heber 1 and Heber 2 projects have 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. With the cooperation of the California Regional Water Quality Control Board, Colorado River Basin Region, the Heber 1 and Heber 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 Heber 2 projects may instead inject the cooling tower blowdown water into the geothermal injection reservoir, as do other geothermal projects in the Imperial Valley.

As of the date of this prospectus, all of the material permits and approvals required to construct or 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 must be transferred or reissued to the correct entity. We believe such transfer and reissuance will occur in the ordinary course.

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 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 may have impacted 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.

Properties

We lease our corporate offices at 980 Greg Street, Sparks, Nevada 89431. 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 plants is located on property that we lease or own, or property that is subject to a concession agreement. See "—Our Projects" above.

MANAGEMENT

The following table sets forth the name, age and positions of our directors, executive officers, persons who are executive officers of certain of our subsidiaries who perform policy making functions for us, and our significant employees:

Name				Age				Position
Lucien Bronicki					70			Chairman of the Board of Directors; Chief Technology Officer(3)
Yehudit "Dita" Bronicki					62			Chief Executive Officer; President; Director(2)
Yoram Bronicki					37			Chief Operating Officer—North America; Director Nominee†(1)
Lisa Kidron					40			Chief Financial Officer, Ormat Systems*
Nadav Amir					54			Executive Vice President—Engineering, Ormat Systems*
Hezy Ram					54			Executive Vice President—Business Development, Ormat Nevada**
Joseph Shiloah					5859			Executive Vice President—Marketing and Sales, Ormat Systems*
Zvi Reiss					53			Executive Vice President—Project Management, Ormat Systems*
Aaron Choresh					5859			Vice President—Operations and Product Support, Ormat Systems*
Zvi Krieger					49			Vice President—Geothermal Engineering, Ormat Systems*
Etty Rosner					49			Vice President—Contract Administrator; Corporate Secretary*
Connie Stechman					48			Vice President—Controller; Director††
Independent Director Nominees:
Dan Falk					59			Independent Director Nominee†(3)
Edward R. Muller					52			Independent Director Nominee†(1)
Jacob J. Worenklein					56			Independent Director Nominee†(2)
Significant Employees:
Shimon Hatzir					43			Vice President—Electrical and Conceptual Engineering, Ormat Systems*
Ran Raviv					3637			Vice President—Business Development, Ormat Nevada**
Daniel Schochet					73			Vice President, Market Development**
Ohad Zimron					4950			Vice President—Product Engineering, Ormat Systems*
Uzi Albert					52			Manager—Logistics and Production, Ormat Systems*

*	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.

†	This nominee will be appointed prior to the completion of this offering.

††	Ms. Stechman will be stepping down from the board, effective upon the effective date of the registration statement.

(1)	Denotes Class I Director

(2)	Denotes Class II Director.

(3)	Denotes Class III Director.

Lucien Bronicki.    Lucien Bronicki is the Chairman of our board of directors, a position he has held since our inception in 1994, and is also our Chief Technology Officer, effective as of July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the board of directors of Ormat Industries, the publicly-traded successor to Ormat Turbines Ltd., and various of its subsidiaries. Since 1992, Mr. Bronicki has also been the Chairman of the board of directors of Bet

Shemesh Engines, a manufacturer of jet engines, and of OPTI Canada Inc. Mr. Bronicki is also the Chairman of the board of directors of Orad Hi-Tec Systems Ltd., a manufacturer of image processing systems, 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 chairs 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 in 1958 and a Master of Science in Physics from Universite de Paris in 1958 and a Master of Science in Mechanical Engineering from Ecole Nationale Superieure d'Ingenieurs Arts et Metiers in 1957.

Yehudit "Dita" Bronicki.    Yehudit "Dita" Bronicki is our Chief Executive Officer, effective as of July 1, 2004, and is also a member of our board of directors and our President, positions she has held since our inception in 1994, and was our Secretary from 1994 through October 2004. Mrs. Bronicki is also the President of Ormat Systems, effective as of 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, the publicly-traded successor to Ormat Turbines Ltd., and various of its subsidiaries. Since 1992, Mrs. Bronicki has also been a director of Bet Shemesh Engines. Mrs. Bronicki is also a member of the board of directors of OPTI Canada Inc., and 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.    Yoram Bronicki is our Chief Operating Officer, effective as of July 1, 2004. Mr. Bronicki is also a member of the board of directors of Ormat Industries, a position he has held since 2001. Mr. Bronicki will be appointed a director of Ormat Technologies prior to the completion of this offering. From 2001 to 2004, Mr. Bronicki was Vice President of OPTI Canada Inc., from 1999 to 2001, he was Project Manager of Ormat Industries and Ormat International, from 1996 to 1999, he was Project Manager of Ormat Industries, and from 1995 to 1996, he was Project Engineer of Ormat Industries. 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.

Lisa Kidron.    Lisa Kidron performs the function of our Chief Financial Officer and is the Chief Financial Officer of Ormat Systems, effective as of July 1, 2004. Ms. Kidron is also the Chief Financial Officer of Ormat Industries, a position she has held since 2002. From 2000 to 2002, Ms. Kidron was Chief Financial Officer at MUL-T-LOCK Ltd. and from 1999 to 2000, Ms. Kidron was Chief Financial Officer at MUL-T-LOCK Technologies Ltd. Ms. Kidron served as a director on the boards of various subsidiaries within the MUL-T-LOCK group from 1999 to 2002. Until 1999, Ms. Kidron was a senior manager in the accounting firm Kost-Forrer & Gabai (Ernst & Young, Global Services). Ms. Kidron obtained an L.L.M. Degree in Law from Bar-Ilan University in 2002, a Bachelor of Arts in Accounting from Tel Aviv University in 1994, a Master of Science in Industrial Engineering from Ben Gurion University in 1987 and a Bachelor of Science in Computer Science and Mathematics from Rutgers University in 1985.

Nadav Amir.    Nadav Amir performs the function of our Executive Vice President of Engineering, and is the Executive Vice President of Engineering of Ormat Systems, effective as of 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, from 1988 to 1993, he was Manager of Engineering of Ormat Industries, from 1984 to 1988, he was Manager of Product Engineering of Ormat Industries, 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.

Hezy Ram.    Hezy Ram performs the function of our Executive Vice President of Business Development, and is the Executive Vice President of Ormat Nevada, a position he has held since

January 1, 2004. From 1999 through December 31, 2003, Mr. Ram was Executive Vice President of Business Development of Ormat Industries. Mr. Ram obtained a 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.

Joseph Shiloah.    Joseph Shiloah performs the function of our Executive Vice President of Marketing and Sales, and is the Executive Vice President of Marketing and Sales of Ormat Systems, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Shiloah was the Executive Vice President of Marketing and Sales at Ormat Industries, from 1989 to 2000, he was Vice President of Marketing and Sales of Ormat Industries, 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.

Zvi Reiss.    Zvi Reiss performs the function of our Executive Vice President of Project Management, and is the Executive Vice President of Project Management of Ormat Systems, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Reiss was the Executive Vice President of Project Management of Ormat Industries, from 1995 to 2000, he was Vice President of Project Management of Ormat Industries and, from 1993 to 1994, he was Director of Projects of Ormat Industries. Mr. Reiss obtained a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.

Aaron Choresh.    Aaron Choresh performs the function of our Vice President of Operations and Product Support, and is the Vice President of Operations and Product Support of Ormat Systems, effective as of July 1, 2004, and will also serve in that capacity and provide services to us upon the completion of this offering. From 1999 through June 30, 2004, Mr. Choresh was the Vice President of Operations and Product Support of Ormat Industries, from 1993 to 1998, he was the Director of Operations and Product Support of Ormat Industries, 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. Mr. Choresh obtained a Bachelor of Science in Electrical Engineering from Technion Haifa in 1982.

Zvi Krieger.    Zvi Krieger performs the function of our Vice President of Geothermal Engineering, and is the Vice President of Geothermal Engineering of Ormat Systems, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Krieger was the Vice President of Geothermal Engineering of Ormat Industries. Mr. Krieger has been with Ormat Industries 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 performs the function of our Corporate Secretary, and is the Corporate Secretary of Ormat Systems, effective as of July 1, 2004. Ms. Rosner is also the Corporate Secretary of Ormat Industries, a position she has held since 1991, and Vice President of Contract Management of Ormat Industries, 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 will be a member of our board of directors until the effective date of the registration statement and is our Vice President and Controller, positions she has held since our inception in 1994. Prior to joining Ormat Technologies, 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 will be appointed as a director of Ormat Technologies prior to the completion of the offering. Mr. Falk is also a member of the Board of Directors of Ormat Industries

Ltd., Orbotech Ltd., Nice System Ltd., Attunity Ltd., ClickSoftware Technologies Ltd. and Jacada Ltd. From 2001 to 2004, Mr. Falk was a business consultant to several public and private companies. From 1999 to 2000, Mr. Falk was Chief Operating Officer and Chief Executive Officer of Sapiens International NV. From 1995 to 1999, Mr. Falk was an Executive Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbotech 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.

Edward R. Muller.    Edward Muller will be appointed a director of Ormat Technologies prior to the completion of this offering. Mr. Muller is also a member of the board of directors of GlobalSantaFe Corp. and The Keith Companies, Inc. Since 2000, Mr. Muller has been a private investor. From 1993 to 2000, Mr. Muller was President and Chief Executive Officer of Edison Mission Energy, the wholly owned subsidiary of Edison International. From 1991 to 1993, Mr. Muller was Vice President, Chief Financial Officer, General Counsel and Secretary of Whittaker Corp. and Vice President, General Counsel and Secretary of BioWhittaker, Inc. Mr. Muller obtained a Bachelor of Arts in History from Dartmouth College in 1973 and a Juris Doctor in Law from Yale Law School in 1976.

Jacob J. Worenklein.    Jacob Worenklein will be appointed a director of Ormat Technologies prior to the completion of this offering. Mr. Worenklein is also president and Chief Executive Officer of US Power Generating Company. 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.

Shimon Hatzir.    Shimon Hatzir performs the function of our Vice President of Electrical and Conceptual Engineering, and is the Vice President of Electrical and Conceptual Engineering of Ormat Systems, effective as of July 1, 2004. From 2002 through June 30, 2004, Mr. Hatzir was the Vice President of Electrical and Conceptual Engineering of Ormat Industries, from 1996 to 2001, he was Manager of Electrical and Conceptual Engineering of Ormat Industries, and from 1989 to 1995, he was Project Engineer in the Engineering Division. Mr. Hatzir obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1988 and a Certificate of the Technology Institute of Management, Senior Executive Program.

Ran Raviv.    Ran Raviv performs the function of our Vice President of Business Development, and is the Vice President of Business Development of Ormat Nevada, a position he has held since 2001. From 1997 to 2001, Mr. Raviv was Manager of Business Development of Ormat Industries, and from 1994 to 1997, he was a business manager at Green Land Ltd., a subsidiary of Browning Ferris Inc. of Houston, Texas. In 1993, Mr. Raviv was a management consultant at Global Present Ltd. Mr. Raviv obtained a Bachelor of Science in Computer Science and Business Studies from the University of Buckingham in 1992 and a Master of Business Administration from City University Business School in 1993.

Daniel Schochet.    Daniel Schochet performs the function of our Vice President of Market Development, and is the Vice President of Market Development of Ormat Nevada, a position he has held since September 1, 1992. From 1987 to 1992, Mr. Schochet was Vice President of Geothermal Project Development of OESI, Inc., from 1984 to 1987, he was Vice President and General Manager of Ormat, Inc.'s geothermal operations in the United States, from 1980 to 1984, he was Director of

International Marketing of Ormat Systems, and from 1975 to 1979, he was Managing Director of Ormat's subsidiary in Iran. Prior to joining Ormat, Mr. Schochet held a number of technical and management positions in the aerospace, electrical power and biomedical research industries. Mr. Schochet is a Member of the Board of Directors of the Geothermal Energy Association and the Geothermal Resources Council and has served as co-chairman of the U.S. Department of Energy's Geo-Powering the West Peer Review Committee. Mr. Schochet received a Master of Science in Electrical Engineering from Columbia University School of Engineering in 1958 and a Bachelor of Electrical Engineering from the Cooper Union School of Engineering in 1953.

Ohad Zimron.    Ohad Zimron performs the function of our Vice President of Product Engineering, and is the Vice President of Product Engineering of Ormat Systems, effective as of July 1, 2004. From 1999 through June 30, 2004, Mr. Zimron was the Vice President of Product Engineering of Ormat Industries, from 1992 to 1999, he was Manager of Product Engineering of Ormat Industries, from 1986 to 1992 he was Product Engineer of Ormat Industries, from 1984 to 1986, he was Product Support Manager of Ormat Systems Inc. and from 1981 to 1984, he was Product Engineer of Ormat Turbines Ltd. Mr. Zimron obtained a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1979 and a Master of Business Administration from Bar Ilan University in 2002.

Uzi Albert.    Uzi Albert performs the function of our Manager of Logistics and Production, and is the Manager of Logistics and Production of Ormat Systems, effective as of July 1, 2004. From 1998 through June 30, 2004, Mr. Albert was the Manager of Logistics and Production of Ormat Industries. Mr. Albert obtained a Diploma of Business Administration from Tel Aviv University in 1991.

Security Ownership of Certain Beneficial Owners and Management

We are a wholly owned subsidiary of Ormat Industries. Ormat Industries is an Israeli company that is publicly traded on the Tel Aviv Stock Exchange. Based on publicly available information, Lucien Bronicki, the Chairman of our board of directors, Yehudit Bronicki, our Chief Executive Officer, Yoram Bronicki, our Chief Operating Officer, and their family beneficially own approximately 35.15%, as of June 30, 2004, of the outstanding ordinary shares of Ormat Industries.

Board Composition

Our board of directors is currently composed of three members. Effective upon the effective date of the registration statement of which this prospectus forms a part, the number of directors on our board of directors will be increased to a total of six members, including three independent directors, Dani Falk, Edward Muller and Jacob Worenklein. Also, on the effective date, our board of directors will be classified into three classes of directors serving staggered, three-year terms as indicated:

Class I Directors (term expiring upon the annual shareholders meeting in 2005)
Yoram Bronicki
Edward R. Muller

Class II Directors (term expiring upon the annual shareholders meeting in 2006)
Yehudit Bronicki
Jacob J. Worenklein

Class III Directors (term expiring upon the annual shareholders meeting in 2007)
Lucien Bronicki
Dan Falk

In addition, in order to ensure compliance with the independence requirements of the New York Stock Exchange, the composition of the board of directors may change prior to and following the offering. It is our intention to be in full and timely compliance with all applicable rules of the New York Stock Exchange and applicable laws, including with respect to the independence of our directors. We intend to rely on the "controlled company" exception to the board of directors and committee composition requirements under the rules of the New York Stock Exchange. The "controlled company" exception does not modify the independence requirements for the audit committee, and we intend to comply with the requirements of the Sarbanes-Oxley Act of 2002 and the New York Stock Exchange rules which require that our audit committee be composed of at least three independent directors.

Board Committees

Our board of directors has the authority to appoint committees to perform certain management and administration functions. Our board of directors currently intends to establish an audit committee, a compensation committee and a nominating and corporate governance committee, effective upon completion of this offering.

Audit Committee.    The audit committee will select, on behalf of our board of directors, an independent public accounting firm to be engaged to audit our financial statements, discuss with the independent auditors their independence, review and discuss the audited financial statements with the independent auditors and management and review our compliance with legal and regulatory requirements with respect to accounting policies, internal controls and financial reporting. The audit committee will consist of three or more members, all of whom will be independent directors. We intend to appoint Dan Falk, Jacob Worenklein and Edward Muller to the audit committee, and to appoint Dan Falk as the chair of the audit committee. Dan Falk qualifies as a financial expert under the rules of the SEC.

Compensation Committee.    The compensation committee will review and either approve, on behalf of our board of directors, or recommend to the board of directors for approval (1) the annual salaries and other compensation of our chief executive officer and certain other executive officers and (2) individual stock and stock option grants. The compensation committee also provides recommendations with respect to our compensation policies and practices and incentive compensation plans and equity plans. The compensation committee will consist of three or more members, of which at least two will be independent directors. We intend to appoint Yehudit Bronicki, Jacob Worenklein and Dan Falk to the compensation committee and to appoint Yehudit Bronicki as the chair of the compensation committee.

Nominating and Corporate Governance Committee.    The nominating and corporate governance committee will assist our board of directors in fulfilling its responsibilities by identifying and approving individuals qualified to serve as members of our board of directors, selecting director nominees for our annual meetings of stockholders, and developing and recommending to our board of directors corporate governance guidelines and oversight with respect to corporate governance and ethical conduct. The nominating and corporate governance committee will consist of three or more directors, of which at least one will be an independent director. We intend to appoint Lucien Bronicki, Dan Falk and Edward Muller to the nominating and corporate governance committee, and to appoint Lucien Bronicki as the chair of the nominating and corporate governance committee.

Compensation Committee Interlocks and Insider Participation

Prior to the completion of this offering, we have not had a compensation committee. Lucien Bronicki, Yehudit Bronicki and Connie Stechman served as the Chairman of our board of directors, President and Controller, respectively, during 2003. Lucien Bronicki and Yehudit Bronicki also held such positions in our parent and all of our subsidiaries and Connie Stechman also held such positions in a number of our subsidiaries during fiscal year 2003. See "Certain Relationships and Related Transactions."

Compensation of Directors

After consummation of this offering, we intend to pay each of our non-employee directors an annual retainer of $25,000 as fees related to their service on our board of directors and an additional board and committee meeting fee of $500 to $2,500 for each meeting they participate in. Any non-employee director who also serves as chairman of the audit committee will receive an annual retainer of $7,500. The non-employee directors shall also receive options to purchase 7,500 shares of our common stock at the public offering price, and 5,000 shares of our common stock at the market price on the relevant grant date on an annual basis from the second year of service.

We intend to promptly reimburse all directors for reasonable expenses incurred to attend meetings of our board of directors or committees.

Executive Compensation

The following table sets forth all compensation received during the year ended December 31, 2003, 2002 and 2001 by our named executive officers. The compensation described in this table does not include medical, group life insurance, or other benefits which are available generally to all of our salaried employees.

Summary Compensation Table

Name and Principal Position(s)				Year				Salary ($)(1)				Bonus ($)(2)				Other Annual Compensation ($)				Securities Underlying Options (#)(3)				All Other Compensation ($)(4)
Yehudit Bronicki					2003				45,518				—				—				—				—
Chief Executive Officer					2002				—				—				—				—				—
					2001				—				—				—				—				—
Nadav Amir					2003				—				—				—				—				—
Executive Vice President					2002				—				—				—				—				—
—Engineering					2001				—				—				—				—				—
Hezy Ram					2003				—				—				—				—				—
Executive Vice President					2002				—				—				—				—				—
—Business Development					2001				—				—				—				—				—
Zvi Reiss					2003				—				—				—				—				—
Executive Vice President					2002				—				—				—				—				—
—Project Management					2001				—				—				—				—				—
Aaron Choresh					2003				—				—				—				—				—
Vice President					2002				—				—				—				—				—
—Operations and Product Support					2001				—				—				—				—				—

                                                                          

(1)

In 2003, 2002 and 2001, in addition to these amounts, Mrs. Bronicki received $58,438, $100,206 and $110,794, respectively, as salary compensation from Ormat Industries; and in 2003, 2002 and 2001, Mr. Amir received $169,820, $156,016 and $166,004, respectively, Mr. Ram received $145,495, $110,593 and $127,951, respectively, Mr. Choresh received $115,819, $110,185 and $95,688, respectively, and Mr. Reiss received $135,441, $124,970 and $132,993, respectively, as salary compensation from Ormat Industries.

(2)	In 2002, Mr. Amir earned $101,492, as bonus compensation from Ormat Industries; in 2003, 2002 and 2001, Mr. Ram earned $333,242, $128,739 and $118,516, respectively, and Mr. Choresh earned $22,161, $19,543 and $16,592, respectively, as bonus compensation from Ormat Industries.

(3)

In 2003, 2002 and 2001, Mr. Amir received options to purchase 33,000, 33,000 and 33,000 shares of Ormat Industries' common stock, respectively, Mr. Ram received options to purchase 33,000, 33,000 and 33,000 shares of Ormat Industries' common stock, respectively, Mr. Reiss received options to purchase 33,000, 33,000 and 33,000 shares of Ormat Industries' common stock, respectively, and Mr. Choresh received options to purchase 22,500, 20,000 and 20,000 shares of Ormat Industries' common stock, respectively.

(4)

In 2003, 2002 and 2001, Mrs. Bronicki received $7,872, $7,271 and $8,000, respectively, Mr. Amir received $6,017, $5,561 and $5,987, respectively, Mr. Ram received $3,996, $3,693 and $3,316, respectively, Mr. Reiss received $3,996, $3,693 and $3,757, respectively, and Mr. Choresh received $3,996, $3,693 and $3,757, respectively, from Ormat Industries reflecting the private use of company-leased cars.

Stock Option Plan

Our board of directors adopted the Ormat Technologies, Inc. 2004 Incentive Compensation Plan (which we refer to as the plan) in October 2004, which plan was subsequently adopted by our stockholders. The plan provides for the grant of the following types of awards (each an award): incentive stock options, within the meaning of Section 422 of the Internal Revenue Code of 1986, as

amended (which we refer to as the Code), non-qualified stock options, restricted stock, stock appreciation rights, stock units, performance awards, phantom stock, incentive bonuses and other possible related dividend equivalents to our employees, directors and independent contractors (whom we refer to as the eligible individuals). Incentive stock options may be granted to our employees only. A total of 1,250,000 shares of our common stock were reserved for issuance pursuant to the plan, all of which could be issued as options or as other forms of awards. We intend to grant options to purchase up to 200,000 shares of our common stock to our employees and options to purchase up to 30,000 shares of our common stock to our non-employee directors prior to the effective date of the registration statement. If there is a merger, consolidation, stock or other non-cash dividend, extraordinary cash dividend, split-up, spin-off, combination or exchange of shares, reorganization or recapitalization or change in capitalization, or any other similar corporate event, the administrator may make certain adjustments in the aggregate number and kind of shares of common stock subject to the plan and dividend equivalents.

If any shares of common stock that have been made subject to an award cease to be subject to the award, such shares of common stock will again be available for an award and will not be considered as having been previously made subject to an award. Any shares of common stock delivered upon exercise of an option in payment of all or part of the option, or delivered or withheld in satisfaction of withholding taxes with respect to an award, will be additional shares of common stock available for an award under the plan. After an award of phantom stock has been paid out, the shares of common stock underlying the award will again be available for an award and will not be considered as having been previously made subject to an award. Certain awards may also be payable in cash.

Administration of the Plan.    Our board of directors, or the compensation committee appointed by our board, will administer the plan. Awards intended to qualify as "performance based compensation" within the meaning of Section 162(m) of the Code to any of the Company's five most highly compensated executives will be granted by a grant committee, a sub-committee of the compensation committee that will consist of two or more "outside directors" within the meaning of Section 162(m) of the Code. The administrator has the power to determine the terms of the awards, including the exercise price, the number of shares subject to each award, the exercisability of the awards and the form of consideration payable upon exercise. Under the plan, the administrator may delegate to our Chief Executive Officer, or his or her delegate, the right to designate other eligible individuals (other than our Chief Executive Officer or his or her delegate) to receive awards and to determine the amount of any awards granted to such eligible individuals and the terms of such awards, except that performance awards to any of the Company's five most highly compensated officers will only be granted by the grant committee, in accordance with the requirements of Section 162(m) of the Code.

Options.    A stock option is the right to purchase shares of our common stock at a fixed exercise price for a fixed period of time. The administrator will determine the exercise price of options granted under our plan, which will be at least equal to the fair market value of our common stock on the date of grant. The aggregate fair market value, determined as of the date the option is granted, of the shares of our common stock for which any employee may be granted incentive stock options which are exercisable for the first time in any calendar year may not exceed $100,000. Stock options generally may not be exercised after ten years from the date of the grant thereof. At the relevant time of exercise, the option price must be paid in full in cash or if permitted in the award agreement in shares of our common stock with a fair market value on the date of exercise equal to the option price or in a combination of cash and shares of common stock whose fair market value on the date of exercise thereof together with such cash will equal the option price. After termination of any of our employees, directors or independent contractors, unless the administrator determines otherwise, an unvested option typically will be subject to forfeiture, and a vested option will be exercisable for the period of time stated in the option agreement. If termination is due to death or retirement, the option generally will remain exercisable for one year following such termination. In all other cases, the option generally will remain exercisable for three months. However, an option may never be exercised later than the expiration of its term.

Stock Appreciation Rights.    A stock appreciation right is the right to receive the appreciation in the fair market value of our common stock between the exercise date and the date of grant, for that number of shares of our common stock with respect to which the stock appreciation right is exercised. A stock appreciation right may be granted in conjunction with an option or alone. We may pay the appreciation in either cash, in shares of our common stock with equivalent value, or in some combination, as determined by the administrator. The administrator determines the exercise price of stock appreciation rights, the vesting schedule and other terms and conditions of stock appreciation rights; however, stock appreciation rights expire under the same rules that apply to stock options.

Restricted Stock.    Restricted stock awards are awards of shares of our common stock that vest in accordance with terms and conditions established by the administrator. The administrator may impose whatever conditions to vesting it determines to be appropriate. The administrator will determine the number of shares of restricted stock granted to any employee. Unless the administrator determines otherwise, shares that do not vest typically will be subject to forfeiture to the extent the vesting schedule and/or specified performance or other criteria have not be satisfied, or upon the termination of employee, director or independent contractor for any reason including death or retirement.

Stock Units.    Stock units are rights to receive shares of our common stock at a future date. The administrator determines the terms and conditions of stock units.

Phantom Stock.    Phantom stock are rights to receive an amount of cash equal to the fair market value of a share of our common stock at a specified date. The administrator determines the terms and conditions of phantom stock.

Incentive Bonuses.    Incentive bonuses are rights to receive cash or shares of our common stock. The administrator determines the terms and conditions of such incentive bonuses. The Board has determined that up to 20% of the annual profits available for distribution by the Company may, at any time from time to time, be distributed to the employees of the Company by way of cash incentive bonuses to employees, pursuant and subject to the provisions of the 2004 Plan and at the discretion of the board. In determining whether there are annual profits available for distribution as cash incentive bonuses, our board of directors will take into account our business plan and current and expected obligations, and no such distribution will be made that in the judgment of our board of directors would prevent the Company from meeting such business plan or obligations.

Any such distribution will only be made when, as and if approved by our board of directors out of funds legally available therefor. The actual amount and timing of any such distribution 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 such distribution, the board 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.

Performance Awards.    Performance awards are awards of options, stock appreciation rights, restricted stock, stock units, phantom stock, and incentive bonus awards that will result in a payment to a key employee only if performance goals established by the administrator are achieved, or if the awards otherwise vest. The administrator or its delegates or the grant committee will establish performance goals in its discretion, which, depending on the extent to which they are met, will determine the number and/or the value of performance units and performance shares to be paid out to key employees. The performance goals may be based upon the achievement of company-wide, divisional or individual goals (including continued service), applicable securities laws or other basis determined by the administrator. Under the plan, no person will receive, in any one fiscal year, grants of performance awards for more than 400,000 shares of our common stock for performance awards of options, stock appreciation rights, restricted stock, stock units and phantom stock. The maximum dollar amount of any performance award of incentive bonuses that may be paid to any key employee in any fiscal year may not exceed $10 million. Performance goals or awards to any of the Company's five most highly compensated executives will only be set or granted by the grant committee.

Dividend Equivalents.    Any award (other than options, stock appreciation rights and bonuses) under the plan may, in the discretion of the administrator, earn dividend equivalents.

Transferability of Awards.    Unless the administrator determines otherwise, no award or portion of an award will be transferable other than by will or by the laws of descent and distribution, except that an option and tandem stock appreciation right may be transferred pursuant to a domestic relations order or by gift to a family member of the holder to the extent permitted in the applicable award. A tandem stock appreciation right may never be transferred except to the transferee of the related option. Only the participant may exercise an award during his or her lifetime.

Amendment and Termination of the Plan.    The plan will automatically terminate in 2014, unless we terminate it earlier. In addition, our board of directors has the authority to amend, suspend or terminate our plan, provided that such amendment does not adversely affect any award previously granted under our plan, unless the board of directors determines that an amendment is desired or appropriate to comply with the requirements of Section 885 of the American Jobs Creation Act of 2004 (which we refer to as the AJCA).

New Legislation.    Congress has recently passed the AJCA andOn October 22, 2004, the President is expected to signsigned the legislation shortly. The legislationAJCA. This law affects the timing for recognition of income attributable to certain types of non-qualified deferred compensation. Our board of directors intends to amend the plan, to the extent such amendment is desirable or appropriate, to comply with the requirements of Section 885 of the AJCA.

Employment Agreements

We have entered into an executive employment agreement with Mrs. Yehudit Bronicki, as our Chief Executive Officer, effective as of July 1, 2004. Such employment agreement is for a four-year term expiring on June 30, 2008, unless terminated earlier pursuant to the terms of the agreement. Such employment agreement, when expired, will be automatically extended for an additional successive four-year term, unless terminated earlier by either us or Mrs. Bronicki pursuant to the terms of the agreement.

Such employment agreement provides for a monthly base salary of $12,500. Mrs. Bronicki is also entitled to a bonus and other benefits set forth in the agreement and a company automobile. Pursuant to the terms of the agreement, if we or Mrs. Bronicki terminate the agreement, by providing the other party with 180 days' written notice prior to the end of the respective term, Mrs. Bronicki will be entitled to her salary, bonus and other benefits for such 180-day period. In the event of such termination, Mrs. Bronicki is entitled to an assignment of her "executive manager's insurance policy" and monies accumulated under such policy, and a payment of the difference, if any, between the sums accumulated under such policy on account of her severance pay, and the amount of severance pay she is entitled to based on her last base salary multiplied by the number of years she has been employed by us or Ormat Industries.

Mrs. Bronicki is also entitled to change in control payments. If, within three years following the occurrence of a change in control, we terminate Mrs. Bronicki's employment or Mrs. Bronicki terminates her own employment for good reason, other than for disability or if, within 180 days following a change in control, Mrs. Bronicki terminates her employment agreement with 90 days' prior written notice, then we are required to pay her a lump sum equal to (1) her full unpaid and accrued base salary through the date of termination; plus (2) her monthly base salary at the time of the change of control including any increases therein multiplied by 24; plus (3) the average of the annual bonus paid to Mrs. Bronicki for the two years immediately preceding the change in control multiplied by two; plus (4) a portion of the annual bonus for the year in which the termination of employment occurs with the amount thereof multiplied by a fraction, the numerator of which is the number of days in the relevant year through the date of termination and the denominator of which is 365, and any unpaid annual bonus for any completed year. In addition, Mrs. Bronicki is also entitled to all employee health, accident, life insurance, disability and other employee welfare benefits for a two-year period following her last day worked, or until she obtains new employment, whichever is earlier.

Hezy Ram is currently employed by Ormat Nevada and serves as our Executive Vice President of Business Development pursuant to an employment agreement dated January 1, 2004, which expires on December 31, 2007. Mr. Ram's employment agreement provides for an annual base salary of $175,000.

Pursuant to the terms of Mr. Ram's employment agreement, in addition to his annual salary, Mr. Ram

is entitled to certain other benefits paid for by us, including, among other things, annual bonuses and medical and hospitalization insurance. Pursuant to the terms of Mr. Ram's employment agreement, if we terminate his employment without cause, Mr. Ram is entitled to receive his monthly salary for the following 90-day period. If Mr. Ram terminates his employment voluntarily, he is not entitled to receive any subsequent payments. Mr. Ram's employment agreement also contains a one-year non-competition and non-solicitation provision.

Nadav Amir is employed by Ormat Systems and serves as our Executive Vice President of Engineering, Aaron Choresh is employed by Ormat Systems and serves as our Vice President of Operations and Product Support and Zvi Reiss is employed by Ormat Systems and serves as our Executive Vice President of Project Management. Each of Messrs. Amir, Choresh and Reiss is party to an employment agreement with Ormat Systems that sets forth their respective terms of employment that are generally applicable to all of Ormat Systems' staff, covering matters such as vacation, health and other benefits. Under such employment agreements, any Ormat Systems employee may be terminated for any reason subject to 30 days' prior notice. However, termination for cause does not require any prior notice. An employee that is terminated for cause is not entitled to any subsequent payments.

The actual salary and other compensation arrangements of Messrs. Amir, Choresh, and Reiss are agreed separately with each employee. Mr. Amir is entitled to a base salary of approximately $173,750 and a guaranteed bonus for 2004 of approximately $44,440, Mr. Choresh is entitled to a base salary of approximately $115,600 and a guaranteed bonus for 2004 of approximately $35,500 and Mr. Reiss is entitled to a base salary of approximately $139,500 and a guaranteed bonus for 2004 of approximately $44,400. Each of these individuals is also covered by Ormat Systems' management insurance plan, to which Ormat Systems contributes a percentage of such individual's salary, and which covers any compensation that such individual may be entitled to receive upon termination. In addition, each of the individuals has the benefit of the use of a company-leased car.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Loan Agreement between Us and Ormat Industries

In 2003, we entered into a loan agreement with Ormat Industries, 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 $150,000,000. 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% percent in U.S. dollars, which represented a rate of 7.5% for the advances made during year 2003. All computations of interest shall be made by Ormat Industries on the basis of a year consisting of 360 days. As of June 30, 2004, the outstanding balance of the loan was approximately $143.2 million.

The loan agreement contains customary representations and warranties to Ormat Industries and also contains customary events of default and notice provisions.

The loan agreement is governed by, and interpreted and construed under, the laws of Israel.

We believe that the terms of the loan agreement are as beneficial to us as could be obtained from unaffiliated third parties.

Capital Note Issued to Ormat Industries

Pursuant to the terms of a capital note, as further 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 NIS 240.0 million. We can repay the loan in full or, upon demand by Ormat Industries, we will be required to repay the loan in full at any time after November 30, 2007. 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 million (using the exchange rate existing on the date of such note).

We believe that the terms of the capital note are as beneficial to us as could be obtained from unaffiliated third parties.

Guarantee Fee Agreement between Us and Ormat Industries

In 1999, we entered into a guarantee fee agreement with Ormat Industries, pursuant to which Ormat Industries agreed to issue certain standby letters of credit and guarantees on our behalf to certain of our customers, as well as guarantees with respect to our bank credit lines.

Such agreement establishes a fee, calculated quarterly, equal to 1% per annum of all amounts guaranteed or subject to an outstanding letter of credit during the relevant quarter. Such payment is due quarterly in arrears and is payable against the receipt of an invoice from Ormat Industries.

We believe that the terms of the guarantee fee agreement are as beneficial to us as could be obtained from unaffiliated third parties.

Reimbursement Agreement between Us and Ormat Industries

On July 15, 2004, we entered into a reimbursement agreement pursuant to which we agreed to reimburse Ormat Industries for any draws made on any standby letter of credit subject to the guarantee fee agreement, dated as of January 1, 1999, between us and Ormat Industries, and for any payments made under any guarantee provided by Ormat Industries subject to such guarantee fee agreement. Interest on any amounts owing pursuant to the reimbursement agreement is paid at a rate per annum equal to Ormat Industries' average effective cost of funds plus 0.3% in U.S. dollars. There are no amounts currently owing to Ormat Industries pursuant to the reimbursement agreement.

Asset Purchase Agreement between Us and Ormat Industries

Pursuant to an asset purchase agreement, effective as of July 1, 2004, Ormat Industries sold and assigned to our subsidiary, Ormat Systems, certain assets and liabilities related to Ormat Industries' geothermal power plants and power units business, which is described elsewhere in this prospectus as our products business. The parties agreed to use their best efforts to assign the contracts and liabilities related to this business to Ormat Systems within 12 months from July 15, 2004, and until then, their unassigned assets are to be held in trust by Ormat Industries for Ormat Systems. As part of this transaction, Ormat Industries agreed, for so long as it holds more than 50% of the voting interest in us, not to compete or engage in any business which is in the same field of the business acquired by Ormat Systems.

As total consideration for the purchase, Ormat Systems agreed to pay Ormat Industries the amount of $11.0 million, which consists of a cash payment and the assumption of an outstanding loan to Bank Continental and certain employment liabilities.

As part of this transaction, Ormat Systems also agreed to pay to Ormat Industries certain commissions ranging between 2.5% and 5.0% on revenues from sale orders entered into prior to July 1, 2004. The aggregate amount of such commissions is subject to receipt of payment from customers and is approximately $2.2 million.

The asset purchase agreement and the following sublease agreement, license agreement, service agreement and reimbursement agreement are agreements that set forth the terms and conditions of the sale and assignment by Ormat Industries' products business to Ormat Systems. We believe that, taken as a whole, the terms of these agreements, collectively, are reasonable and appropriately benefit the company.

Sublease between Us and Ormat Industries

Our subsidiary, Ormat Systems, has entered into a sublease with Ormat Industries for real estate leased by Ormat Industries from the Israeli Land Administration on which our production and manufacturing facilities are located. Such sublease is effective as of July 1, 2004 and the term of such sublease is four years and eleven months, which term may be extended for up to 25 years (which includes the initial term) provided certain consents are obtained from the Israeli Land Administration, if necessary, and if not, the sublease term will automatically be 25 years.

Pursuant to the sublease, Ormat Systems agreed to pay rent, in advance, on a monthly basis, equal to $52,250.00 (plus VAT) per month. Payment will be adjusted every year to reflect increases in the Israeli Consumer Price Index, but will in no event be lower than the rent paid during the previous year. Pursuant to the sublease, Ormat Systems has also agreed to pay taxes and other compulsory charges, to make other required payments, and to indemnify Ormat Industries for taxes (other than income taxes) imposed in connection with the subleased real estate.

Pursuant to the sublease, Ormat Systems agreed to certain other customary undertakings, including indemnification and insurance undertakings.

The sublease was executed in connection with the asset purchase agreement between Ormat Systems and Ormat Industries.

License Agreement between Us and Ormat Industries

On July 15, 2004, our subsidiary, Ormat Systems, entered into a patents and trademarks license agreement, effective as of July 1, 2004, pursuant to which Ormat Industries granted a world-wide royalty-free license to Ormat Systems (which is exclusive with respect to the patents and certain of the trademarks) to internally copy, use, and create derivatives of certain patents and trademarks. The license survives sales and/or transfers of the patents and trademarks and Ormat Systems owns the derivatives created from the licensed patents. The term of the license agreement continues until the patents or trademarks expire or are assigned to Ormat Systems (which are intended to be assigned, subject to tax and other considerations) and the agreement may be terminated if either party becomes insolvent.

The license agreement was executed in connection with the asset purchase agreement between Ormat Systems and Ormat Industries.

Service Agreement between Us and Ormat Industries

On July 15, 2004, our subsidiary, Ormat Systems, entered into a service agreement, effective as of July 1, 2004, pursuant to which Ormat Systems agreed to provide, as an independent contractor, certain corporate, financial, secretarial and administrative services to Ormat Industries. At the request of Ormat Industries, Ormat Systems may also provide certain engineering services.

Ormat Industries is required to pay $10,000 per month for all services (other than engineering services) rendered pursuant to such service agreement plus all out-of-pocket expenses of Ormat Systems. For engineering services, Ormat Industries is required to pay a fee equal to the cost of such services plus 10.0% and all out-of-pocket expenses of Ormat Systems. On each anniversary of such services agreement, such monthly fees are adjusted in accordance with the Israeli Consumer Price Index during the previous twelve-month period plus 10.0%.

The service agreement was executed in connection with the asset purchase agreement between Ormat Systems and Ormat Industries.

Registration Rights Agreement between Us and Ormat Industries

At or prior to the closing of this offering, we will enter into a registration rights agreement with Ormat Industries. Under this agreement, Ormat Industries may require us on one occasion to register our common stock for sale on Form S-1 under the Securities Act if we are not eligible to use Form S-3 under that Act. After we become eligible to use Form S-3, Ormat Industries may require us on unlimited occasions to register our common stock for sale on this form. In addition, we will be required to file a registration statement on Form S-3 to register for sale shares of our common stock that are or have been acquired by directors, officers and employees of Ormat Industries upon the exercise of options granted to them by Ormat Industries. Ormat Industries will also have an unlimited number of piggyback registration rights. This means that any time we register our common stock for sale, Ormat Industries may require us to include shares of our common stock held by it or its directors, officers and employees in that offering and sale, subject to certain allocation procedures set forth in the registration rights agreement. Ormat Industries will not be allowed to exercise any registration rights during the lock-up period.

We will also agree to pay all expenses that result from the registration of our common stock under the registration rights agreement, other than underwriting commissions for such shares and taxes. We have also agreed to indemnify Ormat Industries, its directors, officers and employees against liabilities that may result from their sale of our common stock, including Securities Act liabilities.

Employment Agreements

We have entered into an executive employment agreement with Mr. Lucien Bronicki, as our Chief Technology Officer, effective as of July 1, 2004. Such employment agreement is for a four-year term expiring on June 30, 2008, unless terminated earlier pursuant to the terms of the agreement. Such employment agreement, when expired, will be automatically extended for an additional successive four-year term, unless terminated earlier by either us or Mr. Lucien Bronicki pursuant to the terms of the agreement.

Such employment agreement provides for a monthly base salary of $10,333. Mr. Lucien Bronicki is also entitled to a bonus and other benefits set forth in the agreement and a company automobile. Pursuant to the terms of the agreement, if we or Mr. Lucien Bronicki terminate the agreement, by providing the other party with 180 days' written notice prior to the end of the respective term, Mr. Lucien Bronicki will be entitled to his salary, bonus and other benefits for such 180-day period. In the event of such termination, Mr. Lucien Bronicki is entitled to an assignment of his "executive manager's insurance policy" and monies accumulated under such policy, and payment of the difference, if any, between the sums accumulated under such policy on account of his severance pay, and the amount of severance pay he is entitled to based on his last base salary multiplied by the number of years he has been employed by us or Ormat Industries, as specified in the agreement.

Mr. Lucien Bronicki is also entitled to change in control payments. If, within three years following the occurrence of a change in control, we terminate Mr. Lucien Bronicki's employment or Mr. Lucien Bronicki terminates his own employment for good reason, other than for disability or if, within 180 days following a change in control, he terminates his employment agreement with 90 days' prior written notice, then we are required to pay him a lump sum equal to (1) his full unpaid and accrued base salary through the date of termination; plus (2) his monthly base salary at the time of the change of control including any increases therein multiplied by 24; plus (3) the average of the annual bonus paid to Mr. Lucien Bronicki for the two years immediately preceding the change in control multiplied by two; plus (4) a portion of the annual bonus for the year in which the termination of employment occurs with the amount thereof multiplied by a fraction, the numerator of which is the number of days in the relevant year through the date of termination and the denominator of which is 365, and any unpaid annual bonus for any completed year. In addition, Mr. Lucien Bronicki is also entitled to all employee health, accident, life insurance, disability and other employee welfare benefits for a two-year period following his last day worked, or until he obtains new employment, whichever is earlier.

We have also entered into an executive employment agreement with Yehudit Bronicki, as our Chief Executive Officer. For a description of the employment agreement of Yehudit Bronicki, see "Management—Employment Agreements."

We have also entered into an executive employment agreement with Mr. Yoram Bronicki, as our Chief Operating Officer, effective as of July 1, 2004. Such employment agreement is for a two-year term expiring on June 30, 2006, unless terminated earlier pursuant to the terms of the agreement. Such employment agreement, when terminated, will be automatically extended for additional successive two-year terms subject to conditions set forth in the agreement.

Such employment agreement with Mr. Yoram Bronicki provides for a monthly base salary of $14,000. Mr. Yoram Bronicki is also entitled to a bonus and other benefits set forth in the agreement. Pursuant to the terms of the agreement, if we terminate Mr. Yoram Bronicki's employment without cause, by providing him with a 120 days' written notice prior to the end of the respective term, Mr. Yoram Bronicki will be entitled to his salary, bonus and other benefits for the unexpired portion of the remaining term of his employment agreement, except that if such prior notice is given for a period less than 120 days prior to the termination of his employment agreement, such salary, bonus and other benefits will be paid for a period of 120 days after such notice is given. If Mr. Yoram Bronicki is terminated for cause, he will not be entitled to any salary, bonus or other benefits except for accrued but unpaid salary through the last day worked prior to such termination.

Mr. Yoram Bronicki is also entitled to change in control payments. If, within three years following the occurrence of a change in control, as defined in the agreement, we terminate Mr. Yoram Bronicki's employment or Mr. Yoram Bronicki terminates his own employment for good reason, other than for disability or if, within 180 days following a change in control, he terminates his employment agreement with 90 days' prior written notice then we are required to pay him a lump sum equal to (1) his full unpaid and accrued base salary through the date of termination; plus (2) his monthly base salary at the time of the change of control including any increases therein multiplied by 24; plus (3) the average of the annual bonus paid to Mr. Yoram Bronicki for the two years immediately preceding the change in control multiplied by two; plus (4) the amount of the annual contribution that would be made by us to his 401(k) plan assuming his maximum contribution under the plan, multiplied by two; plus (4) a portion of the annual bonus for the year in which the termination of employment occurs with the amount thereof multiplied by a fraction, the numerator of which is the number of days in the relevant year through the date of termination and the denominator of which is 365, and any unpaid annual bonus for any completed year. In addition, Mr. Yoram Bronicki is also entitled to all employee health, accident, life insurance, disability and other employee welfare benefits for a two-year period following his last day worked, or until he obtains new employment, whichever is earlier.

DESCRIPTION OF CERTAIN MATERIAL AGREEMENTS

The following is a description of the material terms of our material agreements relating to our projects:

Financing Agreements

Beal Bank Credit Agreement and Related Documents

On December 18, 2003, our subsidiary, OrCal Geothermal, Inc., entered into a credit agreement with Beal Bank, S.S.B. pursuant to which Beal Bank made a loan to OrCal Geothermal, Inc. in the amount of $154,500,000. The proceeds of this loan were used to fund a portion of the purchase price for the Heber 1 and Heber 2 projects and our 50% ownership interest in the Mammoth project. Such loan amortizes quarterly in amounts set forth in the credit agreement. The loan accrues at an interest rate determined on each anniversary date of the loan as the greater of 7.125%, which increases 0.50% starting December 2011, or the three-month LIBOR plus 5.125%, with the margin stepping up after a certain number of years. We have entered into cap transactions with Union Bank of California and Lehman Brothers Special Financing Inc. pursuant to which our effective interest rate is capped at 6% for the period between March 30, 2007 and March 31, 2011. The final maturity of the loan is December 18, 2019. As of June 30, 2004, the outstanding balance on the loan was $153.7 million.

Effective January 30, 2004, Beal Bank released its security interest over our partnership interest in the Mammoth project, which was subsequently included in the collateral package supporting the issuance by Ormat Funding of its 8¼% senior secured notes described below.

The loan is secured by liens over (1) all real and personal property comprising the Heber 1 project and the Heber 2 project, (2) the bank accounts into which revenues from these projects are required to be paid, and (3) all capital stock and partnership interests in OrCal Geothermal, Inc. and its subsidiaries, including the entities that own the Heber 1 project and the Heber 2 project.

The credit agreement and related documents contain various affirmative and negative covenants regarding the manner in which OrCal Geothermal, Inc. and its subsidiaries conduct their business, including their ownership, operation, and maintenance of the Heber 1 project and the Heber 2 project and the performance of their obligations and exercise of their rights under the project documents related to these projects. Such covenants include, but are not limited to, restrictions on the ability of OrCal Geothermal, Inc. and its subsidiaries (1) to take actions which would constitute or result in any material alteration to the nature of its business or the nature and scope of the Heber 1, Heber 2 and Mammoth projects, (2) to consolidate or merge, (3) to modify or amend its organizational documents, (4) to enter into certain leases, (5) to make certain investments, or (6) to incur any additional indebtedness. OrCal Geothermal, Inc. and its subsidiaries also may not expand their geothermal fields, develop new geothermal resources, or drill new geothermal wells without the lenders' consent. We are currently in compliance with all of the covenants set forth in the credit agreement and related documents. In addition, OrCal Geothermal, Inc. is prohibited from declaring dividends or making certain payments to holders of any share capital unless certain conditions are satisfied, including debt service coverage ratios and cash flow forecasts that do not demonstrate an inability to amortize the loan. The failure to perform or observe any such covenants, subject to various cure periods, will result in the occurrence of an event of default.

The credit agreement contains customary events of default, some of which are subject to cure periods and, in some instances, materiality thresholds. Such customary events of default include, but are not limited to (1) the failure to pay any principal or interest due pursuant to the credit agreement, (2) the bankruptcy or insolvency of OrCal Geothermal, Inc., (3) defaults under any of its other debt obligations over certain thresholds, (4) material final judgments against it, (5) the failure to perform or observe material covenants, (6) adverse regulatory events, (7) loss of collateral or (8) a change of control in its ownership. Upon the occurrence of any such event of default, the lenders under the credit agreement will be able to, among other things, accelerate the loan and enforce their liens on the collateral.

All project revenues from the Heber 1 project and the Heber 2 project are required to be deposited into a bank account over which Beal Bank has a lien. Amounts from time to time on deposit in this account are disbursed into other segregated accounts (over which Beal Bank has liens) available to pay or fund operating expenses of the Heber 1 project and the Heber 2 project, fees and expenses of the lenders and their agents, principal and interest on the loan, debt service reserve obligations, capital expenditure reserve obligations, and dividends. During the 2004 and 2005 calendar years, OrCal Geothermal, Inc. is required to use project revenues to establish and maintain a capital expenditures reserve in an amount equal to 50% of the capital expenditures reasonably anticipated to become due and payable during such years. We estimate the required amount of these reserves during these years to be between $4.2 million and $10.5 million. In subsequent calendar years, OrCal Geothermal, Inc. must use project revenues to maintain a capital expenditures reserve in an amount at any time that is equal to 100% of the capital expenditures reasonably anticipated to become due and payable during the next three months.

Senior Secured Notes and Related Documents

On February 13, 2004, our subsidiary Ormat Funding issued $190,000,000 of 8¼% senior secured notes due 2020 in an offering under Rule 144A and Regulation S of the U.S. Securities Act of 1933, as amended. The proceeds of the senior secured notes were used to finance the acquisition of the Steamboat 2/3 project, refinance the acquisition of the Brady project, the Steamboat 1/1A project and the Mammoth project, provide funds for the capital expenditures associated with the upgrade of the Steamboat 1/1A project and the Galena repowering, fund a reserve account to repay a loan from United Capital Bank (the proceeds of which were previously used to refinance the acquisition of the Ormesa project), repay a portion of a certain subordinated loan from Ormat Nevada, prepay a portion of the Meyberg lease, and pay transaction expenses associated with the issuance of such notes.

The notes have a final maturity date of December 30, 2020, unless redeemed earlier. Interest on the notes is payable in arrears on June 30 and December 30 of each year, beginning June 30, 2004. The principal of the notes amortizes over time in amounts set forth in the indenture.

The notes are secured by liens over (1) the capital stock of Ormat Funding and all of the capital stock held by Ormat Funding in each of the direct and indirect subsidiaries that own the Brady project, the Steamboat 1/1A project, the Steamboat 2/3 project, and the Mammoth project, (2) with certain exceptions for unassigned leases, all real property owned or leased by Ormat Funding and all of its direct and indirect subsidiaries that own the Brady, Steamboat 1/1A and Steamboat 2/3 projects, (3) all contractual rights under the agreements relating to the Brady, Steamboat 1/1A and Steamboat 2/3 projects (such as the power purchase agreements and all other relevant contracts) and all governmental approvals and permits relating to such projects; (4) all of Ormat Funding's revenues and all of the revenues derived from the Brady, Steamboat 1/1A and Steamboat 2/3 projects, including amounts received as distributions from the Ormesa and Mammoth projects, as well as all of Ormat Funding bank accounts and those of Ormat Funding direct and indirect subsidiaries that own the Brady, Steamboat 1/1A, Steamboat 2/3 and Mammoth projects; (5) any intercompany notes payable to Ormat Funding or any of the direct or indirect subsidiaries that own the Brady, Steamboat and Mammoth projects; (6) insurance policies covering the Brady, Steamboat 1/1A and Steamboat 2/3 projects and, to the extent of our interest therein, any insurance maintained with respect to the Mammoth project; and (7) guarantees from each of the direct and indirect subsidiaries that own the Brady, Steamboat 1/1A and Steamboat 2/3 projects.

Following the repayment of the United Capital Bank loan, which we expect will happen on or prior to January 31, 2005, or such other date as of which Ormesa LLC is no longer prohibited by the terms of the United Capital Bank loan to grant liens on its assets, Ormat Funding and Ormesa LLC are obligated to grant similar liens over similar items of collateral in favor of the indenture trustee and collateral agent for the senior secured notes.

Ormat Funding may redeem all or a portion of the senior secured notes at our option, at any time, at a redemption price equal to the principal amount of the senior secured notes to be redeemed, plus a "make-whole" premium, accrued interest and liquidated damages, if any, to the redemption

date. The make-whole premium is calculated using a discount rate equal to the interest on U.S. Treasury securities with a comparable maturity, plus 50 basis points. In no event can the sum of the redemption price for the notes being redeemed and the make-whole premium be less than 100% of the principal amount of senior secured notes to be redeemed.

Under certain circumstances, Ormat Funding must redeem a portion of the senior secured notes. If Ormat Funding has not satisfied the initial conditions with respect to the Galena re-powering, such as the execution of the Galena power purchase agreement, the execution of the interconnection and operating agreement for such project and the approval of the Public Utilities Commission of the State of Nevada and FERC, on or prior to September 30, 2005, or Ormat Funding fails to achieve certain levels of generating capacity from the Galena re-powering or from the Mammoth enhancement by March 31, 2006 or January 1, 2006, respectively, Ormat Funding will have to redeem the senior secured notes at a price equal to 101% together with accrued interest and liquidated damages, if any, to the redemption date, in an amount calculated in accordance with the indenture for the senior secured notes which cannot exceed, in the aggregate, $20.0 million. Upon receiving more than $5.0 million of insurance proceeds or the receipt of other amounts resulting from the occurrence of a compulsory transfer or the taking of a material part of the collateral or a project by any governmental authority or as a result of damage to a portion of the project and similar events described in the indenture for the senior secured notes, Ormat Funding will have to use any funds received in connection with such events to redeem the senior secured notes at a price equal to the principal amount of the notes scheduled to be redeemed plus accrued interest to the redemption date.

The indenture for the senior secured notes and related documents contains various affirmative and negative covenants regarding the manner in which Ormat Funding and its direct or indirect subsidiaries that own the Brady, Steamboat, Mammoth and, after the repayment of the United Capital Bank loan, Ormesa projects conduct their business, including their ownership, operation and maintenance of these projects and the performance of their obligations and exercise of their rights under the relevant project documents (such as the power purchase agreement and other relevant contracts) relating to such projects. In addition, Ormat Funding cannot make any dividend distribution to its immediate parent, Ormat Nevada, unless certain conditions are satisfied, including compliance with debt service coverage ratios and projected debt service coverage ratios that are at or above specified levels, and the absence of defaults and events of default under the indenture for the senior secured notes and related documents. We are currently in compliance with all of the covenants set forth in the senior secured notes and related documents.

The indenture for the senior secured notes contains customary events of default, some of which are subject to cure periods and, in some instances, materiality thresholds. Such customary events of default include, but are not limited to (1) the failure to pay any principal or interest due under the senior secured notes, (2) the bankruptcy or insolvency of Ormat Funding Corp. or any of its subsidiaries, (3) defaults with respect to any of its other debt obligations, (4) material final judgments against it, (5) the failure to perform or observe material covenants, or (6) a change of control with respect to its ownership, in which a party other than Ormat Nevada and its affiliates becomes, in certain circumstances, the beneficial owner of 50% or more of the economic and voting interests in Ormat Funding. Upon the occurrence of any such event of default, including any failure to perform or observe material covenants, the lenders under the credit agreement will be able to, among other things, accelerate the loan and enforce their liens on the collateral.

Under the depositary agreement for the senior secured notes, all revenues from the projects (other than the Ormesa project, which are not required to be deposited until the United Capital Bank loan is paid off) are required to be deposited into certain bank accounts established with a collateral agent and pledged as security for payment obligations under the senior secured notes. The principal accounts so established constitute a revenue account, operating account, debt service payment account and debt service reserve account. All revenues are required to be deposited initially in the revenue account, and are then transferred in a prescribed order to pay operating expenses, to pay principal and interest on the senior secured notes, to fund the debt service reserve account, and to fund certain other accounts.

The indenture for the senior secured notes authorizes Ormat Funding to issue an unlimited aggregate principal amount of senior secured notes, subject to compliance with certain financial and other conditions set forth in the indenture. Ormat Funding may decide to issue additional senior secured notes under the indenture in the future in connection with possible financing or refinancing of additional projects.

In connection with the issuance of the senior secured notes, Ormat Funding entered into a registration rights agreement, pursuant to which it (1) undertook to file a registration statement with the Securities and Exchange Commission and offer to exchange the senior secured notes for publicly registered notes with substantially identical terms and conditions to the senior secured notes and consummate the exchange offer within 330 days from February 13, 2004; and (2) undertook to file a shelf registration statement for the resale of senior secured notes if the exchange offer described in the foregoing clause could not be consummated within the time period prescribed in such agreement and in certain other circumstances. If Ormat Funding does not comply with these exchange or registration obligations, it will be required under certain circumstances to pay to holders of the senior secured notes liquidated damages until such obligations are satisfied.

Credit Facility Agreement (The Momotombo Project)

On September 15, 2000, our subsidiary Ormat Momotombo Power Company Ltd. entered into a credit facility agreement (as amended as of March 25, 2003) with Bank Hapoalim B.M. The loan, in an aggregate amount equal to $26,435,000, was made pursuant to two tranches, which are used to finance up to 70% of the costs of Phases I and II of the project. Tranche one of the loan bears interest at LIBOR plus 2.375%. Tranche two of the loan bears interest at LIBOR plus 3%. As of June 30, 2004, the outstanding balance on the loan was approximately $18.5 million. The first tranche of the loan is due by December 2009 and the final maturity of the second tranche of the loan is December 2010.

The loan is secured by liens over (1) all real and personal property comprising the Momotombo project, (2) all project revenues and the bank account into which they are required to be deposited, and (3) all of the equity interests in Ormat Momotombo Power Company Ltd.

Ormat Systems has also guaranteed the repayment of 50% of such outstanding obligations to Bank Hapoalim B.M. upon the occurrence of certain events.

Pursuant to the terms of the credit facility agreement, Ormat Momotombo Power Company Ltd. is required to repay all principal amounts disbursed under the credit facility agreement in approximately equal, successive quarterly installments.

Subject to the successful receipt of any required governmental approvals, Ormat Momotombo Power Company Ltd. may, at any time on at least 30 but not more than 60 days' prior written notice to Bank Hapoalim, prepay all or any part of the outstanding principal amount, without premium or penalty.

The credit facility agreement contains various affirmative and negative covenants regarding the manner in which Ormat Momotombo Power Company Ltd. conducts its business, including its ownership, operation and maintenance of the project and the performance of its obligations and exercise of its rights under the related project documents. Such covenants include, but are not limited to, restrictions on the ability of Ormat Momotombo Power Company Ltd. (1) to take actions which would constitute or result in any material alteration to the nature of its business or the nature and scope of the Momotombo project without Bank Hapoalim's prior written consent, (2) to consolidate, merge or consolidate its assets, (3) to modify or amend its organizational documents or its filings with the Nicaraguan Foreign Investment Committee, (4) to declare dividends or make certain payments to holders of any share capital, (5) to enter into certain leases (subject to certain exceptions contained in the credit facility agreement) or (6) to incur any additional indebtedness. Ormat Momotombo Power Company Ltd. must also maintain certain leverage and debt service coverage ratios under the terms of the credit facility agreement. We are currently in compliance with all of the covenants set forth in the credit facility agreement.

The credit facility agreement contains customary events of default, some of which are subject to cure periods and, in some instances, materiality thresholds. Such customary events of default include, but are not limited to (1) the failure to pay any principal or interest due under the credit facility agreement, (2) the bankruptcy or insolvency of Ormat Momotombo Power Company Ltd., (3) defaults with respect to any of its debt obligations or the default of ENEL under its agreements with Ormat Momotombo Power Company Ltd., (4) the termination of the Momotombo power purchase agreement, (5) the failure to perform or observe material covenants, (6) adverse regulatory events, (7) loss of collateral, or (8) the non-completion of the project within the budget or on time as established under the existing business plan. Upon the occurrence of any such event of default, including any failure to perform or observe material covenants, Bank Hapoalim B. M. will be able to accelerate all amounts due under the credit facility agreement and enforce its liens on the collateral.

Eximbank Credit Agreement (The Leyte Project)

On May 13, 1996, our subsidiary Ormat-Leyte Co. Ltd. entered into a credit agreement with the Export-Import Bank of the United States, an agency of the United States, pursuant to which the Export-Import Bank made a loan to Ormat-Leyte Co. Ltd. in the amount of $44,448,038. The credit was established as part of the overall debt financing for the construction of the Leyte project and the proceeds of the loan were used to repay in part certain short-term previous loans made by other lenders to the project owner. As of June 30, 2004, the outstanding balance on the loan was approximately $16.5 million. The final maturity of the loan is July 2007.

The loan is secured by liens over (1) all real and personal property comprising the Leyte project, (2) the bank accounts into which revenues from the project are required to be deposited and (3) all of the equity interests in Ormat-Leyte Co. Ltd.

Pursuant to the terms of the credit agreement, Ormat-Leyte Co. Ltd. is required to repay all principal amounts disbursed under the credit agreement in approximately equal, successive quarterly installments. Ormat-Leyte Co. Ltd. is required to pay interest at a rate equal to 6.54% per annum.

Subject to providing 10 business days' prior written notice, Ormat-Leyte Co. Ltd. may from time to time prepay all or any part of the outstanding principal amount of the loan, together with accrued interest and all other amounts due to Eximbank under the credit agreement and the related financing documents, and a prepayment premium, as provided for in the credit agreement.

The credit agreement contains various customary affirmative and negative covenants regarding the manner in which Ormat-Leyte Co. Ltd. conducts its business, including its ownership, operation and maintenance of the Leyte project and the performance of its obligations and exercise of its rights under the related project documents. We are currently in compliance with all of the covenants set forth in the credit agreement.

The credit agreement contains customary events of default, some of which are subject to cure periods and, in some instances, materiality thresholds. Such customary events of default include, but are not limited to (1) the failure to pay any principal or interest due under the credit agreement, (2) the bankruptcy or insolvency of Ormat-Leyte Co. Ltd., (3) defaults with respect to any of its other debt obligations, (4) the failure to perform or observe material covenants, (5) adverse regulatory events, (6) loss of collateral, or (7) a change of control with respect to its ownership. Upon the occurrence of any such event of default, including any failure to perform or observe material covenants, the Export-Import Bank under the credit agreement will be able to, among other things, accelerate the loan and enforce their liens on the collateral.

Project-Related Agreements

Power Purchase Agreements For Our Nevada Projects

Our existing projects in Nevada sell, and the Galena project will sell, their electrical output to Sierra Pacific Power Company under individual power purchase agreements for each project. The Desert Peak 2 and Desert Peak 3 projects will sell their electrical output to Nevada Power Company

under separate power purchase agreements. These agreements have different durations, but generally have similar terms and conditions, except as specifically noted below. We refer to our Nevada project, including our projects under development, construction or enhancement as, the Galena, Steamboat 1/1A, Steamboat 2/3, Steamboat Hills, Brady, Desert Peak 2 and Desert Peak 3 projects.

The power purchase agreements with Sierra Pacific Power Company (other than the Steamboat 1 and Galena power purchase agreements) generally provide that they may be terminated by Sierra Pacific Power Company prior to their respective expiry dates if our project subsidiaries fail to deliver energy for 180 consecutive days, so long as our project subsidiaries are not attempting to resume operations of the relevant project. In the case of the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements, early termination may occur if the required approval from the NPUC or FERC is not obtained or, in the case of the Galena power purchase agreement, after a force majeure event has occurred and continued for longer than six months (or twelve months if the force majeure event caused loss of a major component of the plant). In the case of the Steamboat 1 power purchase agreement, early termination may occur if there is a force majeure event.

Pursuant to the Steamboat 1 and Steamboat 1A power purchase agreements, our project subsidiaries are entitled to receive, on a monthly basis, energy payments equal to the short term avoided cost rates for energy in effect for the relevant billing period. Under the Brady power purchase agreement and the Steamboat 2 and Steamboat 3 power purchase agreements, our project subsidiaries are entitled to receive, on a monthly basis, energy and capacity payments. The energy payment escalates each year under the Steamboat 2, Steamboat 3 and the Brady power purchase agreements. The capacity payments under these power purchase agreements are subject to reduction if certain capacity availability percentages are not met. There is also a scheduled reduction in the capacity price that will occur in the future with respect to the Steamboat 2, Steamboat 3 and Brady power purchase agreements. In addition, under these power purchase agreements, Sierra Pacific Power Company may dispatch the Steamboat 2/3 and Brady projects up to a certain number of hours per year at a reduced energy rate.

Pursuant to the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements, our project subsidiaries are obligated to deliver energy on a continuous basis, along with dedicating all renewable energy credits and environmental credits, to Sierra Pacific Power Company. Our project subsidiaries receive an energy payment for all energy they deliver under such agreements, which payment escalates over time. In the event our project subsidiaries do not supply 95% of the amount of energy required during a certain period, they must compensate Sierra Pacific Power Company or Nevada Power Company for its replacement costs to purchase such shortfall amount from an alternate source. In addition, if our project subsidiaries do not transfer all of our renewable energy credits associated with the project to Sierra Pacific Company or Nevada Power Company, our project subsidiaries may have to compensate for Sierra Pacific Power Company's or Nevada Power Company's replacement cost to purchase such credits from alternate sources.

Our project subsidiaries are generally relieved from their obligations under the power purchase agreements to the extent they cannot wholly or partly perform such obligations as a result of the occurrence of a force majeure event. Generally, under these power purchase agreements, such relief is contingent upon our providing Sierra Pacific Power Company or Nevada Power Company with prompt notice of the suspension of our performance and our project subsidiaries attempting to remedy the inability to perform.

Pursuant to most of the power purchase agreements, including those of the Brady, Steamboat 1A, Steamboat 2, Steamboat 3, Steamboat Hills, Desert Peak 2 and Desert Peak 3 projects, the non-availability of the geothermal resource by itself is not a force majeure event. The Brady, Steamboat 2 and Steamboat 3 power purchase agreements provide that if the project does not maintain peak period capacity values of at least 85% of those listed in the contract, our relevant project subsidiary will be obligated to pay liquidated damages to Sierra Pacific Power Company in amounts ranging from $1.0 million to $1.5 million.

Pursuant to the Steamboat 1, Steamboat 1A, Steamboat 2, Steamboat 3, Steamboat Hills and Brady power purchase agreements, our project subsidiaries must indemnify Sierra Pacific Power

Company and Nevada Power Company from and against any and all loss and liability for personal injury, bodily injury or property damage, resulting from or arising out of (1) the engineering design, construction, maintenance, or operation of or (2) the making of replacements, additions or betterments to, our project subsidiaries' facilities. Pursuant to the Galena, Desert Peak 2, and Desert Peak 3 power purchase agreements, our project subsidiaries will indemnify Sierra Pacific Power Company for all losses arising out of our project subsidiary's breach of its obligations under the power purchase agreement, except that no party will be indemnified for any loss resulting from its gross negligence, fraud or willful misconduct.

Pursuant to the Steamboat Hills and Steamboat 1A power purchase agreements, our project subsidiaries must provide notice of the project's availability for sale to Sierra Pacific Power Company. Under the Steamboat 2, Steamboat 3, Brady, Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements, our project subsidiaries must provide Sierra Pacific Power Company or Nevada Power Company, as the case may be, with a right of first refusal for the acquisition of such projects.

Our project subsidiaries are generally required to coordinate scheduled maintenance on the plants with Sierra Pacific by providing a list of proposed maintenance operations certain months in advance. In the case of the Steamboat 1 power purchase agreement, our project subsidiary is obligated only to give notice to Sierra Pacific Power Company of scheduled maintenance outages. In the case of the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements, our project subsidiaries have an obligation to obtain Sierra Pacific Power Company's or Nevada Power Company's, as the case may be, consent for any non-forced outage and are limited to fifteen days per year for the Galena project and thirty days per year for the Desert Peak 2 and Desert Peak 3 projects.

Our project subsidiaries are required to obtain and maintain insurance coverage for our plants. Other than in the case of the Steamboat 1, Desert Peak 2, Desert Peak 3 and the Galena power purchase agreements, if our project subsidiaries fail to carry insurance, our project subsidiaries may not deliver capacity and energy to Sierra Pacific Power Company and Sierra Pacific Power Company has no obligation to accept or pay for any capacity or energy until appropriate insurance is obtained or reinstated. If any of our Desert Peak 2 or Desert Peak 3 project subsidiaries fails to maintain the requisite coverage, it must indemnify Nevada Power Company for liabilities that would have been protected against had our project subsidiary maintained such coverage.

Pursuant to the Desert Peak 2 and Desert Peak 3 power purchase agreements, our project subsidiaries are required to maintain minimum credit ratings of BBB by S&P or Baa2 by Moody's credit rating systems or to provide a letter of credit or cash in an escrow account, or provide a guarantee from an entity rated at least BBB by S&P or Baa2 by Moody's, in the amount of $1 million in the case of the Desert Peak 2 project and $0.5 million ($0.55 million if the output of the facility is increased) in the case of the Desert Peak 3 project as collateral in favor of Nevada Power Company. Pursuant to the Galena power purchase agreement, our project subsidiary is required to provide certain collateral as security in favor of Sierra Pacific Power Company.

Our project subsidiaries generally cannot assign the power purchase agreements without the prior written consent of Sierra Pacific Power Company or Nevada Power Company, as the case may be, although the power purchase agreements of all our project subsidiaries provide for collateral assignment for financing purposes without consent from Sierra Pacific Power Company or Nevada Power Company.

The Steamboat 1 power purchase agreement term continues until December 5, 2006 and is then automatically renewed each year unless terminated by either party; the Steamboat 1A power purchase agreement expires on December 14, 2018; the Steamboat 2 and Steamboat 3 power purchase agreements expire on December 19, 2022; the Steamboat Hills power purchase agreement expires in February, 2018; the Brady power purchase agreement expires in July 2022; and the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements expire twenty years from the first January 1 after the commercial operation date, which we currently expect to be the end of 2005, in the case of the Galena project, and early 2006 in the case of the Desert Peak 2 and Desert Peak 3 projects.

We have an aggregate of six power purchase agreements with respect to our Nevada projects. We derived $11.4 million of pro forma revenues in 2003 from three of such power purchase agreements

(excluding three other power purchase agreements which were acquired in 2004). We rely on all of such power purchase agreements for the relevant portion of our revenues.

Interconnection Arrangements For Our Nevada Projects

The Steamboat 1A plant is interconnected to Sierra Pacific Power Company's grid pursuant to the terms of a special facilities agreement. There are no material outstanding obligations under this agreement remaining to be performed by our project subsidiary. The Steamboat 1 and Steamboat Hills projects are interconnected to Sierra Pacific Power Company's grid pursuant to the terms of each project's power purchase agreement.

Our project subsidiaries also have interconnected the Steamboat 2 and Steamboat 3 plants to Sierra Pacific Power Company's grid pursuant to the terms of a special facilities agreement. Our project subsidiaries reimburse Sierra Pacific Power Company, the interconnecting utility, for costs incurred in the operation, maintenance and refurbishment of the interconnection facilities and equipment. As a part of the interconnection agreement, it was stipulated that Sierra Pacific Power Company would perform a reduced scope of work, as certain recommendations made by Sierra Pacific Power Company were not agreed to by us. As a result of the reduced scope of work performed by Sierra Pacific Power Company, our project subsidiaries agreed, under the terms of the agreement to assume certain increased risks of outages, indemnify Sierra Pacific Power Company from liability resulting from the reduced scope of work, and add certain equipment to our facilities before expanding the plants.

All of the special facilities agreements for the Steamboat 1A, Steamboat 2, and Steamboat 3 projects require our project subsidiaries to indemnify Sierra Pacific Power Company from liability arising out of the engineering, design, construction, maintenance or operation of, or the making of improvements or additions to, our facilities. However, our project subsidiaries do not have an obligation to indemnify Sierra Pacific Power Company for liability or loss to the extent such liability or loss results from Sierra Pacific Power Company's negligence or willful misconduct.

Our project subsidiary has interconnected the Brady project to Sierra Pacific Power Company's grid pursuant to the terms of the Brady power purchase agreement. Our project subsidiary has an obligation under this agreement to maintain all project property required for the receipt of energy from the interconnecting utility.

Power Purchase Agreements For Our California Projects

Our California project subsidiaries sell electricity from our Mammoth, Ormesa, Heber 1 and Heber 2 projects under seven separate power purchase agreements with Southern California Edison Company. In the case of our Mammoth project subsidiary, there are three such agreements which we refer to as the G-1, G-2 and G-3 power purchase agreements. In the case of our Ormesa project subsidiary, there are two such power purchase agreements, which we refer to as the Ormesa I and Ormesa II power purchase agreements. Each of our Heber 1 and Heber 2 project subsidiaries also has one such power purchase agreement. These agreements have different durations, but generally have the same terms and conditions, except as specifically noted below.

The G-1, G-2, G-3, Ormesa I, Ormesa II, Heber 1 and Heber 2 power purchase agreements do not terminate at their stated expiry dates unless either party gives prior written notice. The notice period is five years in the case of the G-1 power purchase agreement and 90 days in the case of the other power purchase agreements. The Heber 1 power purchase agreement may be terminated by our project subsidiary prior to its stated expiry upon making payment to Southern California Edison Company in an amount equal to the difference between (1) the total capacity payments paid by Southern California Edison Company up to and including the date of receipt of the termination notice and (2) the total capacity payments which Southern California Edison Company would have paid our project subsidiary for the period of our project subsidiary's actual performance at the adjusted capacity price with interest compounded monthly up to the date of termination of the power purchase agreement.

Under all of the power purchase agreements, our project subsidiaries are entitled to receive, against performance of their obligations, capacity and energy payments on a monthly basis. The energy payments for all of our California project subsidiaries are currently set pursuant to the terms of settlement agreements through April 2007, but beginning in May 2007 will be based on Southern California Edison Company's short run avoided cost. Under the G-3, Ormesa I, Ormesa II and Heber 1 and 2 power purchase agreements, our project subsidiaries potentially are entitled to receive capacity bonuses if the performance of the respective facilities exceed certain requisite performance requirements. Under the G-2, G-3, Ormesa I, Ormesa II and Heber 2 power purchase agreements, Southern California Edison Company may request that our project subsidiaries discontinue or reduce the delivery of energy during off-peak periods if certain economic circumstances exist.

Our project subsidiaries are entitled to perform scheduled maintenance on the respective facilities subject to certain limitations. Under the G-1 power purchase agreement, our project subsidiary has agreed to give reasonable prior written notice of its intent to perform scheduled maintenance and must use its best efforts to schedule such outages during off-peak hours. Under the G-2, G-3, Ormesa I, Ormesa II, Heber 1 and Heber 2 power purchase agreements, our project subsidiaries have agreed to give prior written notice of all scheduled outages; not to perform major overhauls during peak months; to use reasonable efforts to schedule routine maintenance during off-peak months; to cap the number of outage hours that may be taken during peak hours of peak months; and to cap the number of outage hours that may be taken during any twelve-month period.

Under the G-3, Ormesa I, Ormesa II and Heber 1 and 2 power purchase agreements, each of our project subsidiaries has an obligation to meet certain minimum performance requirements set forth in such agreements and to demonstrate its capacity on an annual basis. To meet such minimum performance requirements, each of our project is required to provide the following stipulated contract capacity: 10 MW for the G-3 plant, 24 MW for the Ormesa I plant, 15 MW for the Ormesa II plant, 45 MW for the Heber 1 project, and 40 MW for the Heber 2 project in each peak month for all on-peak hours (as such terms are defined in each relevant power purchase agreement) less an allowance of 20% for forced outages. If one of our project subsidiaries fails to meet such minimum performance requirements, it 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 subsidiary to Southern California Edison Company. If one of our project subsidiaries fails to demonstrate its capacity, the capacity of the relevant power plant may be permanently reduced and, in such case, a refund would be required to be made from such project subsidiary to Southern California Edison Company. Our project subsidiary may also reduce the capacity of the plants upon notice to Southern California Edison Company and after making a certain payment to it.

All of our project subsidiaries have an obligation pursuant to their respective power purchase agreements to indemnify Southern California Edison Company for most losses, damages, claims, costs, charges, or expenses to the extent caused by the negligent acts of our project subsidiaries.

As part of their obligations, our project subsidiaries must maintain certain insurance coverage for the relevant project. If any of our project subsidiaries fails to maintain such coverage, it must indemnify Southern California Edison Company for liabilities to the extent Southern California Edison Company would have been protected had our project subsidiary maintained such insurance coverage.

Our project subsidiaries are released from their obligations under the relevant power purchase agreement to the extent any of them cannot wholly or partly perform such obligations as a result of uncontrollable force, so long as our project subsidiary provides prompt written notice to Southern California Edison Company and attempts to remedy its inability to perform. In addition, under the G-3, Ormesa I, Ormesa II, and Heber 1 and 2 power purchase agreements, Southern California Edison Company is obligated to make capacity payments for up to 90 days during the occurrence of an uncontrollable force. Also, pursuant to the Heber 1, Ormesa I and Ormesa II power purchase agreements, an uncontrollable force that prevents operation for certain prolonged periods of time is deemed to be an abandonment of the project. An abandonment, whether due to an uncontrollable force or other specified events provides Southern California Edison Company with certain rights to purchase the relevant power plant.

All of our project subsidiaries are prohibited from assigning their respective power purchase agreements without the prior written consent of Southern California Edison Company, except that all of our project subsidiaries other than Heber 1 may assign their respective power purchase agreement in connection with the merger or a sale of substantially all of the project assets. The Ormesa II power purchase agreement may be assigned by our project subsidiary to a lender in connection with a related financing. Our Heber 1 and 2 project subsidiaries may assign their power purchase agreements without the prior written consent of Southern California Edison Company to an affiliate.

Under the Ormesa I and Ormesa II power purchase agreements, under certain circumstances, Southern California Edison Company or its designee has a right of first refusal to acquire the facility. Under the G-1 power purchase agreements, under certain circumstances, Southern California Edison Company or its subsidiary or affiliate has a right of first refusal to acquire the facility. Under the Heber 1 power purchase agreement, under certain circumstances, Southern California Edison Company or its subsidiary has a right of first refusal to acquire the facility.

The G-1 power purchase agreement expires on February 26, 2014; the G-2 power purchase agreement expires on December 7, 2020 and the G-3 power purchase agreement expires on December 22, 2020. The Ormesa I and Ormesa II power purchase agreements expire on October 2016 and March 1, 2017, respectively. Our Heber 1 and 2 power purchase agreements expire on December 2015 and July 2023, respectively.

We have an aggregate of seven power purchase agreements with respect to our California projects, from which we derived $98.6 million of pro forma revenues in 2003. We rely on all of such power purchase agreements for the relevant portion of our revenues.

Interconnection Arrangements for our California Projects

Each of our project subsidiaries has entered into an interconnection facilities agreement for the Mammoth G-1, G-2 and G-3 plants with Southern California Edison Company. Each of our project subsidiaries has an obligation to operate and maintain the interconnection facilities at its own expense. Each of our project subsidiaries must indemnify the interconnecting utility from liability arising out of any fault or damage to our interconnection facilities, the interconnecting utility's transmission system or the public as a result of its operation of the G-1, G-2 and G-3 plants.

Each of our project subsidiaries interconnects the Ormesa project (for the Ormesa I and Ormesa II power purchase agreements) and Heber 1 and 2 projects to Southern California Edison Company's grid by way of transmission lines owned by the Imperial Irrigation District, which we refer to as IID. These transmission lines interconnect the Ormesa, Heber 1 and Heber 2 projects with Southern California Edison Company's transmission system and are governed by the terms of certain plant connection agreements. IID has the right to curtail the amount of electricity it carries on such transmission lines under certain circumstances. Transmission service charges are paid monthly to IID pursuant to certain transmission service agreements.

Power Purchase Agreement for the Puna Project

Our Puna project subsidiary in Hawaii sells its electrical output to Hawaii Electric Light Company under a long-term power purchase agreement.

The power purchase agreement with Hawaii Electric Light Company provides that either party may terminate the agreement if an event of force majeure occurs and is continuing for twelve consecutive months and the affected party has not taken action to cure the event.

Under the Puna power purchase agreement, our project subsidiary is entitled to receive, on a monthly basis, energy payments and capacity payments. The energy payments for a portion of the energy delivered by our project subsidiary are equal to the higher of the short term avoided cost rates for energy in effect for the relevant billing period or a fixed rate. The energy payments for a smaller portion of energy to be delivered by our project subsidiary to Hawaii Electric Light Company 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 certain floor. Our project subsidiary also receives a payment for providing reactive power to Hawaii Electric Light Company. To meet the minimum capacity performance requirement provided for in the agreement, our project is required to furnish stipulated contract capacity of 30 MW in each peak month for all on-peak hours (as such terms are defined in the power purchase agreement). If our project subsidiary does not meet its minimum capacity performance requirements, our project subsidiary will be required to pay Hawaii Electric Light Company $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, our project subsidiary is required to pay $7,992 to Hawaii Electric Light Company for each full percentage point of the deficiency, and if such availability is less than 80%, our project subsidiary is required to pay $11,875 for each full percentage point of the deficiency. For each power plant trip in excess of six per contract year, our project subsidiary will pay $10,000 to Hawaii Electric Light Company.

Our project subsidiary is not required to perform its obligations under the power purchase agreement following the occurrence of a force majeure event, upon providing Hawaii Electric Light Company with prompt notice of the suspension of our project subsidiary's performance and commencing with remedial measures. Issues with the geothermal resource by itself do not constitute a force majeure event unless our project subsidiary has taken adequate measures to try to mitigate the adverse impacts of such issues.

Our project subsidiary has an obligation to indemnify Hawaii Electric Light Company from and against any and all loss and liability in connection with personal injury, bodily injury or property damage, directly or indirectly resulting from or arising out of or in connection with the interconnection or parallel operation of our project subsidiary's facility which is attributable to (1) the negligence or willful misconduct of our project subsidiary and/or (2) the breach of representations or warranties in the relevant power purchase agreement. Our project subsidiary is also required to obtain and maintain insurance coverage for the power plant.

Our project subsidiary is generally required to coordinate scheduled maintenance with respect to the power plant with Hawaii Electric Light Company. Our project subsidiary has an obligation to obtain Hawaii Electric Light Company's approval in order to schedule the days each year during which a plant overhaul may be performed.

Our project subsidiary cannot assign the power purchase agreement without the prior written consent of Hawaii Electric Light Company, although our project subsidiary may assign the power purchase agreement to lending institutions in connection with the financing of the project without the prior consent of Hawaii Electric Light Company.

The initial term of the Puna power purchase agreement is scheduled to expire on December 31, 2027 which term will continue in effect after such initial term until either party has given notice of not less than five years of its intent to terminate such power purchase agreement.

We have one power purchase agreement with respect to the Puna project, from which we derived $18.7 million of pro forma revenues in 2003. We rely on such power purchase agreement for the relevant portion of our revenues.

Interconnection Arrangement for the Puna Project

Our project subsidiary is interconnected to Hawaii Electric Light Company's transmission system pursuant to agreements to design and construct transmission lines and substation facilities. There are no material outstanding obligations under these agreements.

Power Purchase Agreement for the Leyte Project

The Leyte project in the Philippines sells energy and capacity to the Philippine National Power Corporation. According to the BOT agreement which was subsequently amended in February and April 1996, Ormat-Leyte Co. Ltd. is required to deliver the electricity generated at the Leyte Project

to the Philippine National Power Corporation, on behalf of PNOC-Energy Development Corporation. PNOC-Energy Development Corporation agreed to supply Ormat-Leyte Co. Ltd. with the geothermal fluid necessary for operating the power plant during the entire term of the BOT agreement at no cost. Under the BOT agreement, our project subsidiary will dedicate all energy and capacity of the power plant to the purchaser, and the purchaser is obligated to purchase all of the electricity generated by the project and provide our project with capacity payments and energy fees. PNOC-Energy Development Corporation agreed to make the Leyte Power Expansion Geothermal Reservation site available exclusively to us at no cost in exchange for the construction and operation of the project. The BOT agreement expires in September 2007, at the end of which the power plant will be transferred to PNOC-Energy Development Corporation (for no further consideration).

We have a BOT Agreement with respect to the Leyte project, from which we derived $12.6 million of pro forma revenues in 2003. We rely on such BOT agreement for the relevant portion of our revenues.

Power Purchase Agreement for the Momotombo Project

The Momotombo project in Nicaragua sells electricity to the Nicaraguan Electricity Company. The Momotombo project has a power purchase agreement and a concession agreement with Nicaraguan Electricity Company, both of which will expire in 2014. The revenues from the Momotombo project will cease at the time the concession expires. The term of the concession may be extended for an additional period of 15 years or less with both parties' consent. There is also a provision for possible extension of the power purchase agreement, subject to both parties' consent. In 2001, Nicaraguan Electricity Company assigned the power purchase agreement to 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. Under the power purchase agreement, Ormat Momtombo Power Company, our wholly owned project subsidiary that operates the project, is required to use all available geothermal steam extracted by the plant in order to generate electricity. Our project subsidiary cannot sell the electricity to any person or organization other than the power purchasers. The power purchasers are required to pay for the electricity each month according to the amount of electricity that our project subsidiary sold or is deemed to have sold. Our project subsidiary may sell electricity to third parties if the power purchase agreement is terminated prior to the end of its term for reasons attributable to the power purchasers. However, if the price at which the electricity is sold to the third party is higher than the price fixed in the power purchase agreement, the power purchasers are entitled to 85% of such difference.

We have one power purchase agreement with respect to the Momotombo project, from which we derived $11.6 million of pro forma revenues in 2003. We rely on such power purchase agreement for the relevant portion of our revenues.

Power Purchase Agreement for the Olkaria III Project

The Olkaria III project in Kenya sells electricity to the Kenya Power & Lighting Co. Ltd. Under the power purchase agreement, the purchaser is obligated to pay the project a capacity fee and an energy fee. The term of the power purchase agreement expires in 2020 or, if Phase II of the project is constructed, 20 years from the date on which such Phase II commences commercial operation, and may be extended with both parties' consent on such terms as the parties may agree.

We have one power purchase agreement with respect to the Olkaria III project, from which we derived $9.7 million of pro forma revenues in 2003. We rely on such power purchase agreement for the relevant portion of our revenues.

Power Purchase Agreement for the Zunil Project

The Zunil project in Guatemala sells electricity to Instituto Nacional de Electrification. Pursuant to the power purchase agreement, which will expire in October 2019, the power purchaser is responsible for supplying the geothermal fluid to the plant. The power purchaser is obligated to

purchase all the power generated by the plant's facilities, as converted from the geothermal fluid. The power purchaser is required to make both an energy payment and a capacity payment to the project, the rate of which is pre-determined under the power purchase agreement, regardless of whether or not the power purchaser is able to supply the geothermal fluid to the plant. Instituto Nacional de Electrification has the option to receive, by way of allotment for no consideration, 3% of the issued share capital of Orzunil, the owner of the Zunil project. Upon termination of the power purchase agreement, Instituto Nacional de Electrification will have the right of first refusal to acquire the power plant's assets at a price no lower than its market value. In the event that our project terminates the power purchase agreement, it will have the right to continue and operate the power plant and sell electricity to any other purchaser. Pursuant to the power purchase agreement, the purchaser is responsible, among other things, for building and maintaining transmission lines and maintaining and operating the geothermal reservoir.

Leases

Bureau of Land Management Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with the U.S. government, pursuant to which they have obtained the right to conduct their geothermal development and operations on federally-owned land. These leases are made pursuant to the Geothermal Steam Act of 1970, which we refer to as the Act, and the lessor under such leases is the U.S. government, acting through the U.S. Department of the Interior, Bureau of Land Management, which we refer to as the BLM.

Typically, BLM geothermal leases grant projects the exclusive right and privilege to drill for, extract, produce, remove, utilize, sell and dispose of geothermal steam and associated geothermal resources. The projects are also granted certain nonexclusive rights, which include, among others, the right to conduct within the leased area geological and geophysical exploration (in accordance with certain applicable regulations), as well as the right to construct and operate within the leased area power generating plants and certain other works and related structures and to use so much of the surface of the land as may be necessary or reasonably convenient for the production, utilization and processing of geothermal resources (subject to applicable laws and regulations). Additionally, projects are granted the right to reinject into the leased lands geothermal resources and condensates to the extent that such resources and condensates are not utilized and to the extent that such reinjection is necessary for geothermal operations.

The leases provide for a primary term of 10 years and so long thereafter as geothermal steam is being produced or utilized in commercial quantities, but cannot exceed a period of 40 years after the end of the primary term. However, if at the end of the such 40-year period geothermal steam is still being produced or utilized in commercial quantities and the applicable leased lands are not needed for other purposes, the project will have a preferential right for a renewal of the lease for a second 40-year term, in accordance with such terms and conditions as the BLM deems appropriate. If actual drilling operations are commenced on the leased lands or under an approved plan or agreement on behalf of the leased lands prior to the end of the primary term and are being diligently prosecuted at the end of the primary term, the lease will be extended for 5 additional years and so long thereafter (but not more than 35 years) as geothermal steam is produced or utilized in commercial quantities. If at the end of such extended term, geothermal steam is still being produced or utilized in commercial quantities, the project will have the preferential right for a renewal for a second term. The leases also provide for extensions under certain other circumstances.

Under the terms of the BLM leases, projects are required to pay an annual rental fee (on a per acre basis), which escalates according to a schedule described therein, until production of geothermal steam in commercial quantities has commenced. After such production has commenced, the projects are required to pay royalties (on a monthly basis) on the amount or value of (1) steam, (2) by-products derived from production and (3) commercially de-mineralized water sold or utilized by the project (or reasonably susceptible to such sale or use).

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

In the event of a default under any such BLM lease, or the failure to comply with any of the provisions of the Act or regulations issued under the Act or the terms or stipulations of the lease, the BLM may, 30 days after notice of default is provided to the relevant project, (1) suspend operations until the requested action is taken or (2) cancel the lease.

Private Geothermal Leases

Certain of our domestic project subsidiaries have entered into geothermal resources leases with private parties, pursuant to which they have obtained the right to conduct their geothermal development and operations on privately owned land.

Typically, the leases grant our project subsidiaries the exclusive right and privilege to drill for, produce, extract, take and remove from the leased land water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted by such project subsidiary. The project subsidiaries are also granted certain rights pertaining to the construction and operation of plants, structures and facilities on the leased land. Additionally, the project subsidiaries are granted the right to dispose of waste brine and other waste products as well as the right to reinject into the leased land water, brine, steam and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity.

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

As consideration under such leases, the project subsidiary must pay to the lessor a certain specified percentage of the value "at the well" (which is not attributable to the enhanced value of electricity generation), gross proceeds or gross revenues of all lease products produced, saved and sold on a monthly basis.

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

If the project subsidiary fails to pay any installment of royalty or rental when due and if such default continues for a period of 15 days after its receipt of written notice thereof from the lessor, then at the option of the lessor, the lease will terminate as to the portion or portions thereof as to which the project subsidiary is in default.

If the project subsidiary defaults in the performance of any obligations under the lease, other than a payment default, and if, for a period of 90 days after written notice is given to it by the lessor of such default, the project subsidiary fails to commence and thereafter diligently and in good faith take remedial measures to remedy such default, the lessor may terminate the lease.

PRINCIPAL STOCKHOLDERS

The following table shows information with respect to the beneficial ownership of our common stock as of October 15, 2004, and as adjusted to reflect the sale of common stock being offered in this offering, for:

•	each person, or group of affiliated persons, known to us to own beneficially 5% or more of our outstanding common stock;

•	each of our directors;

•	each of our named executive officers; and

•	all of our directors and executive officers as a group.

Percentage ownership before the offering is based on 24,374,996 shares of common stock outstanding as of October 15, 2004, subject to the assumptions set forth below. Percentage ownership after the offering is based on 30,624,996 shares of common stock outstanding immediately after the closing of this offering. Beneficial ownership is determined in accordance with the rules of the SEC. Except as indicated by footnote and subject to community property laws where applicable, to our knowledge, the persons named in the table below have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, shares of common stock subject to options held by that person that are exercisable as of October 21, 2004, or will become exercisable within 60 days thereafter are deemed outstanding, while such shares are not deemed outstanding for purposes of computing percentage ownership of any other person.

				Shares of Ormat Technologies Common Stock Beneficially Owned												Shares of Ormat Industries Common Stock Beneficially Owned								Maximum Number of Shares being Sold in the Over- Allotment Option, if Any				Shares Beneficially Owned After the Offering if the Underwriters' Over- Allotment Option is Exercised in Full
								Percent in this Offering
Name of Beneficial Owner				Number of Shares				Before Offering				After Offering				Number				Percent								Number of Shares				Percentage Ownership
Principal Stockholder:
Ormat Industries Ltd.†				24,374,996(1)					100	%			79.6	%			—				—			—				24,374,996				77.2%
Directors and Executive Officers:
Yehudit Bronicki†				—					—				—				32,269,130	(2)			34.91	%		—				—				—
Lucien Bronicki†				—					—				—				32,269,130	(2)			34.91	%
Yoram Bronicki†				—					—				—				—				—			—				—				—
Nadav Amir†				—					—				—				33,000	(3)				*		—				—				—
Hezy Ram††				—					—				—				24,750	(4)				*		—				—				—
Aaron Choresh†				—					—				—				20,625	(5)				*		—				—				—
Zvi Reiss†				—					—				—				28,875	(6)				*		—				—				—
All executive officers and directors as a group (eleven (11) persons)				—					—				—				38,906,811				35.11	%		—				—				—

†	c/o Ormat Industries Ltd., Industrial Area, P.O. Box 68 Yavneh 81100, Israel

††	c/o Ormat Technologies, Inc., 980 Greg Street, Sparks, NV 89431

*	Represents beneficial ownership of less than 1% of the outstanding shares of common stock.

(1)	The board of directors of Ormat Industries has voting power and investment power over our shares. The board of Ormat Industries includes Lucien Bronicki, Dita Bronicki and Yoram Bronicki, who collectively with their family as of October 15, 2004 beneficially owned approximately 34.91% of the ordinary shares of Ormat Industries through their holdings in Bronicki Investment Ltd.

(2)

Includes 32,269,030 shares beneficially owned by Bronicki Investment Ltd. Mr. and Mrs. Bronicki are directors of Bronicki Investment Ltd. and have voting control of such shares held by Bronicki Investment Ltd. Each of Mr. and Mrs. Bronicki also owns 20% of Bronicki Investment Ltd. Accordingly, they may be deemed to share beneficial ownership of such shares held by Bronicki Investment Ltd. Each of Mr. and Mrs. Bronicki disclaims beneficial ownership of all shares held by Bronicki Investment Ltd., except to the extent of his or her 20% ownership in Bronicki Investment Ltd.

(3)	Represents currently exercisable options granted to Mr.Amir to purchase 33,000 ordinary shares of Ormat Industries; this excludes options to purchase 66,000 ordinary shares of Ormat Industries which are not exercisable within 60 days of June 30, 2004.

(4)	Represents currently exercisable options granted to Mr. Ram to purchase 24,750 ordinary shares of Ormat Industries; this excludes options to purchase 66,000 ordinary shares of Ormat Industries which are not exercisable within 60 days of June 30, 2004.

(5)	Represents currently exercisable options granted to Mr. Choresh to purchase 20,625 ordinary shares of Ormat Industries; this excludes options to purchase 41,875 ordinary shares of Ormat Industries which are not exercisable within 60 days of June 30, 2004.

(6)	Represents currently exercisable options granted to Mr. Reiss to purchase 28,875 ordinary shares of Ormat Industries; this excludes options to purchase 61,875 ordinary shares of Ormat Industries which are not exercisable within 60 days of June 30, 2004.

DESCRIPTION OF CAPITAL STOCK

The following is a description of our capital stock and the material provisions of our amended and restated certificate of incorporation, amended and restated by-laws and other agreements to which we and our stockholders are parties, in each case upon the closing of this offering. The following is only a summary and is qualified by applicable law and by the provisions of the amended and restated certificate of incorporation, amended and restated by-laws and other agreements, copies of which are available as set forth under the caption entitled "Where You Can Find More Information."

General

As of June 30, 2004, 24,374,996 shares of our common stock were issued and outstanding, all of which were owned by Ormat Industries. Our amended and restated certificate of incorporation provides that our authorized capital stock will consist of an aggregate number of 200,000,000 shares of common stock, par value $0.001 per share, and 5,000,000 shares of preferred stock, par value $0.001 per share, of which our board of directors has designated 500,000 shares as Series A Junior Participatory Preferred Stock for issuance in connection with the exercise of our preferred share purchase rights pursuant to a rights plan which we intend to adopt. See "—Rights Plan" below. Each such outstanding share of our common stock will be validly issued, fully paid and non-assessable. In addition, at such time, shares of our common stock will be reserved for issuance upon exercise of outstanding options.

Common Stock

Voting.    The holders of our common stock are entitled to one vote for each outstanding share of common stock owned by that stockholder on every matter properly submitted to the stockholders for their vote. Stockholders are not entitled to vote cumulatively for the election of directors.

Dividend Rights.    Subject to the dividend rights of the holders of any outstanding series of preferred stock, holders of our common stock are entitled to receive ratably such dividends and other distributions of cash or any other right or property as may be declared by our board of directors out of our assets or funds legally available for such dividends or distributions.

Liquidation Rights.    In the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs, holders of our common stock would be entitled to share ratably in our assets that are legally available for distribution to stockholders after payment of liabilities. If we have any preferred stock outstanding at such time, holders of the preferred stock may be entitled to distribution and/or liquidation preferences. In either such case, we must pay the applicable distribution to the holders of our preferred stock before we may pay distributions to the holders of our common stock.

Conversion, Redemption and Preemptive Rights.    Holders of our common stock have no conversion, redemption, preemptive, subscription or similar rights.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our board of directors, subject to limitations prescribed by law, to issue up to 5,000,000 shares of preferred stock in one or more series without further stockholder approval. The board will have discretion to determine the rights, preferences, privileges and restrictions of, including, without limitation, voting rights, dividend rights, conversion rights, redemption privileges and liquidation preferences of, and to fix the number of shares of, each series of our preferred stock.

Our board of directors has designated 500,000 shares of our preferred stock as Series A Junior Participating Preferred Stock for issuance in connection with the exercise of our preferred share purchase rights pursuant to our rights plan. Although our board of directors has no intention at the present time of doing so, it could authorize the issuance of shares of preferred stock with terms and conditions that could have the effect of delaying, deferring or preventing a transaction or a change in control that might involve a premium price for holders of our common stock or otherwise be in their best interest. See "—Rights Plan" below.

Limitations on Directors' Liability

Our amended and restated certificate of incorporation and by-laws contain provisions indemnifying our directors and officers to the fullest extent permitted by law. Prior to the completion of this offering, we intend to enter into indemnification agreements with each of our directors which may, in some cases, be broader than the specific indemnification provisions contained under Delaware law.

In addition, as permitted by Delaware law, our amended and restated certificate of incorporation provides that no director will be liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director. The effect of this provision is to restrict our rights and the rights of our stockholders in derivative suits to recover monetary damages against a director for breach of fiduciary duty as a director, except that a director will be personally liable for:

•	any breach of his or her duty of loyalty to us or our stockholders;

•	acts or omissions not in good faith which involve intentional misconduct or a knowing violation of law;

•	the payment of dividends or the redemption or purchase of stock in violation of Delaware law; or

•	any transaction from which the director derived an improper personal benefit.

This provision does not affect a director's liability under the federal securities laws.

To the extent that our directors, officers and controlling persons are indemnified under the provisions contained in our amended and restated certificate of incorporation, Delaware law or contractual arrangements against liabilities arising under the Securities Act, we have been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Provisions of Our Amended and Restated Certificate of Incorporation, Amended and Restated By-laws, Rights Plan and Delaware Law that May Have an Anti-Takeover Effect

Amended and Restated Certificate of Incorporation and Amended and Restated By-laws

Certain provisions in our amended and restated certificate of incorporation and amended and restated by-laws summarized below may be deemed to have an anti-takeover effect and may delay, deter or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interests, including attempts that might result in a premium being paid over the market price for the shares held by stockholders.

Classified Board of Directors.    Our amended and restated certificate of incorporation provides that the number of directors is fixed by our board of directors. Our directors are divided into three classes, each class consisting as nearly as possible of an equal number of directors. Currently, the terms of office for the three classes of directors expire, respectively, at our annual meetings in 2005, 2006 and 2007. The term of the successors of each class of directors expires three years from the year of election. Directors elected by stockholders at an annual meeting of stockholders will be elected by a plurality of all votes cast. To amend or repeal the provisions providing for our classified board of directors in our amended and restated certificate of incorporation and by-laws, the affirmative vote of the holders of at least 75% of the then outstanding shares of capital stock entitled to vote is required.

Special Meetings.    Our amended and restated certificate of incorporation and amended and restated by-laws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the President, our board of directors, the holders of not less than a majority of all of the outstanding shares of the corporation entitled to vote at the meeting or, at any time that Ormat Industries (or a certain transferee of Ormat Industries) owns at least 20% of the then outstanding shares of our common stock, by Ormat Industries (or such transferee). Stockholders are not permitted to call, or to require that the board of directors call, a special meeting of stockholders. Moreover, the

business permitted to be conducted at any special meeting of stockholders is limited to the business brought before the meeting pursuant to the notice of the meeting given by us. Our amended and restated by-laws establish an advance notice procedure for stockholders to nominate candidates for election as directors or to bring other business before meetings of our stockholders.

The foregoing proposed provisions of our amended and restated certificate of incorporation and amended and restated by-laws could discourage potential acquisition proposals and could delay or prevent a change in control. These provisions are intended to enhance the likelihood of continuity and stability in the composition of the board of directors and in the policies formulated by the board of directors and to discourage certain types of transactions that may involve an actual or threatened change of control. These provisions are designed to reduce our vulnerability to an unsolicited acquisition proposal. The provisions also are intended to discourage certain tactics that may be used in proxy fights. However, such provisions could have the effect of discouraging others from making tender offers for our shares and, as a consequence, they also may inhibit fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts. Such provisions also may have the effect of preventing changes in our management.

Rights Plan

Pursuant to our rights agreement with American Stock Transfer & Trust Company, as rights agent, each holder of our common stock has the right (which we refer to, collectively, as the rights) to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock for each share of common stock owned by each such holder for $                , subject to adjustment. Our rights initially trade with, and are inseparable from, our common stock. Our rights are evidenced only by certificates that represent shares of our common stock. New rights will accompany any new shares of common stock we issue after the date this offering is completed until the date on which the rights are distributed as described below. The rights will generally become exercisable ten days following a public announcement that a person or group of affiliated or associated persons (which we refer to as an acquiring person) has acquired beneficial ownership of 15% or more of the voting power of all of our outstanding capital stock or ten business days, or such later date as may be determined by our board of directors prior to such time as any person or group becomes an acquiring person, following the commencement of, or announcement of an intention to make, a tender offer or exchange offer the consummation of which would result in the beneficial ownership by a person or group of 15% or more of the voting power of all of our outstanding capital stock. In the event that, at any time after a person has become an acquiring person, we are acquired in a merger or other business combination transaction or 50% or more of our consolidated assets or earning power is sold, proper provision will be made so that each holder of rights will thereafter have the right to receive, upon the exercise thereof, at the then current exercise price of the rights, that number of shares of common stock of the acquiring company which at the time of such transaction will have a market value of two times the exercise price of the rights. In the event that any person becomes an acquiring person, proper provision shall be made so that each holder of rights, other than the rights beneficially owned by the acquiring person, which will thereafter be void, will have the right to receive upon exercise, instead of shares of Series A Junior Participating Preferred Stock, that number of shares of common stock having a market value of two times the exercise price of the rights. The rights have the right to vote once exercised, expire in 2014 and may be redeemed by us, at the discretion of our board of directors, in whole, but not in part, at a price of $.001 per right at any time prior to the acquisition by a person or group of affiliated or associated persons of beneficial ownership of 15% or more of the voting power of all of our outstanding capital stock, unless extended.

We cannot redeem shares of Series A Junior Participating Preferred Stock purchasable upon the exercise of the rights. Each share of Series A Junior Participating Preferred Stock will be entitled to a minimum preferential quarterly dividend payment of $1 per share but will be entitled to an aggregate dividend of 100 times the dividend declared per share of common stock whenever such dividend is declared. In the event of liquidation, the holders of Series A Junior Participating Preferred Stock will be entitled to a minimum preferential liquidation payment of $100 per share but will be entitled to an aggregate payment of 100 times the payment made per share of common stock. Each share of Series A Junior Participating Preferred Stock will have 100 votes, voting together with the holders of the common stock. In the event of any merger, consolidation or other transaction in which shares of

common stock are exchanged, each share of Series A Junior Participating Preferred Stock will be entitled to receive 100 times the amount received per share of common stock.

Our board of directors may adjust the purchase price of Series A Junior Participating Preferred Stock, the number of shares of Series A Junior Participating Preferred Stock issuable, and the number of our outstanding rights to prevent dilution that may occur from a stock dividend, a stock split or a reclassification of our Series A Junior Participating Preferred Stock. No adjustments to the purchase price of our Series A Junior Participating Preferred Stock of less than 1% will be made.

The purpose of the rights plan is to encourage potential acquirors to negotiate with our board of directors prior to attempting a takeover and to give the board leverage in negotiating on behalf of the stockholders the terms of any proposed takeover. The rights are intended to have anti-takeover effects. If the rights become exercisable, the rights will cause substantial dilution to a person or group that attempts to acquire or merge with us in most circumstances. Accordingly, the existence of the rights plan may deter a potential acquiror from making a takeover proposal or tender offer for an outstanding common stock. The rights should not interfere with any merger or other business combination approved by our board of directors as we may redeem the rights as described below and since a transaction approved by our board of directors would not cause the rights to become exercisable.

The terms of our rights agreement may be amended by our board of directors without the consent of the holders of our rights. After a person or group becomes an acquiring person, our board of directors may not amend the agreement in a way that adversely affects holders of our rights.

Delaware Takeover Statute

We are subject to Section 203 of the Delaware General Corporation Law, which, subject to certain exceptions, prohibits a Delaware corporation from engaging in any "business combination" (as defined below) with any "interested stockholder" (as defined below) for a period of three years following the date that such stockholder became an interested stockholder, unless: (1) prior to such date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder; (2) on consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding those shares owned (x) by persons who are directors and also officers and (y) by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or (3) on or subsequent to such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.

Section 203 of the Delaware General Corporation Law defines "business combination" to include: (1) any merger or consolidation involving the corporation and the interested stockholder; (2) any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder; (3) subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder; (4) any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or (5) the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation. In general, Section 203 defines an "interested stockholder" as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person.

The New York Stock Exchange

We have applied to list our common stock on the New York Stock Exchange under the symbol "ORA".

Transfer Agent and Registrar

We have appointed American Stock Transfer & Trust Company (AST) as the transfer agent and registrar for our common stock.

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock, and a significant public market for our common stock may not develop or be sustained after this offering. Future sales of significant amounts of our common stock, including shares of our outstanding common stock and shares of our common stock issued upon exercise of outstanding options, in the public market after this offering could adversely affect the prevailing market price of our common stock and could impair our future ability to raise capital through the sale of our equity securities.

Sale of Restricted Shares and Lock-Up Agreements

Upon the closing of this offering, we will have 30,624,996 outstanding shares of common stock based upon our shares outstanding as of October 15, 2004.

Of these shares, the 6,250,000 shares of common stock sold in this offering will be freely tradable without restriction under the Securities Act, unless purchased by affiliates of our company, as that term is defined in Rule 144 under the Securities Act.

The remaining 24,374,996 shares of common stock were issued and sold by us in private transactions, and are eligible for public sale if registered under the Securities Act or sold in accordance with Rules 144, 144(k) or 701 of the Securities Act. However, all of these remaining shares of common stock are held by our parent company, which is subject to a lock-up agreement for a period of 180 days after the date of this prospectus under which it has agreed not to sell or otherwise dispose of its shares of common stock.

The representative, in its sole discretion, may release the shares subject to the lock-up agreement in whole or in part at anytime with or without notice. We have been advised by the representative that, when determining whether or not to release shares from the lock-up agreement, it will consider, among other factors, the stockholder's reasons for requesting the release, the number of shares for which the release is being requested and market conditions at the time. The representative has advised us that they have no present intention to release any of the shares subject to the lock-up agreement prior to the expiration of the lock-up period.

As of the date of this prospectus, none of the remaining shares may be eligible for sale in the public market. Beginning 180 days after the date of this prospectus, all of these remaining shares will be eligible for sale in the public market, subject to certain volume limitations under Rule 144.

Rule 144

In general, Rule 144 allows a stockholder (or stockholders where shares are aggregated) who has beneficially owned shares of our common stock for at least one year and who files a Form 144 with the SEC to sell within any three month period commencing 90 days after the date of this prospectus a number of those shares that does not exceed the greater of:

•	1% of the number of shares of common stock then outstanding, which will equal approximately shares immediately after this offering; or

•	the average weekly trading volume of the common stock during the four calendar weeks preceding the filing of the Form 144 with respect to such sale.

Sales under Rule 144, however, are subject to specific manner of sale provisions, notice requirements, and the availability of current public information about our company. We cannot estimate the number of shares of common stock our existing stockholders will sell under Rule 144, as this will depend on the market price for our common stock, the personal circumstances of the stockholders, and other factors.

Rule 144(k)

Under Rule 144(k), in general, a stockholder who has beneficially owned shares of our common stock for at least two years and who is not deemed to have been an affiliate of our company at any

time during the immediately preceding 90 days may sell shares without complying with the manner of 98 sale provisions, notice requirements, public information requirements, or volume limitations of Rule 144. Affiliates of our company, however, must always sell pursuant to Rule 144, even after the otherwise applicable Rule 144(k) holding periods have been satisfied.

Rule 701

Rule 701 generally allows a stockholder who purchased shares of our common stock pursuant to a written compensatory plan or contract and who is not deemed to have been an affiliate of our company during the immediately preceding 90 days to sell these shares in reliance upon Rule 144, but without being required to comply with the public information, holding period, volume limitation, or notice provisions of Rule 144. Rule 701 also permits affiliates of our company to sell their Rule 701 shares under Rule 144 without complying with the holding period requirements of Rule 144. All holders of Rule 701 shares, however, are required to wait until 90 days after the date of this prospectus before selling such shares pursuant to Rule 701.

As of the date of this prospectus, no shares of our outstanding common stock had been issued in reliance on Rule 701 as a result of exercises of stock options.

Options

In addition to the 30,624,996 shares of common stock outstanding, immediately after this offering, there will be outstanding options to purchase 230,000 shares of our common stock. As soon as practicable after the closing of this offering, we intend to file a registration statement on Form S-8 under the Securities Act covering shares of our common stock issued or reserved for issuance under our 2004 Incentive Compensation Plan. Accordingly, shares of our common stock registered under such registration statement will be available for sale in the open market upon exercise by the holders, subject to vesting restrictions with us, contractual lock-up restrictions, and/or market stand-off provisions applicable to each option agreement that prohibit the sale or other disposition of the shares of common stock underlying the options for a period of 180 days after the date of this prospectus without the prior written consent from us or our underwriters.

Registration Rights

At or prior to the closing of this offering, we will enter into a registration rights agreement with Ormat Industries. See "Certain Relationships and Related Transactions." We do not have any other contractual obligations to register our common stock.

UNITED STATES FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following is a description of the material United States federal income tax consequences that may be relevant to Non-U.S. Holders, as defined below, with respect to the acquisition, ownership and disposition of our common stock. This description addresses only the United States federal income tax considerations of holders that are initial purchasers of our common stock pursuant to the offering and that will hold our common stock as capital assets. This description does not address tax considerations applicable to holders that are U.S. persons or that may be subject to special tax rules, including:

•	financial institutions or insurance companies;

•	real estate investment trusts, regulated investment companies or grantor trusts;

•	dealers or traders in securities or currencies;

•	tax-exempt entities;

•	persons that received our stock as compensation for the performance of services;

•	persons that will hold our stock as part of a "hedging" or "conversion" transaction or as a position in a "straddle" for United States federal income tax purposes;

•	persons that have a "functional currency" other than the U.S. dollar; or

•	holders that own or are deemed to own 10% or more, by voting power or value, of our stock.

Moreover, except as set forth below, this description does not address the United States federal estate and gift or alternative minimum tax consequences of the acquisition, ownership and disposition of our common stock.

This description is based on the Internal Revenue Code of 1986, as amended, which we refer to as the Code, existing, proposed and temporary United States Treasury Regulations and judicial and administrative interpretations thereof, in each case as in effect and available on the date hereof. All of the foregoing are subject to change, which change could apply retroactively and could affect the tax consequences described below.

For purposes of this description, a "Non-U.S. Holder" is a beneficial owner of our common stock that, for United States federal income tax purposes, is not:

•	a citizen or resident of the United States;

•	a partnership or corporation created or organized in or under the laws of the United States or any state thereof, including the District of Columbia;

•	an estate the income of which is subject to United States federal income taxation regardless of its source; or

•	a trust if such trust validly elects to be treated as a United States person for United States federal income tax purposes or if (1) a court within the United States is able to exercise primary supervision over its administration and (2) one or more United States persons have the authority to control all of the substantial decisions of such trust.

If a partnership (or any other entity treated as a partnership for United States federal income tax purposes) holds our common stock, the tax treatment of a partner in such partnership will generally depend on the status of the partner and the activities of the partnership. Such a partner should consult its tax advisor as to its tax consequences.

You should consult your own tax advisor with respect to the United States federal, state, local and foreign tax consequences of acquiring, owning and disposing of our common stock.

Distributions

Generally, but subject to the discussions below under "Status as United States Real Property Holding Corporation" and "Backup Withholding Tax and Information Reporting Requirements," if

you are a Non-U.S. Holder, distributions of cash or property paid to you will be subject to withholding of United States federal income tax at a 30% rate or such lower rate as may be specified by an applicable United States income tax treaty. In order to obtain the benefit of any applicable United States income tax treaty, you will have to file certain forms (e.g., Form W-8BEN). Such forms generally would contain your name and address and a certification that you are eligible for the benefits of such treaty.

Except as may be otherwise provided in an applicable United States income tax treaty, if you are a Non-U.S. Holder and conduct a trade or business within the United States, you generally will be taxed at ordinary United States federal income tax rates (on a net income basis) on dividends that are effectively connected with the conduct of such trade or business and such dividends will not be subject to the withholding described above. If you are a foreign corporation, you may also be subject to a 30% "branch profits tax" unless you qualify for a lower rate under an applicable United States income tax treaty. To claim an exemption from withholding because the income is effectively connected with a United States trade or business, you must provide a properly executed Form W-8ECI (or such successor form as the Internal Revenue Service designates) prior to the payment of dividends.

Sale or Exchange of Our Common Stock

Generally, but subject to the discussions below under "Status as United States Real Property Holding Corporation" and "Backup Withholding Tax and Information Reporting Requirements," if you are a Non-U.S. Holder, you will not be subject to United States federal income or withholding tax on any gain realized on the sale or exchange of our common stock unless (1) such gain is effectively connected with your conduct of a trade or business in the United States or (2) if you are an individual, you are present in the United States for 183 days or more in the taxable year of such sale or exchange and certain other conditions are met.

Status as United States Real Property Holding Corporation

If you are a Non-U.S. Holder, under certain circumstances, gain recognized on the sale or exchange of, and certain distributions in excess of basis with respect to, our common stock would be subject to United States federal income tax, notwithstanding your lack of other connections with the United States, if we are or have been a "United States real property holding corporation" for United States federal income tax purposes at any time during the five-year period ending on the date of such sale or exchange (or distribution). We believe that we will not be classified as a United States real property holding corporation as of the date of this offering and do not expect to become a United States real property holding corporation.

Federal Estate Tax

Our common stock held by an individual at death, regardless of whether such individual is a citizen, resident or domiciliary of the United States, will be included in the individual's gross estate for United States federal estate tax purposes, subject to an applicable estate tax or other treaty, and therefore may be subject to United States federal estate tax.

Backup Withholding Tax and Information Reporting Requirements

United States backup withholding tax and information reporting requirements generally apply to certain payments to certain non-corporate holders of stock. The backup withholding tax rate is currently 28%.

If you are not a United States person, under current Treasury regulations, backup withholding will not apply to distributions on our common stock to you, provided that we have received valid certifications meeting the requirements of the Code and neither we nor the payor has actual knowledge or reason to know that you are a United States person for purposes of such backup withholding tax requirements.

If provided by a beneficial owner, the certification must give the name and address of such owner, state that such owner is not a United States person, or, in the case of an individual, that such person is

neither a citizen or resident of the United States, and must be signed by the owner under penalties of perjury. If provided by a financial institution, other than a financial institution that is a qualified intermediary, the certification must state that the financial institution has received from the beneficial owner the certificate set forth in the preceding sentence, set forth the information contained in such certificate (and include a copy of such certificate), and be signed by an authorized representative of the financial institution under penalties of perjury. Generally, the furnishing of the names of the beneficial owners of our common stock that are not United States persons and a copy of such beneficial owner's certificate by a financial institution will not be required where the financial institution is a qualified intermediary.

In the case of such payments made within the United States to a foreign simple trust, a foreign grantor trust or a foreign partnership, other than payments to a foreign simple trust, a foreign grantor trust or a foreign partnership that qualifies as a "withholding foreign trust" or a "withholding foreign partnership" within the meaning of such United States Treasury Regulations and payments to a foreign simple trust, a foreign grantor trust or a foreign partnership that are effectively connected with the conduct of a trade or business in the United States, the beneficiaries of the foreign simple trust, the persons treated as the owners of the foreign grantor trust or the partners of the foreign partnership, as the case may be, will be required to provide the certification discussed above, and the trust or partnership, as the case may be, will need to provide an appropriate intermediary certification form, in order to establish an exemption from backup withholding tax and information reporting requirements. Moreover, a payor may rely on a certification provided by a payee that is not a United States person only if such payor does not have actual knowledge or a reason to know that any information or certification stated in such certificate is incorrect.

The above description is not intended to constitute a complete analysis of all tax consequences relating to the acquisition, ownership and disposition of our common stock. You should consult your own tax advisor concerning the tax consequences of your particular situation.

UNDERWRITING

Under the underwriting agreement, which is filed as an exhibit to the registration statement relating to this prospectus, each of the underwriters named below, for whom Lehman Brothers Inc., sole book-running manager and representative of the underwriters listed below, has severally agreed to purchase from us, on a firm commitment basis, subject only to the conditions contained in the underwriting agreement, the number of shares of common stock shown opposite each of their names below:

Underwriter				Number of Shares
Lehman Brothers Inc.
Deutsche Bank Securities Inc.
RBC Capital Markets Corporation
Wells Fargo Securities, LLC
Total					6,250,000

The underwriting agreement provides that the underwriters' obligations to purchase our common stock depend on the satisfaction of the conditions contained in the underwriting agreement, which include:

•	if any shares of common stock are purchased by the underwriters, then all of the shares of common stock the underwriters agreed to purchase must be purchased;

•	the representations and warranties made by us to the underwriters are true;

•	there is no material change in the financial markets; and

•	we deliver customary closing documents to the underwriters.

Commissions and Expenses

The representative has advised us that the underwriters propose to offer the common stock directly to the public at the public offering price presented on the cover page of this prospectus, and to selected dealers, that may include the underwriters, at the public offering price less a selling concession not in excess of $        per share. The underwriters may allow, and the selected dealers may re-allow, a concession not in excess of $        per share to brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

The following table summarizes the underwriting discounts and commissions that we will pay. The underwriting discount is the difference between the offering price and the amount the underwriters pay to purchase the shares from us. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase up to an additional 937,500 shares. The underwriting discounts and commissions equal       % of the public offering price.

				No Exercise				Full Exercise
Per share				$				$
Total

We estimate that the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $3,128,500. We have agreed to pay such expenses.

Over-Allotment Option

We have granted to the underwriters an option to purchase up to an aggregate of additional shares of common stock, exercisable to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions shown on the cover page of this prospectus. The underwriters may exercise this option at any time, and from time to time, until 30 days after the date of the underwriting agreement. To the extent the underwriters exercise this option, each

underwriter will be committed, so long as the conditions of the underwriting agreement are satisfied, to purchase a number of additional shares of common stock proportionate to that underwriter's initial commitment as indicated in the preceding table, and we will be obligated, under the over-allotment option, to sell the additional shares of common stock to the underwriters.

Lock-Up Agreements

Pursuant to lock-up agreements, we will agree not to, and each of our officers, directors and stockholders will agree not to, for period of 180 days from the date of this prospectus, directly or indirectly, (1) offer for sale, sell, pledge or otherwise dispose of (or enter into any transaction or device which is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of common stock or securities convertible into or exchangeable for common stock (other than the stock and shares issued pursuant to employee benefit plans, qualified stock option plans or other employee compensation plans existing on the date hereof or pursuant to currently outstanding options, warrants or rights), or sell or grant options, rights or warrants with respect to any shares of common stock or securities convertible into or exchangeable for common stock (other than the grant of options pursuant to option plans existing on the date hereof), (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such shares of common stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common stock or other securities, in cash or otherwise, in each case without the prior written consent of Lehman Brothers Inc. on behalf of the underwriters. During such 180-day period, the representative may, in its sole discretion, give such consent in whole or in party at any time with or without notice. When determining whether to or not to give their consent, the representative will consider, among other factors, the stockholder's reason for requesting such consent, the number of shares for which such consent is being requested and market conditions at the time. If (1) during the last 17 days of such 180-day period we issue an earnings release or material news or a material event relating to us occurs or (2) prior to the expiration of such 180-day period, we announce that we will release earnings results during the 17-day period beginning on the last day of such 180-day period, then such 180-day period shall continue to apply until the expiration of the 17-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

Offering Price Determination

Prior to this offering, there has been no public market for our common stock. The initial public offering price will be negotiated between the representative and us. In determining the initial public offering price of our common stock, the representative will consider:

•	prevailing market conditions;

•	estimates of our business potential and earning prospects;

•	our historical performance and capital structure;

•	an overall assessment of our management; and

•	the consideration of these factors in relation to market valuation of companies in related businesses.

Distribution Standards

In connection with the listing of our common stock on the New York Stock Exchange, the underwriters will undertake to sell our common stock in a manner such that we satisfy the following New York Stock Exchange standards prior to trading: (1) maintain at least 2,000 U.S. stockholders of 100 shares or more; (2) maintain at least 1,100,000 publicly held shares outstanding in the United States; and (3) maintain aggregate market value of publicly held shares of at least $60 million in the United States.

Indemnification

We have agreed to indemnify the underwriters against certain liabilities relating to the offering, including liabilities under the Securities Act, liabilities arising from breaches of the representations

and warranties contained in the underwriting agreement, and to contribute to payments that the underwriters may be required to make for these liabilities.

Discretionary Shares

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares of our common stock offered by them.

Stabilization, Short Positions and Penalty Bids

The underwriters may engage in over-allotment, stabilizing transactions, syndicate covering transactions and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock, in accordance with Regulation M under the Exchange Act:

•

Over-allotment involves sales by the underwriters of shares of common stock in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option, in whole or in part, or purchasing shares in the open market.

•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•	Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we, nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we, nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Stamp Taxes

Purchasers of the shares of our common stock offered in this prospectus may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to

the offering price listed on the cover page of this prospectus. Accordingly, we urge you to consult a tax advisor with respect to whether you may be required to pay those taxes or charges, as well as any other tax consequences that may arise under the laws of the country of purchase.

Electronic Distribution

A prospectus in electronic format may be made available on Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Relationships

Certain of the underwriters have performed and may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses. Certain of the underwriters have and may, from time to time, engage in transactions with or perform services for us in the ordinary course of their business.

Foreign Securities Laws Restrictions

Prior to the expiry of a period of six months from the closing date of this offering, no common stock may be offered or sold, as the case many be, to persons in the United Kingdom, except to persons whose ordinary activities involve them acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their businesses or otherwise in circumstances which have not resulted and will not result in an offer to the public in the United Kingdom within the meaning of the Public Offers of Securities Regulations 1995, as amended, or the Regulations. Any invitation or inducement to engage in investment activity (within the meaning of section 21 of the Financial Services and Markets Act 2000, or FSMA) received in connection with the issue or sale of any common stock may only be communicated or caused to be communicated in circumstances in which section 21(1) of the FSMA does not apply to us. All applicable provisions of the Regulations and of the FSMA with respect to anything done in relation to the common stock in, from or otherwise involving the United Kingdom must be complied with.

Any shares of common stock that are offered, as part of their initial distribution or by way of re-offering, in The Netherlands shall, in order to comply with the Netherlands Securities Market Supervision Act 1995, only be offered, and such an offer shall only be announced in writing (whether electronically or otherwise), to individuals or legal entities in The Netherlands who or which trade or invest in securities in the conduct of a business or profession (which includes banks, securities intermediaries (including dealers and brokers), insurance companies, pension funds, collective investment institutions, central governments, large international and supranational organizations, other institutional investors and other parties, including treasury departments of commercial enterprises, which as an ancillary activity regularly invest in securities), or Professional Investors, provided that in the offer and in any documents or advertisements in which a forthcoming offering of common stock is publicly announced (whether electronically or otherwise) it is stated that such offer is and will be exclusively made to such Professional Investors.

VALIDITY OF COMMON STOCK

The validity of the shares of common stock offered hereby will be passed upon for us by Chadbourne & Parke LLP, New York, New York, and for the underwriters by White & Case LLP, New York, New York. Chadbourne & Parke LLP has from time to time represented Lehman Brothers, Inc. on unrelated matters. White & Case LLP has from time to time represented one of our subsidiaries on unrelated matters.

EXPERT

Our (Ormat Technologies, Inc.) financial statements as of December 31, 2002 and 2003 and for each of the three years in the period ended December 31, 2003 and those of Puna Geothermal Venture as of December 31, 2002 and 2003 and for the year ended December 31, 2002 and for the period from January 1, 2003 to December 10, 2003, and for the period from December 11, 2003 to December 31, 2003, Combined Heber and Affiliates as of December 31, 2002 and December 17, 2003, and for the years ended December 31, 2001 and 2002, and for the period from January 1, 2003 to December 17, 2003, and Mammoth-Pacific, L.P. as of December 31, 2002 and September 30, 2003 and for the year ended December 31, 2002 and the nine months ended September 30, 2003, included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting. The report on Ormat Technologies, Inc. contains an explanatory paragraph relating to the restatement of the financial statements as described in Note 20 to the financial statements. The report on Combined Heber and Affiliates contains an explanatory paragraph indicating that Heber and Affiliates filed a petition for reorganization under the provisions of Chapter 11 of the Bankruptcy Code on April 1, 2002 and emerged from bankruptcy on December 18, 2003.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules, and amendments to the registration statement) under the Securities Act with respect to the shares of common stock offered by this prospectus. This prospectus does not contain all the information set forth in the registration statement. For further information with respect to us and the shares of common stock to be sold in this offering, we refer you to the registration statement. Statements contained in this prospectus as to the contents of any contract, agreement or other document are only summaries. With respect to any contract, agreement or document filed as an exhibit to the registration statement, we refer you to the exhibit for a copy of such contract, agreement or other document, and each such statement in this prospectus regarding such contract, agreement or document is qualified by reference to such exhibit. Our website is located at http://www.ormat.com. Information contained on our company Web site is not a part of this prospectus.

Upon completion of this offering, we will become subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended, and, as a result, will file periodic and current reports, proxy statements, and other information with the SEC. You may read and copy this information at the Public Reference Room of the SEC located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. Copies of all or any part of the registration statement may be obtained from the SEC's offices upon payment of fees prescribed by the SEC. The SEC maintains an Internet site that contains periodic and current reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC's website is http://www.sec.gov.

INDEX TO FINANCIAL STATEMENTS

Consolidated Financial Statements of Ormat Technologies, Inc. and Subsidiaries
Report of Independent Registered Public Accounting Firm					F-3
Consolidated Financial Statements as of December 31, 2002, and 2003 and for each of the three years in the period ended December 31, 2003, including Unaudited Consolidated Financial Statements as of June 30, 2004 and for the six-month periods ended June 30, 2003 and 2004:
Consolidated Balance Sheets					F-4
Consolidated Statements of Operations and Comprehensive Income (Loss)					F-5
Consolidated Statements of Stockholder's Equity					F-6
Consolidated Statements of Cash Flows					F-7
Notes to Consolidated Financial Statements					F-8
Financial Statements of Puna Geothermal Venture
Report of Independent Auditors					F-51
Financial Statements as of December 31, 2002 and 2003, and for the year ended December 31, 2002, for the period from January 1, 2003 to December 10, 2003 and for the period from December 11, 2003 to December 31, 2003, including Unaudited Financial Statements as of March 31, 2004 and for the three-month periods ended March 31, 2003 and 2004:
Balance Sheets					F-53
Statements of Operations					F-54
Statements of Partners' Equity					F-55
Statements of Cash Flows					F-56
Notes to Financial Statements					F-57
Combined Financial Statements of Heber and Affiliates
Report of Independent Auditors					F-65
Financial Statements as of December 31, 2002 and December 17, 2003, and for the years ended December 31, 2001 and 2002, and for the period from January 1, 2003 to December 17, 2003:
Balance Sheets					F-66
Statements of Operations					F-67
Statements of Partners' Capital					F-68
Statements of Cash Flows					F-69
Notes to Financial Statements					F-70
Financial Statements of Mammoth Pacific, L.P.
Report of Independent Auditors					F-79
Financial Statements as of December 31, 2002 and September 30, 2003, and for the year ended December 31, 2002, and for the nine-month period ended September 30, 2003, including Unaudited Financial Statements for the nine-month period ended September 30, 2002:
Balance Sheets					F-80
Statements of Operations					F-81
Statements of Partners' Capital					F-82
Statements of Cash Flows					F-83
Notes to Financial Statements					F-84

Ormat Technologies, Inc.
and Subsidiaries

Report on Audits of
Consolidated Financial Statements
As of December 31, 2002 and 2003, and for the years
ended December 31, 2001, 2002 and 2003 and
Unaudited Consolidated Financial Statements
As of June 30, 2004 and for six month periods
ended June 30, 2003 and 2004

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of
Ormat Technologies, Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income (loss), of stockholder's equity and of cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2002 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 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 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 11 to the financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets.

As discussed in Note 20, the consolidated financial statements have been restated for adjustments required to amounts due to/from Parent and stockholder's equity.

/s/ PricewaterhouseCoopers LLP

Sacramento, California
July 19, 2004, except for Note 20
as to which the date is September 26, 2004
and Note 21 as to which the
date is October 21, 2004

Ormat Technologies, Inc. and Subsidiaries
Consolidated Balance Sheets (dollars in thousands, except per share amounts)

				December 31,											December 31,
				2002				2003				June 30, 2004						2002				2003				June 30, 2004				Pro Forma Balance Sheet at June 30, 2004
												(unaudited)														(unaudited)				(unaudited)
				Restated				Restated							Restated				Restated
Assets	Assets			Assets
Current assets:	Current assets:			Current assets:
Cash and cash equivalents	Cash and cash equivalents			$	36,684			$	8,873			$	21,170		Cash and cash equivalents			$	36,684			$	8,873			$	21,170			$	13,870
Restricted cash and cash equivalents	Restricted cash and cash equivalents				8,010				16,371				37,145		Restricted cash and cash equivalents				8,010				16,371				37,145				37,145
Receivables:	Receivables:			Receivables:
Trade	Trade				20,713				28,689				33,445		Trade				20,713				28,689				33,445				33,445
Related entities	Related entities				1,756				1,939				1,722		Related entities				1,756				1,939				1,722				1,722
Other	Other				2,658				729				2,856		Other				2,658				729				2,856				2,856
Inventories, net	Inventories, net				5,948				3,712				7,456		Inventories, net				5,948				3,712				7,456				7,456
Costs and estimated earnings in excess of billings on uncompleted contracts	Costs and estimated earnings in excess of billings on uncompleted contracts				—				1,922				3,586		Costs and estimated earnings in excess of billings on uncompleted contracts				—				1,922				3,586				3,586
Prepaid expenses and other	Prepaid expenses and other				1,853				2,091				1,991		Prepaid expenses and other				1,853				2,091				1,991				1,991
Total current assets	Total current assets				77,622				64,326				109,371		Total current assets				77,622				64,326				109,371				102,071
Restricted cash and cash equivalents	Restricted cash and cash equivalents				—				—				25,805		Restricted cash and cash equivalents				—				—				25,805				25,805
Unconsolidated investments	Unconsolidated investments				8,363				46,760				48,459		Unconsolidated investments				8,363				46,760				48,459				48,459
Deposits and other	Deposits and other				12,395				13,071				14,367		Deposits and other				12,395				13,071				14,367				14,367
Property, plant and equipment, net	Property, plant and equipment, net				152,342				344,015				472,217		Property, plant and equipment, net				152,342				344,015				472,217				472,217
Construction-in-process	Construction-in-process				27,776				35,118				41,745		Construction-in-process				27,776				35,118				41,745				41,745
Deferred financing costs, net	Deferred financing costs, net				1,624				7,843				16,461		Deferred financing costs, net				1,624				7,843				16,461				16,461
Intangible assets, net	Intangible assets, net				7,256				32,005				49,758		Intangible assets, net				7,256				32,005				49,758				49,758
Total assets	Total assets			$	287,378			$	543,138			$	778,183		Total assets			$	287,378			$	543,138			$	778,183			$	770,883
Liabilities and Stockholder's Equity	Liabilities and Stockholder's Equity			Liabilities and Stockholder's Equity
Current liabilities:	Current liabilities:			Current liabilities:
Short-term debt	Short-term debt			$	65,000			$	—			$	—		Short-term debt			$	65,000			$	—			$	—			$	—
Accounts payable and accrued expenses	Accounts payable and accrued expenses				18,650				27,479				34,764		Accounts payable and accrued expenses				18,650				27,479				34,764				34,764
Billings in excess of costs and estimated earnings on uncompleted contracts	Billings in excess of costs and estimated earnings on uncompleted contracts				3,153				7,843				8,042		Billings in excess of costs and estimated earnings on uncompleted contracts				3,153				7,843				8,042				8,042
Current portion of long-term debt:	Current portion of long-term debt:			Current portion of long-term debt:
Limited and non-recourse	Limited and non-recourse				11,036				15,686				21,260		Limited and non-recourse				11,036				15,686				21,260				21,260
Full recourse	Full recourse				8,271				10,490				30,489		Full recourse				8,271				10,490				30,489				30,489
Senior secured notes (non-recourse)	Senior secured notes (non-recourse)				—				—				3,279		Senior secured notes (non-recourse)				—				—				3,279				3,279
Due to Parent	Due to Parent				51,365				151				413		Due to Parent				51,365				151				413				413
Total current liabilities	Total current liabilities				157,475				61,649				98,247		Total current liabilities				157,475				61,649				98,247				98,247
Long-term debt, net of current portion:	Long-term debt, net of current portion:			Long-term debt, net of current portion:
Limited and non-recourse	Limited and non-recourse				44,171				193,251				165,449		Limited and non-recourse				44,171				193,251				165,449				165,449
Full recourse	Full recourse				32,329				41,061				35,317		Full recourse				32,329				41,061				35,317				35,317
Senior secured notes (non-recourse)	Senior secured notes (non-recourse)				—				—				186,506		Senior secured notes (non-recourse)				—				—				186,506				186,506
Notes payable to Parent	Notes payable to Parent				—				177,004				193,852		Notes payable to Parent				—				177,004				193,852				193,852
Other liabilities	Other liabilities				1,549				1,469				1,429		Other liabilities				1,549				1,469				1,429				1,429
Deferred income taxes	Deferred income taxes				11,951				13,886				15,928		Deferred income taxes				11,951				13,886				15,928				15,928
Liabilities for severance pay	Liabilities for severance pay				9,534				9,993				10,135		Liabilities for severance pay				9,534				9,993				10,135				10,135
Asset retirement obligation	Asset retirement obligation				—				5,737				8,019		Asset retirement obligation				—				5,737				8,019				8,019
Total liabilities	Total liabilities				257,009				504,050				714,882		Total liabilities				257,009				504,050				714,882				714,882
Minority interest in net assets of subsidiaries	Minority interest in net assets of subsidiaries				2,532				2,113				69		Minority interest in net assets of subsidiaries				2,532				2,113				69				69
Commitments and contingencies (Notes 6, 11, 17 and 18)	Commitments and contingencies (Notes 6, 11, 17 and 18)			Commitments and contingencies (Notes 6, 11, 17 and 18)
Stockholder's equity:	Stockholder's equity:			Stockholder's equity:
Common stock, par value $0.001 per share; 200,000,000 shares authorized; 23,214,281, 23,214,281 and 24,374,996 shares issued and outstanding	Common stock, par value $0.001 per share; 200,000,000 shares authorized; 23,214,281, 23,214,281 and 24,374,996 shares issued and outstanding				23				23				24		Common stock, par value $0.001 per share; 200,000,000 shares authorized; 23,214,281, 23,214,281 and 24,374,996 shares issued and outstanding				23				23				24				24
Additional paid-in capital	Additional paid-in capital				6,988				7,002				27,001		Additional paid-in capital				6,988				7,002				27,001				27,001
Divisional deficit	Divisional deficit				(6,599	)			(11,263	)			(10,293	)	Divisional deficit				(6,599	)			(11,263	)			(10,293	)			—
Unearned stock-based compensation	Unearned stock-based compensation				(111	)			(86	)			(51	)	Unearned stock-based compensation				(111	)			(86	)			(51	)			(51	)
Retained earnings	Retained earnings				27,536				41,299				46,551		Retained earnings				27,536				41,299				46,551				28,958
Total stockholder's equity	Total stockholder's equity				27,837				36,975				63,232		Total stockholder's equity				27,837				36,975				63,232				55,932
Total liabilities and stockholder's equity	Total liabilities and stockholder's equity			$	287,378			$	543,138			$	778,183		Total liabilities and stockholder's equity			$	287,378			$	543,138			$	778,183			$	770,883

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

Ormat Technologies, Inc. and Subsidiaries
Consolidated Statements of Operations and Comperhensive Income (loss)
(dollars in thousands, except per share amounts)

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Revenues:
Electricity:
Energy and capacity				$	33,956			$	65,491			$	77,752			$	35,651			$	48,048
Lease					—				—				—				—				22,167
Total electricity					33,956				65,491				77,752				35,651				70,215
Products					13,959				20,138				41,688				16,022				29,491
					47,915				85,629				119,440				51,673				99,706
Cost of revenues:
Electricity:
Energy and capacity					12,536				33,482				46,726				22,165				29,440
Lease					—				—				—				—				11,172
Total electricity					12,536				33,482				46,726				22,165				40,612
Products					17,454				17,293				29,494				10,306				23,122
					29,990				50,775				76,220				32,471				63,734
Gross margin					17,925				34,854				43,220				19,202				35,972
Operating expenses:
Research and development expenses					1,729				1,503				1,391				871				1,202
Selling and marketing expenses					6,535				6,051				7,087				2,666				3,946
General and administrative expenses					5,444				7,073				9,252				4,053				5,219
Operating income					4,217				20,227				25,490				11,612				25,605
Other income (expense):
Interest income					1,323				609				607				299				431
Interest expense					(4,333	)			(6,179	)			(8,120	)			(3,835	)			(19,475	)
Foreign currency translation and transaction gain (loss)					305				(323	)			(316	)			(151	)			(397	)
Other non-operating income					300				1,195				464				278				145
Income from continuing operations before income taxes, minority interest, and equity in income of investees					1,812				15,529				18,125				8,203				6,309
Income tax provision					(3,065	)			(6,135	)			(2,506	)			(2,173	)			(1,957	)
Minority interest in earnings of subsidiaries					(645	)			(1,194	)			(519	)			(399	)			(108	)
Equity in income of investees					166				314				559				188				2,035
Income (loss) from continuing operations					(1,732	)			8,514				15,659				5,819				6,279
Discontinued operations (Note 2):
Loss from operations of discontinued activities in Kazakhstan					(4,681	)			(3,114	)			—				—				—
Loss on sale of Kazakhstan operations					—				(6,444	)			—				—				—
Income (loss) before cumulative effect of change in accounting principle					(6,413	)			(1,044	)			15,659				5,819				6,279
Cumulative effect of change in accouting principle
(net of tax benefit of $125)					—				—				(205	)			(205	)			—
Net income (loss)					(6,413	)			(1,044	)			15,454				5,614				6,279
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments					(1,133	)			(51	)			—				—				—
Reclassification adjustments					—				1,184				—				—				—
Comprehensive income (loss)				$	(7,546	)		$	89			$	15,454			$	5,614			$	6,279
Basic and diluted income (loss) per share:
Income (loss) from continuing operations				$	(0.07	)		$	0.37			$	0.67			$	0.25			$	0.27
Loss from discontinued operations					(0.20	)			(0.41	)			—				—				—
Cumulative effect of change in accounting principle					—				—				(0.01	)			(0.01	)			—
Net income (loss)				$	(0.27	)		$	(0.04	)		$	0.66			$	0.24			$	0.27
Weighted average number of shares outstanding					23,214,281				23,214,281				23,214,281				23,214,281				23,227,036

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

Ormat Technologies, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity (dollars in thousands)

				Common Stock								Additional Paid-in Capital				Divisional Deficit				Unearned Stock-based Compensation				Retained Earnings				Accumulated Other Comprehensive Loss				Total
				Shares				Amount
				(in thousands)												(Restated)								(Restated)								(Restated)
Balance, December 31, 2000					23,214			$	23			$	6,839			$	6,539			$	—			$	15,600			$	—			$	29,001
Foreign currency translation adjustments					—				—				—				—				—				—				(1,133	)			(1,133	)
Contribution from Parent					—				—				—				1,511				—				—				—				1,511
Net income (loss)					—				—				—				(12,550	)			—				6,137				—				(6,413	)
Balance, December 31, 2001					23,214				23				6,839				(4,500	)			—				21,737				(1,133	)			22,966
Foreign currency translation adjustments					—				—				—				—				—				—				(51	)			(51	)
Reduction of accumulated foreign currency translation losses					—				—				—				—				—				—				1,184				1,184
Unearned stock-based compensation					—				—				149				—				(149	)			—				—				—
Amortization of unearned stock-based compensation					—				—				—				—				38				—				—				38
Contribution from Parent					—				—				—				4,744				—				—				—				4,744
Net income (loss)					—				—				—				(6,843	)			—				5,799				—				(1,044	)
Balance, December 31, 2002					23,214				23				6,988				(6,599	)			(111	)			27,536				—				27,837
Unearned stock-based compensation					—				—				14				—				(14	)			—				—				—
Amortization of unearned stock-based compensation					—				—				—				—				39				—				—				39
Distribution to Parent					—				—				—				(6,355	)			—				—				—				(6,355	)
Net income					—				—				—				1,691				—				13,763				—				15,454
Balance, December 31, 2003					23,214				23				7,002				(11,263	)			(86	)			41,299				—				36,975
Amortization of unearned stock- based compensation (unaudited)					—				—				—				—				35				—				—				35
Conversion of note payable to Parent to equity (unaudited)					1,161				1				19,999				—				—				—				—				20,000
Distribution to Parent (unaudited)					—				—				—				(57	)			—				—				—				(57	)
Net income (unaudited)					—				—				—				1,027				—				5,252				—				6,279
Balance, June 30, 2004 (Unaudited)					24,375			$	24			$	27,001			$	(10,293	)		$	(51	)		$	46,551			$	—			$	63,232

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

Ormat Technologies, Inc. and Subsidiaries
Consolidated Statements of Cash Flows (dollars in thousands)

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Cash flows from operating activities:
Net income (loss)				$	(6,413	)		$	(1,044	)		$	15,454			$	5,614			$	6,279
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization					11,245				14,477				16,619				7,270				14,258
Minority interest in earnings of subsidiaries					645				1,194				519				398				108
Loss on sale of subsidiary					—				6,444				—				—				—
Equity in income of investees					(166	)			(314	)			(559	)			(188	)			(2,035	)
Distributions from unconsolidated investments					—				—				—				—				5,182
Provision for (recovery of) doubtful accounts					465				(256	)			(234	)			—				—
Deferred income tax provision					2,782				5,883				2,060				2,172				1,592
Cumulative effect of change in accounting principle					—				—				205				205				—
Changes in operating assets and liabilities, net of sale and acquisitions:
Receivables					1,242				(10,516	)			1,343				1,146				(4,568	)
Costs and estimated earnings in excess of billings on uncompleted contracts					—				—				(1,922	)			—				(1,664	)
Inventories					(1,058	)			408				2,236				412				(3,744	)
Prepaid expenses and other					(1,106	)			1,628				32				1,145				16
Deposits and other					1,763				(2,033	)			(231	)			(60	)			1,526
Accounts payable and accrued expenses					1,742				(3,676	)			5,266				(1,666	)			4,771
Due from/to related entities, net					214				195				(150	)			(82	)			446
Billings in excess of costs and estimated earnings on uncompleted contracts					74				(581	)			4,691				—				199
Liabilities for severance pay					(431	)			(175	)			459				419				142
Asset retirement obligation					—				—				231				—				152
Net cash provided by operating activities					10,998				11,634				46,019				16,785				22,660
Cash flows from investing activities:
Change in restricted cash and cash equivalents					254				(3,343	)			(2,403	)			688				(50,724	)
Capital expenditures					(32,265	)			(22,710	)			(25,296	)			(16,940	)			(6,615	)
Decrease of cash resulting from deconsolidation of OLCL					—				—				—				—				(1,800	)
Increase in severance fund asset, net					(565	)			(448	)			(446	)			(220	)			(217	)
Repayment from joint ventures					651				1,674				794				413				485
Cash received from sale of subsidiary					—				3,966				—				—				—
Cash paid for acquisitions, net of cash received					(30,511	)			(39,660	)			(257,829	)			—				(174,258	)
Net cash used in investing activities					(62,436	)			(60,521	)			(285,180	)			(16,059	)			(233,129	)
Cash flows from financing activities:
Due to Parent, net					9,277				5,154				(582	)			22,526				—
Proceeds from issuance of notes payable to Parent					—				—				126,339				—				92,848
Payments of notes payable to Parent					—				—				—				—				(56,000	)
Distributions to minority shareholders					(890	)			(1,320	)			(940	)			(440	)			—
Contributions from (distributions to) Parent					1,511				4,744				(6,355	)			(12	)			(57	)
Proceeds from issuance of short-term debt					—				50,000				—				—				—
Proceeds from issuance of long-term debt					51,662				20,279				178,018				13,518				210,000
Payments of long-term debt					(6,698	)			(6,437	)			(23,336	)			(55,284	)			(10,408	)
Payments of short-term debt					—				—				(55,000	)			——				—
Deferred debt issue costs					—				—				(6,794	)			—				(9,448	)
Payment for interest rate cap					—				—				—				—				(3,820	)
Deferred stock offering costs					—				—				—				—				(349	)
Net cash provided by (used in) financing activities					54,862				72,420				211,350				(19,692	)			222,766
Effect of foreign currency translation adjustments					(293	)			(51	)			—				—				—
Net increase (decrease) in cash and cash equivalents					3,131				23,482				(27,811	)			(18,966	)			12,297
Cash and cash equivalents, beginning of the period					10,071				13,202				36,684				36,684				8,873
Cash and cash equivalents, end of the period				$	13,202			$	36,684			$	8,873			$	17,718			$	21,170
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest				$	4,248			$	5,055			$	4,937			$	658			$	13,289
Income taxes				$	297			$	453			$	—			$	—			$	—
Supplemental non-cash investing and financing activities:
Effect of adopting SFAS No. 143:
Asset retirement cost				$	—			$	—			$	2,475			$	—			$	—
Asset retirement obligation				$	—			$	—			$	2,805			$	—			$	—
Conversion of amounts due to Parent to notes payable to Parent				$	—			$	—			$	50,665			$	—			$	—
Conversion of note payable to Parent to equity					—				—				—				—			$	20,000
Accounts payable related to purchases of fixed assets				$	71			$	—			$	748			$	—			$	1,306
Deconsolidation of OLCL Non-cash Assets				$	—			$	—			$	—			$	—			$	3,081
Net deferred tax liabilities resulting from the change in functional currency of the Company's Kazakhstan operations				$	839			$	—			$	—			$	—			$	—
Business acquisitions — See Note 2

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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

1.    Business and Significant Accounting Policies

Business

Ormat Technologies, Inc. ("Company"), a wholly owned subsidiary of Ormat Industries Ltd. ("Parent"), is engaged in the geothermal and recovered energy business, including supply of equipment that is manufactured by the Company and design and construction of such power plants for projects owned by the Company or for third parties. The Company owns and operates geothermal power plants in various countries, including Kenya, Nicaragua, the Philippines, Guatemala and the United States of America ("U.S."). The Company also owned coal fueled heating and electricity power plants and distribution facilities in the Republic of Kazakhstan ("Kazakhstan"), that were sold on September 16, 2002 (Note 2). The Company's equipment manufacturing operations are located in Israel.

Several of the Company's power plant facilities are listed as Qualifying Facilities (QF) under the Public Utility Regulatory Policies Act (PURPA). The related power purchase agreements for such facilities are dependent upon the Company maintaining the QF status.

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, comprising 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 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.

Additionally, on June 29, 2004, the outstanding and issued 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, $20,000 outstanding pursuant to the note payable to 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 $20,000 and no gain or loss was recognized as a result thereof.

As further discussed in Note 21, on October 21, 2004, the board of directors approved a 1-for-1.325444 reverse stock split of the Company's common stock.

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, an 85% interest in OrYunnan Geothermal Co. Ltd. ("OrYunnan"), a 79% interest in Ormat Leyte Co, Ltd. ("OLCL"), a 50% interest in Karaganda Holding Company ("KHC") prior to March 12, 2002, and a 100% interest in KHC from March 12, 2002 to September 16, 2002. All intercompany accounts and transactions are eliminated.

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 and YPGD is to contribute, for the remaining 15% ownership interest, $450. 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 Republic of China.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

The Company's consolidated balance sheets include 100% of the assets and liabilities of OrYunnan and of OLCL prior to March 31, 2004. The unrelated entity's 15% interests in OrYunnan, and 21% interest in OLCL prior to March 31, 2004, have been reflected as "Minority interest in net assets of subsidiaries" in the Company's consolidated balance sheets and the earnings therefrom have been reflected on the consolidated statements of operations and comprehensive income for all periods presented and have been reflected in "Minority interest in earnings of subsidiaries". Intercompany accounts and transactions have been eliminated in the consolidation.

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 consolidated method of accounting for the three month period ended March 31, 2004, and 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 $4.3 million, which is the Company's net investment at June 30, 2004 (unaudited).

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 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 to acquiring the tangible net assets of the power generation business, OSL has assumed the title and interest to certain related contracts and liabilities and rights under agreements with employees and

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

consultants, and obtained a perpetual license of all intellectual property pertaining to the power generation business from the Parent. Further, in connection with binding work and product orders that the Parent had with its customers, which were transferred to OSL as part of the acquisition, OSL has agreed to pay the Parent a commission ranging from 2.5% to 5% of sales by OSL related to such work and product orders.

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, services including 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 through 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, adjusted annually for the Israeli Consumer Price Index, plus tax and other costs to maintain the properties. The term of the rental agreement is for 59 months and expires in June 2009.

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 accompanying financials statements for all periods 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 accompanying statement of stockholder's 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 will be reclassified to additional paid-in capital.retained earnings. Retained earnings in the accompanying statement of stockholder's equity for all periods presented represents the retained earnings of the Company prior to the acquition 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 periods presented.

The statement of operations for OSL was carved out using specific identification for revenues and cost of goods sold, research and development expense, interest income and expense, and selling, marketing, general and administrative expenses. Income tax expense was recalculated based on the separate return method pursuant to Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes (SFAS No. 109).

The balance sheet for OSL was carved out of the Parent using specific identification of assets and liabilities. Certain assets and liabilities were allocated in accordance with the terms of the signed definitive agreements.

The OSL financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and in a manner which management believes is reasonable and appropriate. All significant intercompany transactions and accounts have been eliminated. The allocations and estimates used may not necessarily reflect the financial position, operating results and cash flows for the periods presented had OSL been operated as a separate entity.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Of the $11 million purchase price, the Company paid $4.8 million in cash and assumed $6.2 million in debt and other liabilities. As the Company's purchase of the power generation business effective July 1, 2004 has been accounted as a transfer of assets between entities under common control, the excess of the consideration paid over the historical net book value of the purchased business will be recorded as a distribution to the Parent, which will have the effect of reducing stockholder's equity by approximately $4.8 million at July 1, 2004. Because the deferred taxes have a full valuation allowance, there was no tax effect for the difference between the book and tax basis of the purchased assets and liabilities. Additionally, on July 1, 2004, the Company will be reclassifying the divisional equity to additional paid-in capital.retained earnings.

Interim financial statements

The interim financial statements, including information contained in the notes to the financial statements, as of June 30, 2004, and for the six months ended June 30, 2003 and 2004, is unaudited, however, in the opinion of the Company, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for such interim periods. The interim amounts presented are not necessarily indicative of the results of operations of the Company for the year ending December 31, 2004.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Cash and cash equivalents

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

Restricted cash and cash equivalents

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 and cash equivalents. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts are invested primarily in money market accounts. The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable.

The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31, 2002 and 2003, and June 30, 2004 (unaudited), the Company had deposits in four, six and seven respectively, U.S. financial institutions that were federally insured up to $100 per financial institution. At December 31, 2002 and 2003, and June 30, 2004 (unaudited), the Company's deposits in foreign countries of approximately $9,642, $9,927, and $5,000 respectively, were not insured.

At December 31, 2002 and 2003, and June 30, 2004 (unaudited), accounts receivable related to operations in foreign countries amounted to approximately $15,093, $13,029, and $14,170, respectively. At December 31, 2002 and 2003, and June 30, 2004 (unaudited), accounts receivable from the Company's major customers (Note 15) amounted to approximately 61%, 57% and 65% of the Company's accounts receivable, respectively. The Company performs ongoing credit evaluations of its customers' financial condition. The Company requires the customer in Nicaragua to provide a cash security arrangement for its payment obligations. The Company has historically been able to collect on all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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, which approximates the first-in first-out method, and is stated net of provision for slow-moving and obsolescence, which was not significant.

Deposits and other

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

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 costs are expensed. Power plants operated by the Company are depreciated using the straight-line method over

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

the term of the relevant power purchase agreement (Note 13). The geothermal power plants in the Philippines and Nicaragua are 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:

Leasehold improvements				25 years
Machinery and equipment - manufacturing				10 years
Machinery and equipment - computers				3 years
Office equipment - furniture and fixtures				15 years
Office equipment - other				10 years
Automobiles				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 plants. 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 approximately $974, $201, and $297 for the years ended December 31, 2001, 2002 and 2003, respectively. No amounts were capitalized during the six months ended June 30, 2003 and 2004 (unaudited).

Intangible assets

Intangible assets consist of allocated acquisition cost of power purchase agreements, that are amortized over the 15 to 20-year terms of the agreements using the straight-line method.

Deferred financing costs

Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs are presented as interest expense in the statement of operations. Accumulated amortization related to deferred financing costs amounted to $0, $576 and $1,406 at December 31, 2002 and 2003 and June 30, 2004 (unaudited), respectively. Amortization expense for the years ended December 31, 2001, 2002 and 2003 and for the six months ended June 30, 2003 and 2004 (unaudited) amounted to $0, $0, $576, $288 and $830, respectively.

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

Long-lived assets 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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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 exceed 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

Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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 that a company must 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. Gain or loss on contracts that initially qualify for cash flow hedge accounting is included as a component of other comprehensive income and are subsequently reclassified into earnings when interest on the related debt is paid. Gain or loss on contracts that are not designated to qualify as a cash flow hedge is included as a component of interest expense.

The Company is subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15 (DIG Issue No. C15), Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also under DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. The Company has power sales agreements that qualify as derivative instruments under DIG Issue No. C15 because they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. The adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on the Company's consolidated financial position and results of operations.

In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 superseded DIG Issue No. C11 Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception, and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company). In conjunction with initially applying the implementation guidance, DIG Issue No.C20 requires contracts that did not previously qualify for the normal purchases normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortized such fair value over the remaining contract period. Upon adoption of DIG Issue No. C20, the Company elected the normal purchase and normal sales scope exception under FAS No. 133 related

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

to its power purchase agreements. Such adoption did not have a material impact on the Company's consolidated financial position and results of operations.

Foreign currency translation

The functional currency of all foreign entities is the reporting currency (U.S. dollars). 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.

The Company's functional currency of certain Kazakhstan activities was considered to be the local currency, accordingly all assets and liabilities were translated at the exchange rate as of the balance sheet date. Revenues, costs and expenses were translated at the weighted average exchange rate for

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

the period. Translation adjustments were accumulated in a separate component of equity. Upon sale of the Kazakhstan business (Note 2), the accumulated foreign currency translation losses were eliminated.

Comprehensive income reporting

The Company accounts for comprehensive income with SFAS No. 130, Reporting Comprehensive Income, which requires comprehensive income and its components to be reported when a company has items of other comprehensive income. Comprehensive income includes net income plus other comprehensive income, which for the Company consists of foreign currency translation adjustments and is reported as a separate component of stockholder's equity rather than in the current year's earnings. The changes to accumulated other comprehensive loss for all periods presented consist entirely of changes in foreign currency translation adjustments, which changes have been presented in the accompanying statements of stockholder's equity. Such adjustments did not have any tax effect as Karaganda Holding Company ("KHC") was not in a taxable position due to its recurring losses that resulted in a full valuation of deferred taxes. In connection with the sale of KHC that is further discussed in Note 2, the Company recorded a reduction of $1,184 in accumulated foreign currency translation losses, and included such accumulated losses as a component of "loss on sale of Kazakhstan operations" in determining the net loss for the year ended December 31, 2002.

Revenue and cost of revenues

Revenues are primarily related to (i) sale of electricity from geothermal power plants owned and operated by the Company; and (ii) geothermal and recovered energy power plant equipment engineering, sale, construction and installation and operating services.

Revenues related to the sale of electricity from geothermal 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) acquired as part of the projects purchased since July 1, 2003 (Note 2), revenues related to the lease element of the PPA are included as "lease" revenues, with the remaining revenues related to the production and delivery of energy presented as "energy and capacity".

Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts. Revenue from the construction of geothermal and recovered energy power plant equipment on behalf of others is 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, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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 income 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. A provision for warranty reserve is recorded currently for the estimated costs that may be incurred under its warranty. Such reserve is estimated based on past experience, which have historically been immaterial.

Research and development

Research and development costs incurred by OSL for the development of existing and new geothermal, recovered energy, and remote power technologies, are expensed as incurred. Grants

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

received from the Office of the Chief Scientist ("OCS") of the Israeli Government are offset against the related research and development expenses. Such grants amounted to $1,030, $531 and $142 during the years ended December 31, 2001, 2002, and 2003, respectively. No grants were received during the six months ended June 30, 2003 and 2004 (unaudited). During 2003, OSL discontinued requesting any further grants from OCS.

Advertising expense

Advertising costs are expensed as incurred and totaled $118, $72, $58, $26, and $43 for the years ended December 31, 2001, 2002, and 2003, and the six months ended June 30, 2003 and 2004 (unaudited), respectively.

Patent expense

Patents are internally developed, and therefore costs are expensed as incurred and totaled $404, $436, $377, $171, and $172 for the years ended December 31, 2001, 2002 and 2003, and six months ended June 30, 2003 and 2004 (unaudited), respectively.

Income taxes

Income taxes are accounted for using an asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law; the effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized.

Pro forma balance sheet (unaudited)

The pro forma effects of the purchase of OSL (Note 1) and the payment of the dividend to the Parent (Note 19) are unaudited and have been reflected in the accompanying pro forma balance sheet at June 30, 2004. Relating to the purchase of OSL, the $4.8 million cash payment has been reflected as a decrease in cash and a corresponding decrease in retained earnings. The divisional deficit of OSL of $10.3 million at June 30, 2004, has been recorded to retained earnings. The dividend payment on October 21, 2004 to the Parent has been reflected as a decrease to cash and a corresponding decrease to retained earnings.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Income (loss) per share

Basic income (loss) per share is computed by dividing income (loss) available to common shareholders by the weighted average number of common shares outstanding for the period. The Company does not have any equity instruments that are dilutive. The stock options granted to employees of the Company in the Parent's stock are not dilutive to the Company's earnings per share.

Stock-based compensation

The Company accounts for stock-based compensation based on the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), and FASB Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation, and other related interpretations which states that no compensation expense is recorded for stock options or other stock-based awards to employees that are granted with an exercise price equal to or above the estimated fair value per share of common stock on the grant date. In the event that stock options are granted at a price lower than the fair market value at that date, the difference between the fair market value of the common stock and the exercise price of the stock options is recorded as unearned compensation. Unearned compensation is amortized to compensation expense over the vesting period applicable to the stock option. The Company has adopted the disclosure requirements of SFAS No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123"), as it relates to stock options granted to employees, which requires proforma net income be disclosed based on the fair value of the options granted at the date of the grant.

The Company calculated the fair value of each option on the date of grant using the Black-Scholes option pricing model using the following assumptions:

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

				Year Ended December 31,												Six months ended June 30,
				2001				2002				2003				2004
Risk-free interest rates					4.8	%			4.7	%			4.7	%			4.7	%
Expected lives (in years)					5				5				5				5
Dividend yield					0	%			0	%			0	%			0	%
Expected volatility					44	%			37	%			31	%			28	%

Had compensation cost for the options granted to employees of the Company been determined based on the fair value method prescribed by SFAS No. 123, the Company's proforma net income (loss) and earnings (loss) per share would have been as follows:

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Net income (loss):
As reported				$	(6,413	)		$	(1,044	)		$	15,454			$	5,614			$	6,279
Add: Total stock-based employee compensation expense included in reported net income, net of tax					—				24				24				12				12
Deduct: Total stock-based employee compensation expense determined under fair value based method, net of tax					—				(94	)			(175	)			—				—
Pro forma net income (loss)				$	(6,413	)		$	(1,114	)		$	15,303			$	5,626			$	6,291
Basic and diluted net income (loss) per share:
As reported				$	(0.27	)		$	(0.04	)		$	0.66			$	0.24			$	0.27
Pro forma				$	(0.27	)		$	(0.05	)		$	0.66			$	0.24			$	0.27

Fair value of financial instruments

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

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

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and hedging activities under SFAS No. 133. The amendments in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. SFAS No. 149 clarifies the circumstances under which a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and clarifies when a derivative contains a financing component that warrants special reporting in

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

the statement of cash flows. The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The Company adopted the provisions of SFAS No. 149 effective July 1, 2003, which did not have a material impact on its consolidated results of operations and financial position as of December 31, 2003.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability because that financial instrument embodies an obligation of the issuer. The requirements of SFAS No. 150 are effective for financial instruments entered into or

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

modified after May 31, 2003, effective the first interim period beginning after June 15, 2003. For financial instruments created prior to the issuance date of SFAS No. 150, transition shall be achieved by reporting the cumulative effect of a change in accounting principle. The Company adopted the provisions of SFAS No. 150 effective July 1, 2003, which did not have a material impact on its consolidated results of operations and financial position as of December 31, 2003.

In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combination on or after July 1, 2003. The adoption of EITF No. 01-8 effective July 1, 2003 did not have a material effect to the Company's financial position or results of operations. As further discussed in Note 13, power purchase agreements acquired as part of the projects purchased since July 1, 2003 (Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects – see Note 2), contain lease elements within the scope of SFAS 13. Lease revenue related to the Heber 1 and 2 projects from the date of acquisition (December 18, 2003) to December 31, 2003 was not material.

2.    Business Acquisitions and Sale

Karaganda Holding Company ("KHC")

KHC was established for the purpose of generating power and selling and distributing electricity and heating power in Kazakhstan. Prior to March 12, 2002, the Company had a 50% ownership interest in KHC. Effective March 12, 2002, the Company purchased the remaining 50% interest in KHC for $500. Such transaction was accounted for using the purchase method, and the allocation of the $500 purchase price was as follows:

Cash and cash equivalents				$	2,541
Accounts receivable assumed					6,988
Property, plant and equipment					9,089
Other assets assumed					3,056
Accounts payable and accrued liabilities assumed					(9,747	)
Long-term debt assumed					(10,632	)
Deferred tax liabilities assumed					(795	)
Total purchase price allocation				$	500

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

On September 16, 2002, the Company sold all of its ownership interest in KHC to a third party for approximately $4.1 million, less $184 of costs related to the sale. The Company recognized a loss on the sale of this subsidiary equal to approximately $6.4 million during 2002, in addition to the operational losses incurred prior to such sale. The net assets of KHC on the date of the sale were as follows:

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Accounts receivable				$	12,718
Inventory, prepaid expenses and other					5,035
Property, plant and equipment					27,061
Accounts payable and accrued liabilities					(13,966	)
Long-term debt					(19,988	)
Deferred tax liabilities					(1,634	)
Accumulated foreign currency translation adjustments					1,184
Net assets				$	10,410

The sale of KHC resulted in the Company discontinuing its operating activities in Kazakhstan. The net results of operations of the discontinued activities in Kazakhstan prior to September 16, 2002 are shown in the statement of operations as "Loss from discontinued activities in Kazakhstan" for the years ended December 31, 2001 and 2002.

The Ormesa Project

In April 2002, the Company acquired 100% of the equity interests in the combined 52-megawatt ("MW") generating capacity of the Ormesa Project, located in Imperial Valley, Southern California, to expand its geothermal power plant operations. The Ormesa Project consists of six power plants and was owned by several unrelated companies. The Company acquired 100% interests in four of the entities and acquired the assets of a fifth entity. These entities and assets were merged into Ormesa, LLC ("Ormesa") in 2002. The Company paid approximately $41.7 million for the ownership of the Ormesa Project, of which approximately $35.7 million and $6 million has been allocated to property, plant and equipment and intangible assets, respectively. The acquisition was accounted for as a purchase and the acquired assets are being depreciated over their estimated useful lives of five to fifteen years.

The Steamboat Projects

On June 30, 2003, the Company acquired from two groups of unrelated sellers, a 100% interest in Steamboat Geothermal LLC ("SG"), which owns geothermal power plants ("Steamboat 1/1A") in Nevada. The purchase price of $1,215 was paid in cash, of which, $2,138 has been recorded as property, plant and equipment, less assumption of liabilities of $923. The acquisition has been accounted for as a purchase and the acquired assets are being depreciated over their estimated useful lives of three to fifteen years.

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 United States. The Company acquired the lessee and lessor positions of the Steamboat 2/3 geothermal power plants for a combined purchase price of approximately $82 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.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The acquisition of the Steamboat 2/3 power plants and the Meyberg Property have been accounted for under the purchase method of accounting and the depreciable acquired assets and intangibles, are being depreciated over their estimated useful lives of approximately 19 years. The purchase price of the lessee and lessor position has been allocated based on independent valuation and management's estimates as follows (unaudited):

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Current assets				$	1,944
Property, plant and equipment					78,719
Intangibles (power purchase agreement)					4,499
Accounts payable and other liabilities assumed					(2,396	)
Net assets acquired				$	82,766

The Heber and Mammoth Projects

On December 18, 2003, the Company purchased certain geothermal assets from Covanta Energy Corporation ("CEC"), an unrelated entity for a total purchase price of $215 million, plus transaction costs of approximately $3.2 million. As further discussed in Note 10, the Company entered into a loan agreement and borrowed $154.5 million from Beal Bank, all of which is collateralized by the acquired assets described below, except for the assets related to the Company's 50% ownership interest in Mammoth-Pacific, L.P. ("Mammoth").

The assets purchased include (i) a 100% ownership in Heber Geothermal Company, which owns a 38 MW geothermal power plant ("Heber 1") located near Heber, California, (ii) a 100% ownership in Second Imperial Geothermal Company ("SIGC"), that has rights to the lessee position of a 38 MW geothermal power plant ("Heber 2"), adjacent to the Heber 1 plant, (iii) a 100% ownership in Heber Field Company, that has the rights to the geothermal resources used by Heber 1 and Heber 2, and (iv) 50% ownership interest in Mammoth, that owns and operates three geothermal plants, with a combined generating capacity of 26 MW located near the city of Mammoth, California.

In addition, the Company acquired all of the beneficial rights, title and interest in the Heber 2 geothermal power plant from the lessor for a purchase price of approximately $38.5 million.

The SG and Heber and Mammoth projects asset acquisitions have been accounted for under the purchase method of accounting and the acquired assets and intangibles are being depreciated over their estimated useful lives of three to 20 years. The purchase price has been allocated based on independent valuation and management's estimates as follows:

				SG				Heber and Mammoth Projects				Total
Cash and cash equivalents				$	—			$	195			$	195
Restricted cash					—				5,959				5,959
Accounts receivable assumed					—				7,155				7,155
Property, plant and equipment					2,138				184,585				186,723
Intangibles (power purchase agreement)					—				25,273				25,273
Investment in Mammoth					—				38,632				38,632
Other assets assumed					—				270				270
Accounts payable and other liabilities assumed					(923	)			(2,559	)			(3,482	)
Asset retirement obligation					—				(2,701	)			(2,701	)
Total purchase price allocation				$	1,215			$	256,809			$	258,024

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The following unaudited pro forma financial information for the years ended December 31, 2002 and 2003, assumes the Heber and Mammoth projects acquisition occurred as of the beginning of the respective periods, 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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

results of operations that may occur in the future or that would have occurred had the acquisition of the Heber and Mammoth projects been affected on the dates indicated.

				Year Ended December 31,
				2002				2003
				(unaudited)
Revenues				$	150,707			$	185,571
Income before cumulative effect of accounting change					10,684				42,246
Net income					10,684				40,381
Basic and diluted income per share				$	0.46			$	1.74

Puna Project (unaudited)

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 $71,231, including acquisition costs of $231. PGV operates a geothermal power plant ("Puna Project") located on the island of Hawaii. The Company purchased PGV in order to increase its geothermal power plant operations in the United States. The results of PGV's operations have been included in the consolidated financial statements since June 3, 2004.

The Puna Project was not in compliance with the threshold minimum performance requirements of its power purchase agreement at the time of the acquisition, and is currently not in compliance with such requirements, which non-compliance has resulted in the imposition of sanctions that reduce the aggregate amounts of revenues payable to the Company from the relevant power purchaser, and amounted to $6 for the period from June 3, 2004 to June 30, 2004.

Steamboat Hills Project (unaudited)

On May 20, 2004, the Company completed the acquisition of 100% of the equity interests of Yankee Caithness Joint Venture, L.P. ("Yankee"), which we refer to as Steamboat Hills, from unrelated parties for a purchase price of $20,261, including acquisition costs of $111. 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 in the United States. Yankee was subsequently renamed as Steamboat Hills. The result of Steamboat Hills' operations have been included in the consolidated financial statements since May 20, 2004.

The Puna Project and the Steamboat Hills Project acquisitions have been accounted for under the purchase method of accounting and the acquired depreciable assets and intangibles are being depreciated over their estimated useful lives of three to 23 years. The purchase price has been allocated based on independent valuation and management's estimates as follows (unaudited):

				Steamboat Hills Project				Puna Project				Total
Accounts receivable assumed				$	—			$	1,870			$	1,870
Property, plant and equipment					20,809				55,763				76,572
Intangibles (power purchase agreement)					—				14,418				14,418
Accounts payable and other liabilities assumed					—				(179	)			(179	)
Asset retirement obligation					(548	)			(641	)			(1,189	)
Total purchase price allocation				$	20,261			$	71,231			$	91,492

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

				Steamboat Hills Project				Puna Project				Total
Accounts receivable assumed				$	—			$	1,870			$	1,870
Property, plant and equipment					20,809				55,763				76,572
Intangibles (power purchase agreement)					—				14,418				14,418
Accounts payable and other liabilities assumed					—				(179	)			(179	)
Asset retirement obligation					(548	)			(641	)			(1,189	)
Total purchase price allocation				$	20,261			$	71,231			$	91,492

3.    Cost and Estimated Earnings on Uncompleted Contracts

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Costs and estimated earnings incurred on uncompleted contracts				$	7,622			$	12,493			$	37,253
Less billings to date					(10,775	)			(18,414	)			($41,709	)
Total				$	(3,153	)		$	(5,921	)			($4,456	)

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

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Costs and estimated earnings in excess of billings on uncompleted contracts				$	—			$	1,922			$	3,586
Billings in excess of costs and estimated earnings on uncompleted contracts					(3,153	)			(7,843	)			($8,042	)
Total				$	(3,153	)		$	(5,921	)			($4,456	)

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.

Total costs of a construction contract completed during the six months ended June 30, 2003 decreased by $2.7 million as a result of the cancellation of a provision recorded during the year ended 2002, following negotiations with a customer. Such decrease in cost resulted in an increase in pretax income of $2.7 million during the six months ended June 30, 2003 and had no effect on future periods.

4.    Inventories

Inventories consist of the following:

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Raw materials and purchased parts for assembly				$	3,090			$	2,181			$	3,772
Self-manufactured assembly parts and finished products					2,858				1,531				3,684
Total				$	5,948			$	3,712			$	7,456

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

4.    Inventories

Inventories consist of the following:

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Raw materials and purchased parts for assembly				$	3,090			$	2,181			$	3,772
Self-manufactured assembly parts and finished products					2,858				1,531				3,684
Total				$	5,948			$	3,712			$	7,456

5.    Unconsolidated Investments

Unconsolidated investments in power plant projects consist of the following:

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Orzunil:
Investment				$	2,303			$	2,722			$	3,056
Advances					6,060				5,266				4,781
					8,363				7,988				7,837
Mammoth					—				38,772				36,319
OLCL					—				—				4,303
Total				$	8,363			$	46,760			$	48,459

The Zunil Project

The Company has a 21% ownership interest in Orzunil I de Electricidad, Limitada ("Orzunil"), a limited responsibility company incorporated in Guatemala and established for the purpose of the generation and co-generation of power from 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. The Company's 21% ownership interest in Orzunil is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Orzunil.

Notes receivable for cash advances to Orzunil consist of the following:

				December 31,								June 30, 2004				Interest Rate				Maturity Date
				2002				2003
												(unaudited)
Subordinated				$	4,499			$	4,207			$	3,991			Libor +4%				11/15/2011
Junior subordinated					1,561				1,059				790			0%				see below
				$	6,060			$	5,266			$	4,781

All available cash after the debt service under the Subordinated Loan is used to repay the Junior Subordinated Loan. Interest income received from these loans amounted to approximately $546, $296, $270, and $111 during the years ended December 31, 2001, 2002 and 2003, and the six months ended June 30, 2004 (unaudited), respectively.

The Company's equity in income of Orzunil was not significant for each of the periods presented in the accompanying financial statements.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The Mammoth Project

As discussed in Note 2, on December 18, 2003, the Company acquired a 50% interest in the Mammoth Project, which is comprised of three geothermal power plants. 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 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.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

								December 31, 2003				June 30, 2004
												(unaudited)
Condensed balance sheets:
Current assets								$	11,182			$	8,398
Non-current assets									88,918				86,394
Current liabilities									608				464
Non-current liabilities									3,680				3,738
Stockholders' equity									95,812				90,590

				Period from December 18, 2003 to December 31, 2003				Six Months Ended June 30, 2004
								(unaudited)
Condensed statements of operations:
Net sales				$	672			$	7,690
Gross margin					252				1,772
Net income					246				1,778
Company's equity in income of Mammoth:
50% of Mammoth net income				$	123			$	889
Plus amortization of the equity					18				297
				$	141			$	1,186

The Leyte Project

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 will be deconsolidated effective April 1, 2004.

The condensed financial position and results of operations of OLCL at June 30, 2004, is summarized below (unaudited):

Condensed balance sheets:
Current assets				$	6,561
Non-current assets					19,901
Current liabilities					5,691
Non-current liabilities					11,406
Stockholders' equity					9,365

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Condensed balance sheets:
Current assets				$	6,561
Non-current assets					19,901
Current liabilities					5,691
Non-current liabilities					11,406
Stockholders' equity					9,365

Condensed statements of operations
for the three months ended June 30, 2004:
Net sales				$	3,184
Gross margin				$	1,477
Net Income					877
Company's equity in income of OLCL:
80% of OLCL net income				$	702
Plus amortization of deferred revenue on intercompany profit ($3.2 million unamortized balance at June 30, 2004)					263
Total				$	965

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 will be accounted for using the equity method of accounting.

6.    Property, plant and equipment

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

				December 31,								June 30, 2004
				2002				2003
												(unaudited)
Land				$	399			$	1,090			$	11,221
Leasehold improvements					993				907				948
Machinery and equipment					9,630				10,672				11,023
Office equipment					2,151				2,218				2,301
Automobiles					1,003				1,221				1,156
Geothermal power plants, including geothermal wells:
United States of America					71,094				269,108				418,086
Foreign countries					111,212				113,177				64,037
Asset retirement cost					—				5,316				7,424
					196,482				403,709			$	516,196
Less accumulated depreciation					(44,140	)			(59,694	)			(43,979	)
				$	152,342			$	344,015			$	472,217

U.S. operations:

The net book value of the property, plant and equipment, including construction in progress, located in the United States is approximately $67,640, $274,465 and $428,102, as of December 31, 2002 and 2003, and June 30, 2004 (unaudited), respectively.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Foreign operations:

In 1996, OLCL entered into a Build, Operate, and Transfer ("BOT") agreement with PNOC-Energy Development Corporation (PNOC) in connection with the geothermal power plants located in Leyte, Philippines. The BOT agreement calls for the Company 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 10 year power purchase agreement (tolling arrangement). The

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Company owns the plants for a ten-year period ending September 2007, at which time they will be transferred to PNOC for no further consideration. As such, the Company's cost is being depreciated over the 10 year period. The net book value of the assets related to the geothermal power plants located in the Philippines amounted to approximately $22,078 and $17,433, at December 31, 2002 and 2003. As further discussed in Note 1, the Company deconsolidated the balance sheet of OLCL as of March 31, 2004.

During 1998, the Company entered into a power purchase agreement with Kenya Power and Lighting Company Limited ("KPLC"). Under the agreement, the Company will 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. The first phase has been completed and the net book value of the assets related to the generation power plant and the related wells amounted to approximately $33,269, $32,722 and $31,892 at December 31, 2002 and 2003, and June 30, 2004 (unaudited), respectively. The Company is currently in discussions with the Kenyan government and KPLC regarding, among other things, the construction of Phase II of the Olkaria III project in Kenya and the provision of certain collateral and government support. The Company must notify KPLC, by April 17, 2005, whether the Company will proceed to construct Phase II of the Olkaria III project and, if the company notifies KPLC that the Company will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If the Company fails to provide such notification the Company will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. As of December 31, 2002 and 2003, and June 30, 2004 (unaudited), the Company had incurred approximately $22,913, $22,189 and $22,370, respectively, (included in construction-in-process) in connection with construction of Phase II of the power plant, which is required to be completed no later than 2007. Management believes that the discussions will be successful and the project will be completed in the required timeframe.

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 $27,567, $26,087 and $24,849 at December 31, 2002 and 2003, and June 30, 2004 (unaudited), respectively. Additionally, as of December 31, 2002 and 2003, and June 30, 2004 (unaudited), the Company has incurred approximately $1,506, $1,103 and $1,144, respectively, (included in construction-in-process) to drill an additional well.

The Company is engaged in the construction of several geothermal power plants in other foreign countries. At December 31, 2002 and 2003, and June 30, 2004 (unaudited), such projects were in the

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

early stages of construction and the related costs totaling approximately $2,260, $3,588 and $3,900, respectively, have been included as construction-in-process.

7.    Intangible assets

Intangible assets consist of all of the Company's power purchase agreements acquired in business combinations and amounted to $7,256, $32,005 and $49,758, net of accumulated amortization of $402, $926 and $2,090 as of December 31, 2002, 2003 and June 30, 2004 (unaudited), respectively.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Amortization expense for the years ended December 31, 2001, 2002 and 2003, and for the six months ended June 30, 2003 and 2004 (unaudited) amount to $40, $362, $524, $262, and $1,164, respectively.

Estimated future amortization expense for the intangible assets as of December 31, 2003 is as follows:

Year ending December 31:
2004				$	1,743
2005					1,743
2006					1,743
2007					1,743
2008					1,743
Thereafter					23,290
Total				$	32,005

8.    Accounts payable and accrued expenses

Accounts payable and accrued expenses consist of the following:

				December 31,								June 30, 2004
				2002				2003
												(unaudited)
Trade payables				$	9,455			$	11,528			$	20,072
Scheduling and transmission charges					890				3,684				3,058
Royalties					406				2,570				1,654
Salaries and other payroll costs					3,216				3,854				4,054
Debt issue costs					—				1,313				—
Accrued interest					1,460				631				537
VAT payable					349				306				250
Other					2,874				3,593				5,139
Total				$	18,650			$	27,479			$	34,764

9.    Short-term debt

Line of credit

In July 2002, the Company consolidated an existing line of credit into a new line of credit for $55,000, all of which was outstanding as of December 31, 2002. During 2003, the line of credit was repaid in full and expired on June 30, 2004.

Bridge loan

During 2002, the Company entered into a $40,000 bridge loan agreement ("Bridge Loan") with an unrelated party, of which $10,000 was outstanding at December 31, 2002. During 2003, the Bridge Loan was amended and reclassified to long-term debt (Note 10).

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

10.    Long-term debt

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

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Limited and non-recourse agreements:
Non-recourse agreements:
Eximbank Credit Agreement (Term loan)				$	24,129			$	19,049			$	—
Ormesa loan					20,000				15,473				14,510
Beal bank credit agreement					—				154,500				153,728
Limited recourse agreements:
Credit facility agreement					11,078				19,915				18,471
					55,207				208,937				186,709
Less current portion					(11,036	)			(15,686	)			(21,260	)
				$	44,171			$	193,251			$	165,449
Full recourse agreements with banks:
Loan one				$	6,000			$	5,000			$	4,000
Loan two					5,600				4,900				4,550
Loan three					10,000				6,667				5,000
Loan four					9,500				8,143				6,786
Loan five					9,500				6,786				5,428
Bridge loan					—				20,000				20,000
Bridge loan two					—				—				20,000
Other					—				55				42
					40,600				51,551				65,806
Less current portion					(8,271	)			(10,490	)			(30,489	)
				$	32,329			$	41,061			$	35,317
Senior secured notes (non recourse)				$	—			$	—			$	189,785
Less current portion					—				—				(3,279	)
				$	—			$	—			$	186,506

Eximbank Credit Agreement (Term Loan)

In connection with the construction of four geothermal power generation plants, with a total capacity of 49MW in Leyte, Philippines, the Company 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 Term Loan is collateralized by mortgage on all real property, assignment of revenues, and pledge of partnership interest 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.

Ormesa Loan

On December 31, 2002, a wholly owned subsidiary of the Company ("Ormesa LLC"), that owns and operates the Ormesa Complex, entered into a credit facility agreement ("Ormesa Loan") amounting

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

to $20 million with a bank. Principal payments are payable in 20 varying quarterly payments that commenced in March 2003. As further discussed below, in connection with the Company's issuance of 8¼% senior secured notes, the Company has committed under the terms of the notes to repay in full the Ormesa Loan no later than January 31, 2005. Interest is computed at LIBOR (2.1% at December 31, 2003, and 1.61% at June 30, 2004 – unaudited) plus 5%, and is also payable quarterly. The Ormesa Loan is collateralized by all of the assets of Ormesa LLC and the Company's ownership interest in Ormesa LLC. There are various restrictive covenants under the Ormesa Loan, which include limitations on additional indebtedness and payments of dividends.

As required by the Ormesa Loan agreement, the Company entered into an interest rate cap agreement ("Cap Agreement") with another bank. This agreement allows the Company to receive limited reimbursement, as defined in the Cap Agreement, for interest payments the Company will pay to the bank under the Ormesa Loan if the LIBOR rate should increase to more than 6%.

Beal Bank Credit Agreement

In December 2003, in connection with the acquisition of the CEC geothermal power plant assets (Note 2), OrCal Geothermal, Inc. ("OrCal"), a wholly owned subsidiary of the Company, entered into a loan agreement with Beal Bank ("Beal Bank Credit Agreement") amounting to $154.5 million. Principal payments range from 0.25% to 3.5% of the outstanding balance and are payable in quarterly payments that commenced in June 2004 and continue through December 2019. Interest payments on the unpaid principal balance commenced in March 2004, and are payable quarterly at a variable rate determined on each anniversary date of the loan as the greater of 7.125% or LIBOR plus 5.125%. The applicable interest rate will increase by 0.5% starting in December 2011.

The Beal Bank Credit Agreement is collateralized by substantially all of the assets of OrCal and certain OrCal subsidiaries ("OrCal Subsidiaries"). Performance under the Beal Bank Credit Agreement is guaranteed by OrCal and its subsidiaries. Funds held in debt service reserve accounts established under a depository agreement are pledged for the benefit of Beal Bank and have been included in restricted cash in the accompanying balance sheet.

There are various restrictive covenants under the Beal Bank Credit Agreement, which include limitations on indebtedness, transactions with related parties and payments of dividends. Beal Bank maintains the right, through December 31, 2004, to refinance up to $100 million of the Beal Bank Credit Agreement as senior secured notes under the 1933 Securities Act, at terms consistent with the terms of the Beal Bank Credit Agreement. Should Beal Bank exercise its right, OrCal would be required to provide necessary information in connection with the issuance of such senior secured notes, and pay reasonable fees and expenses, not to exceed $25. Mandatory prepayment of the Beal Bank Credit Agreement is required to the extent that OrCal or its subsidiaries receives funds from an issuance of equity or debt securities, as well as in the occurrence of a major casualty resulting from damage or destruction of power plants owned by OrCal, whereby, receipt of insurance proceeds are in excess of $2,500.

During the second quarter of 2004 (unaudited), the Company entered into two separate interest rate cap agreements ("Cap Transactions") with two different financial institutions to mitigate the interest rate risk associated with the Beal Bank Credit Agreement. Pursuant to the Cap Transactions, the Company paid an aggregate of $3,820 to the financial institutions providing such interest rate investments. 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 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 on the effective date and reduces each payment period down to $49,633 upon termination. The fair value of the Cap Transactions at June 30, 2004 amounted to $2,922, and the decrease in the fair value of $898 has been recorded in the consolidated statement of operations as interest expense.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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 the Company executed a two-phase loan with the bank in the amounts of $11,435 ("Phase I Loan") and $36,800 ("Phase II Loan") (collectively "Credit Facility Agreement"). In March 2003, the Company signed an amendment to the Credit Facility Agreement changing the amount of the Phase II Loan from $36,800 to $15,000. 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 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 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, 2003, and June 30, 2004 (unaudited), approximately $8,046 and $7,451, respectively, was outstanding under the Phase I Loan and approximately $11,869 and $11,020, 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. Additionally, the Parent has provided to the lender a repayment guarantee of 50% of the unpaid principal, interest and all other amounts of the Credit Facility Agreement which become past due and are not paid by the Company due to any event of default as defined in the Credit Facility Agreement. 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.

Loan one

In May 1998, the Company entered into an $8,000 loan agreement, with principal payable in $1,000 annual installments that commenced in May 2001, and continue through May 2008. Interest is computed at LIBOR plus 1.7%, and is payable annually. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan.

In 2003, the Company obtained a waiver from the bank with respect to the failure by the Parent in 2001 and 2002 to meet certain financial ratios contained in its guarantee. The Company provided no consideration for such waiver. The Parent has since been in compliance with the required financial ratios.

Loan two

In July 2000, the Company entered into a $5,600 loan agreement with principal payable in equal semi-annual payments that commenced in January 2003, and continue through July 2010. Interest is computed at LIBOR plus 1.7% and is payable semi-annually. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan. On July 14, 2004 (unaudited), the Company repaid the loan in full.

Loan three

In March 2001, the Company entered into a $10,000 loan agreement, with principal payable in equal quarterly payments that commenced in April 2003, and continue through January 2006. Interest is computed at LIBOR plus a margin as calculated by the bank each quarter (1.8% at December 31, 2003), and is payable quarterly. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Loan four

In July 2001, the Company entered into a $9,500 loan agreement with a bank, with principal payable in equal semi-annual payments that commenced in July 2003, and continue through July 2006. Interest is computed at LIBOR plus 1% and is payable annually. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan. In July 2004 (unaudited) the Company committed to the lender to repay the entire loan no later than January 14, 2005 or convert the outstanding balance into a five year loan bearing interest at LIBOR plus 2.5%. In addition, the Company is subject to various restrictive covenants. If neither of the actions is taken, the lender is entitled to demand immediate repayment of the above loan.

Loan five

In July 2001, the Company entered into a $9,500 loan agreement with a bank, with principal payable in equal semi-annual payments that commenced in May 2003, and continue through May 2006. Interest is computed at LIBOR plus 1% and is payable annually. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan. In July 2004 (unaudited) the Company committed to the lender to repay the entire loan no later than January 14, 2005 or convert the outstanding balance into a five year loan bearing interest at LIBOR plus 2.5%. In addition, the Company is subject to various restrictive covenants. If neither of the actions is taken, the lender is entitled to demand immediate repayment of the above loan.

In December 2002, the Company entered into an interest rate swap agreement with a financial institution that involves the exchange of fixed interest rate payments at a rate of 2.26% on a notional amount of $9,500 at the effective date of February 21, 2003, that is reduced periodically ($6,786 at December 31, 2003) in exchange for floating interest rate payments that equal the interest due under Loan Five. As the Company did not achieve hedge accounting on such swap, the net payments or receipts under such agreement are recognized as an adjustment to interest expense. This agreement expires on May 22, 2006.

The fair value of the interest rate swap is the estimated amount that the Company would currently pay to terminate the swap agreement at the reporting date, taking into account current interest rates and the current creditworthiness of the swap counterparties. The estimated fair value of the interest rate swap was a liability of $41 at December 31, 2003. The effect of the interest rate swap utilized to offset variable rate funding was to increase interest expense by approximately $74 in 2003.

Bridge loan

During 2003, a wholly owned subsidiary of the Company amended the Bridge Loan by changing the maximum loan amount from $40,000 to $20,000. The amendment also changed the interest rate from LIBOR plus 1% to LIBOR plus 1.5%, which is payable quarterly, and extended the maturity date to February 2005. Under the terms of the Bridge Loan, the Parent has provided a letter of credit in the amount of $21 million that expires in March 2005 as collateral for the Bridge Loan.

Bridge loan two (unaudited)

In June 2004, the Company entered into a $20,000 loan agreement with a financial institution, with principal payable by November 2005. Interest is computed at LIBOR plus 1.45%, and is payable semi-annually. The parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the financial institution the remaining outstanding balance of the loan.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Future Minimum Payments

Future minimum payments under long-term obligations, excluding notes payable to Parent, as of December 31, 2003 are as follows:

Year ending December 31:
2004				$	26,176
2005					48,048
2006					26,082
2007					23,960
2008					15,016
Thereafter					121,206
Total				$	260,488

Senior Secured Notes (Unaudited)

On February 13, 2004, the Company, through Ormat Funding Corporation ("OFC"), a wholly owned subsidiary, completed the issuance of 8¼% senior secured notes ("Notes") pursuant to an exempt offering under Rule 144A and Regulation S of the Securities Act of 1933 ("Offering"), amounting to $190 million, and received net cash proceeds of approximately $179.7 million net of bond issuance costs of approximately $10.3 million, which have been included in deferred financing costs at June 30, 2004. The Notes have a final maturity date of December 30, 2020. Principal and interest on the Notes are payable in semi-annual payments that commenced in June 30, 2004. The Notes are collateralized by substantially all of the assets of OFC and fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC, other than Ormesa LLC ("Ormesa"), which will be obligated to guarantee the Notes upon the earlier of (i) January 31, 2005, (ii) the date that all the obligations under the Ormesa Loan have been repaid in full, and (iii) the date that Ormesa is no longer prohibited pursuant to the terms of the Ormesa Loan from providing a guarantee and (with certain exceptions) by all real property, contractual rights, revenues and bank accounts, intercompany notes, certain insurance policies and guarantees of OFC and its subsidiaries. There are various restrictive covenants under the Note, which include limitations on additional indebtedness and payment of dividends.

The Company may redeem the Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the Notes to be redeemed plus accrued interest, premium and liquidated damages, if any, plus a "make-whole" premium. Under certain conditions, as defined in the note agreement, the Company may be required to redeem the Notes at a redemption price ranging from 100% to 101% of the principal amount of the Notes being redeemed plus accrued interest, premium and liquidated damages, if any.

OFC has agreed to file a registration statement with the Securities and Exchange Commission and offer to exchange the Notes for publicly registered exchange notes with substantially identical terms and consummate the exchange offer prior to January 8, 2005.

Non-current restricted cash at June 30, 2004 relating to proceeds from the Offering consists of the following:

Galena re-powering construction reserve

As required by the Offering, the Company has set aside approximately $25.8 million to replace the existing equipment at the Steamboat 1/1A project with more efficient equipment, in order to optimize the geothermal resources available. After such replacement, the company will rename the Steamboat 1/1A project as the Galena project. The Company expects the re-powering will be complete and the project will achieve commercial operations by the end of 2005.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Also as required under the terms of the Notes, the Company has restricted cash accounts, consisting of the following, which are classified as current on the balance sheet:

Debt service reserve

The Company maintains an account to fund an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the Notes in the following six months. As of June 30, 2004 the required funds amounted to $8.1 million.

Ormesa debt reserve

The Company has committed under the Offering to repay in full the Ormesa Loan no later than January 31, 2005. Approximately $12.9 million of the proceeds from the Offering equal to the outstanding balance on the Ormesa Loan, less the deposit in the Debt Service reserve account described above, was placed in escrow to be released to the Company for principal payments toward the Ormesa Loan. If the Ormesa Loan is not paid in full by January 31, 2005, the balance in the escrow account will be used to repay the outstanding balance on the Ormesa Loan.

Revenue reserve

The Company deposits all revenues received into the revenue account. Such amounts are used to pay operating expenses and fund the debt service reserve account, but the funds are only available to the Company upon submission of draw requests by the Company to the bank. As such amounts are not fully unrestricted to use by the Company, they have been classified as restricted on the accompanying balance sheet. As of June 30, 2004 the balance of such account was approximately $0.2 million.

11.    Asset Retirement Obligation

The Company adopted SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, effective January 1, 2003. Under SFAS No. 143, entities are required to record 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 capping 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, an entity settles the obligation for its recorded amount or incurs a gain or loss. On January 1, 2003, the Company recorded a cumulative effect of change in accounting principle of $205, net of related tax benefit of $125. As a result of adopting the provisions of SFAS No. 143, the net income for the year ended December 31, 2003, decreased by $238, net of tax benefit of $144. The proforma net loss for the years ended December 31, 2001 and 2002 reflecting the adoption of SFAS No. 143 applied retroactively would have been $6,435 and $1,227, respectively.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The following table summarizes the impact on the Company's balance sheet following the adoption of SFAS No. 143:

				Balance at December 31, 2002				Change Resulting from Application of SFAS No. 143				Balance at January 1, 2003
Property, plant and equipment				$	196,482			$	2,615			$	199,097
Accumulated depreciation					(44,140	)			(140	)			(44,280	)
Net property, plant and equipment				$	152,342			$	2,475			$	154,817
Deferred income tax liability (benefit)				$	11,951			$	(125	)		$	11,826
Non-current asset retirement obligation				$	—			$	2,805			$	2,805

The proforma changes to the non-current asset retirement obligation, based on the information, assumptions and interest rates as of January 1, 2003 are presented below to show what the Company would have reported if the provisions of SFAS No. 143 had been in effect for the periods presented below (unaudited):

				2001				December 31, 2002				2003				June 30, 2004
																(unaudited)
Balance, beginning of period				$	—			$	580			$	2,805			$	5,737
Liabilities incurred					556				2,057				2,701				2,108
Accretion expense					24				168				231				174
Balance, end of period				$	580			$	2,805			$	5,737			$	8,019

12.    Stock Options

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 Plans"). Options under the 2004 Employee Stock Option Plan were granted in April 2004. Under the 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 Ltd. Options under the 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 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.

The following table summarizes the status of the Plans as of and for the periods presented below (shares in thousands):

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

				2001								Year Ended December 31, 2002								2003								Six Months Ended June 30, 2004
				Shares				Weighted- Average Exercise Price				Shares				Weighted- Average Exercise Price				Shares				Weighted- Average Exercise Price				Shares				Weighted- Average Exercise Price
																												(unaudited)
Outstanding, beginning of year					—			$	—				695			$	2.26				1,320			$	1.86				1,930			$	1.81
Granted, above fair value					706				2.26				—				—				—				—				—				—
Granted, below fair value					—				—				693				1.41				710				1.75				651				3.78
Exercised					—				—				—				—				(68	)			2.26				(170	)			1.98
Forfeited					(11	)			2.26				(68	)			1.82				(32	)			2.00				—				—
Outstanding at period end					695				2.26				1,320				1.86				1,930				1.81				2,411				2.40
Options exercisable at period end					—				—				—				—				92				2.26				267				1.89
Weighted-average fair value of options granted during the period:
Above fair value								$	0.92							$	—							$	—							$	—
Below fair value								$	—							$	0.85							$	0.60							$	1.73

The following table summarizes information about stock options outstanding at December 31, 2003 (shares in thousands):

Exercise Prices				Number of Shares Outstanding				Weighted-Average Remaining Contractual Life in Years				Number of Shares Exercisable				Weighted-Average Remaining Contractual Life in Years
$ 1.41					656				3.2				—				—
1.75					704				4.2				—				—
2.26					570				2.1				92				2.1
					1,930				3.2				92				2.1

The following table summarizes information about stock options outstanding at June 30, 2004 (shares in thousands)(unaudited):

Exercise Prices				Number of Shares Outstanding				Weighted-Average Remaining Contractual Life in Years				Number of Shares Exercisable				Weighted-Average Remaining Contractual Life in Years
$1.41					599				2.7				107				2.7
1.75					704				3.7				—				—
2.26					457				1.6				160				1.6
3.78					651				4.8				—				—
					2,411				3.5				267				2.1

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")

The Company has two power purchase agreements ("PPAs") with SCE related to the Ormesa Complex and two PPAs related to Heber 1 and Heber 2. The PPAs provide for the sale of

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

capacity and energy through their respective terms, with the following expiring dates: Ormesa PPAs expiring in 2017 and 2018, and Heber 1 and Heber 2 PPAs expiring in 2015 and 2023, respectively. Under the PPAs, the Company receives a fixed energy payment through April 30, 2007, 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 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 for auxiliary purposes. The Company has commenced discussions with SCE to resolve the dispute. In the interim period, SCE has tentatively agreed to pay a lower fixed price for such power. The Company cannot evaluate the potential long-term financial impact of a failure to reach a resolution with SCE, among other things because the current contract rates will fluctuate as of May 2007, however, financial loss at the reduced price paid by SCE for the year ending December 31, 2005 may be in the range of $1 million.

The temperature of the geothermal resource at the Heber 1 project has declined since the project commenced operations and as a result is currently operating at a level that is close to the minimum performance requirements set forth in its power purchase agreement. If the Company fails to upgrade the facilities and the project's performance deteriorates below minimum capacity requirements, the Company will be obligated to pay a one-time penalty to SCE of approximately $500,000 per each MW of reduced capacity.

SPPC — Nevada

The Company also has six power purchase agreements with Sierra Pacific Power Company ("SPPC"); one related to the Brady Power Plant, two related to the Steamboat 1 and 1A Power Plants, one related to the Steamboat Hills Plant, and two related to the Steamboat 2 and 3 Power Plants. The PPAs provide for the sale of energy, and for capacity for all power plants except Brady, through their respective terms, with the following expiring dates: Steamboat 1 and 1A expire in 2006 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.

HELCO — Hawaii

The Company has one power purchase agreement with Hawaii Electric Light Company ("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 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.

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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The Leyte Project (Philippines)

In connection with the BOT agreement with PNOC (Note 6), the subsidiary in the Philippines converts the steam delivered by PNOC into electric energy required by the National Power Corporation ("NPC") in accordance with the power purchase agreement between NPC and PNOC during the term of the BOT agreement. 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.

The Momotombo Project (Nicaragua)

In connection with the agreement with NEC (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" power purchase agreement. Fees are paid each month through the term of the agreement and vary based on plant performance.

Pursuant to the terms of certain of the power purchase agreements described above, 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 PPA's 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. If the Ormesa and Heber 1 and Heber 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 certain payment to it. 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 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 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 their power purchase agreements.

As required by EITF 01-8 (Note 1), the Company assessed all PPA's acquired since July 1, 2003, and concluded that all such PPA's related to our Heber 1 and Heber 2, Steamboat 2/3, Steamboat Hills, and Puna projects (see Note 2) contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the PPA is presented as "lease" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in the accompanying consolidated statements of operations. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2003 (Heber 1 and Heber 2) were as follows:

For the year ending:
2004				$	48,810
2005					57,349
2006					56,998
2007					56,084
2008					53,379
Thereafter					713,737
				$	986,357

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

14.    Income Taxes

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

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
U.S.				$	(2,843	)		$	5,756			$	2,263			$	1,267			$	733
Non-U.S. (foreign)					4,655				9,773				15,862				6,936				5,576
				$	1,812			$	15,529			$	18,125			$	8,203			$	6,309

The components of income tax expense (benefit) from continuing operations are as follows:

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Current:
Federal				$	188			$	—			$	—			$	—			$	—
Foreign					95				252				446				—				365
					283				252				446				—				365
Deferred:
Federal					(1,077	)			1,614				(1,210	)			431				(134	)
State					—				878				432				110				(24	)
Foreign					3,859				3,391				2,838				1,632				1,750
					2,782				5,883				2,060				2,173				1,592
				$	3,065			$	6,135			$	2,506			$	2,173			$	1,957

The significant components of the deferred income tax expense (benefit) from continuing operations are as follows:

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Deferred tax expense (exclusive of the effect of other components listed below)				$	3,657			$	9,846			$	5,233			$	4,185			$	5,865
Benefit of operating loss carryforwards – US					(1,154	)			(3,573	)			(1,643	)			(2,012	)			(4,273	)
(Benefit) utilization of operating loss carryforwards – Israel					(4,482	)			(1,248	)			1,019				560				407
Change in valuation allowance					4,539				1,248				(1,019	)			(560	)			(407	)
Benefit of investment tax credits					222				(390	)			(1,530	)			—				—
				$	2,782			$	5,883			$	2,060			$	2,173			$	1,592

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
U.S. federal statutory tax rate					34.0	%			34.0	%			34.0	%			34.0	%			34.0	%
State taxes, net of federal benefit					—				2.5				1.7				1.3				0.8
Effect of foreign income tax, net					(110.9	)			(6.1	)			(7.0	)			(2.8	)			2.6
Valuation allowance – Israel					250.5				8.0				(5.6	)			(6.8	)			(6.5	)
Investment tax credits					—				(2.5	)			(8.4	)			—				—
Other, net					(4.4	)			3.6				(0.9	)			0.8				0.1
					169.2	%			39.5	%			13.8	%			26.5	%			31.0	%

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

				December 31,								June 30,
				2002				2003				2004
												(unaudited)
Deferred tax assets (liabilities):
Net foreign deferred taxes, primarily depreciation				$	(8,194	)		$	(11,032	)		$	(12,782	)
Depreciation					(9,361	)			(11,704	)			(16,271	)
Net operating loss carryforwards – U.S.					5,702				7,345				11,618
Net operating loss carryforwards – Israel					7,047				6,028				5,621
Investment tax credits					441				1,971				1,971
State income taxes					—				73				75
					(4,365	)			(7,319	)			(9,768	)
Valuation allowance					(7,586	)			(6,567	)			(6,160	)
				$	(11,951	)		$	(13,886	)		$	(15,928	)

Realization of the deferred tax assets and investment tax credits is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset, except for those of the Company's Israeli operations (separate tax jurisdiction), will be realized.

At December 31, 2003, the Company had U.S. federal and state net operating loss carryforwards of approximately $20.7 million and $7.3 million, respectively, available to reduce future taxable income, which expire between 2021 and 2023, and 2014, respectively. The investment tax credits carry over indefinitely until utilized.

At December 31, 2003, the Company had net operating loss carryforwards related to its Israeli operations of approximately $16.7 million available to reduce future taxable income, which carryover indefinitely until utilized. Further, despite the fact that the net operating losses carryforward indefinitely, there is currently uncertainty as to the Israeli tax laws related to establishing limitations on the use of net operating losses. Due to OSL's history of operating losses and based on OSL's inability to generate sufficient taxable income in the foreseeable future, management believes it is not more likely than not that such net operating loss carry forwards will be utilized. Accordingly, the Company has recorded a full valuation allowance against such deferred tax assets.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $31 million at December 31, 2003. 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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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.

Income taxes related to foreign operations

Philippines – From OLCL's inception in 1996 to September 2003, OLCL, an 80% owned subsidiary 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%. The tax holiday, assuming a tax rate of 32%, has the effect of reducing tax expense by $1,032, $1,978, $798, $487, and $0, and increasing earnings per share by $0.04, $0.09, $0.03, $0.02, and $0, for the years ended December 31, 2001, 2002 and 2003 and for the six months ended June 30, 2003 and 2004 (unaudited), respectively.

Israel – The Company's operations in Israel through OSL are taxed at the regular corporate tax rate of 36%. However, under the Israeli Law for the Encouragement of Capital Investments, some of the operations of OSL have been granted "Approved Enterprise" status under expansion plan of 1996 and 2003, whereby income from the Approved Enterprise, which is determined as the increase of revenues in a particular year compared to those of the program's determined base year (1995 and 2002), will be exempt from taxes for two years commencing in the first year OSL generates taxable income, which for OSL has not commenced yet, and at a reduced tax rate of 25% for a remaining five years. The Approved Enterprise status plans of 1996 and 2003 expire in 2010 and 2017, respectively.

Other significant foreign countries – The Company's operations in Nicaragua and Kenya are taxed at the rates of 25% and 40%, respectively.

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 according 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.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

				Electricity				Products				Consolidated
Year ended December 31, 2001:
Net revenues from external customers				$	33,956			$	13,959			$	47,915
Intersegment revenues					—				1,481				1,481
Depreciation and amortization expense					10,634				611				11,245
Operating income (loss)					12,931				(8,714	)			4,217
Segment assets at period end					202,658				23,959				226,617
Expenditures for long-lived assets					68,324				52				68,376
Year ended December 31, 2002:
Net revenues from external customers				$	65,491			$	20,138			$	85,629
Intersegment revenues					—				10,157				10,157
Depreciation and amortization expense					13,780				697				14,477
Operating income					21,971				(1,744	)			20,227
Segment assets at period end					260,181				27,197				287,378
Expenditures for long-lived assets					76,568				207				76,775
Year ended December 31, 2003:
Net revenues from external customers				$	77,752			$	41,688			$	119,440
Intersegment revenues					—				7,130				7,130
Depreciation and amortization expense					15,969				650				16,619
Operating income					20,390				5,100				25,490
Segment assets at period end					519,173				23,965				543,138
Expenditures for long-lived assets					276,266				386				276,652
Six months ended June 30, 2003 (unaudited):
Net revenues from external customers				$	35,651			$	16,022			$	51,673
Intersegment revenues					—				6,780				6,780
Operating income					9,656				1,956				11,612
Segment assets at period end					248,988				26,475				275,463
Six months ended June 30, 2004 (unaudited):
Net revenues from external customers				$	70,215			$	29,491			$	99,706
Operating income					23,149				2,456				25,605
Segment assets at period end					750,673				27,510				778,183

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Revenues:
Total segment revenues				$	47,915			$	85,629			$	119,440			$	51,673			$	99,706
Intersegment revenues					1,481				10,157				7,130				6,780				—
Elimination of intersegment sales					(1,481	)			(10,157	)			(7,130	)			(6,780	)			—
Total consolidated sales				$	47,915			$	85,629			$	119,440			$	51,673			$	99,706
Operating income:
Operating income				$	4,217			$	20,227			$	25,490			$	11,612			$	25,605
Interest expenses, net					(3,010	)			(5,570	)			(7,513	)			(3,536	)			(19,044	)
Non-operating income and other					605				872				148				127				(252	)
Total consolidated income from continuing operations before income taxes				$	1,812			$	15,529			$	18,125			$	8,203			$	6,309

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Revenues from external customers attributable to: (1)
North America				$	4,901			$	33,557			$	52,534			$	19,619			$	57,050
Pacific Rim					1,646				4,502				10,340				746				25,505
Latin America					12,002				18,459				25,016				17,611				6,887
Africa					8,688				9,236				12,171				7,512				4,927
Far East					16,119				17,937				17,793				4,743				4,436
Europe					4,559				1,938				1,586				1,442				901
Consolidated total				$	47,915			$	85,629			$	119,440			$	51,673			$	99,706

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

				December 31,												June 30,
				2001				2002				2003				2004
																(unaudited)
Long-lived assets (primarily power plants and related assets) relating to continuing operations located in:
North America				$	37,537			$	77,617			$	314,296			$	494,930
Latin America					18,256				31,333				30,778				29,269
Africa					50,189				56,182				54,911				54,262
Far East					26,592				22,078				17,433				—
Europe					2,240				1,788				1,563				1,620
Consolidated total				$	134,814			$	188,998			$	418,981			$	580,081

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

The following table presents revenues from major customers:

				Year ended December 31,																								Six months ended June 30,
				2001								2002								2003								2003								2004
				Revenues				%				Revenues				%				Revenues				%				Revenues				%				Revenues				%
																												(unaudited)
Revenues from major customers:
Customer A (1)				$	—				—			$	21,845				26			$	32,458				27			$	13,097				25			$	41,776				42
Customer B (2)					—				—				—				—				10,318				9				—				—				16,041				16
Customer C (1)					12,475				26				15,593				18				12,620				11				6,342				12				3,096				3
Customer D (1)					8,910				19				9,221				11				11,617				10				5,978				12				6,128				6
Customer E (1)					3,964				8				9,606				11				11,389				10				5,495				11				12,537				13
Customer F (1)					8,607				18				9,225				11				9,669				8				4,739				9				4,816				5
Customer G (2)					—				—				7,025				8				10,754				9				10,754				21				—				—
Customer H					—				—				—				—				—				—				—				—				8,666				9

(1)	Revenues reported in electricity segment

(2)	Revenues reported in products segment

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

16.    Transactions with related entities

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

				Year Ended December 31,												Six Months Ended June 30,
				2001				2002				2003				2003				2004
																(unaudited)
Transactions
Revenues on construction project to subsidiary of Parent				$	303			$	—			$	—			$	—			$	—
Revenues on construction of Zunil project				$	330			$	—			$	—			$	—			$	—
Property rental fee expense paid to Parent				$	627			$	627			$	627			$	314			$	314
Interest expense on note payable to Parent				$	1,131			$	1,068			$	1,874			$	783			$	4,568
Guarantee fees to Parent				$	145			$	783			$	709			$	352			$	218
Corporate financial, administrative and executive services provided to Parent				$	120			$	120			$	120			$	60			$	60
Year-End Balances (at end of period)
Due from Orzunil								$	132			$	145							$	149
Due from subsidiaries of Parent								$	1,624			$	1,794							$	1,573

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, 2001, 2002 and 2003, and the six months ended June 30, 2003 and 2004 (unaudited), the fees under the agreement totaled approximately $145, $783, $709, $352 and $218, respectively.

The current liability due to Parent at December 31, 2002 and 2003, and June 30, 2004 (unaudited) of $51,365, $151 and $413, 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 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 ("Parent Loan Agreement") with the Parent pursuant to which the Company may borrow 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 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, 2003 and June 30, 2004 (unaudited) was $126,339 and $143,187, respectively. As further discussed in Note 1, on June 29, 2004 (unaudited), $20,000 outstanding under the Parent Loan Agreement was converted to 1,160,714 shares of $0.001 par value common stock of the Company.

In 2003, the Company entered into a $50,665 non-interest bearing note agreement with the Parent. Principal is payable upon demand at any time after November 2007, but no later than December 2009. The loan is subordinated to all other liabilities of the Company.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Future minimum payments under the notes payable to Parent as of December 31, 2003 are as follows:

Year ending December 31:
2004				$	—
2005					17,834
2006					78,100
2007					27,435
2008					27,435
Thereafter					26,200
				$	177,004

17.    Employee benefit plan

401(k) Plan

Prior to July 1, 2002, the Company had a Simple IRA ("IRA Plan") plan covering substantially all employees of the Company, age 21 or older, with minimum service requirements. The Company contributed 2% of the eligible employees' compensation for the year. The Company contributed $17 and $6 to the plan for year ended December 31, 2001 and for the six-month period ended June 30, 2002, respectively. On July 1, 2002 the Company discontinued making contributions to the IRA Plan, as the Company exceeded the maximum number of employees allowed for such a plan due to the purchase of the Ormesa Project. Any amounts remaining in the IRA Plan will continue to be invested, and earnings applied to the participating employees' accounts. All contributions made after July 1, 2002 are contributed into the Company's new 401(k) plan, discussed below.

On July 1, 2002 the Company established a 401(k) Plan (the "Plan") for the benefit of its employees. Employees of the Company 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 $46, $83, $24 and $79 and for the six-month period ended December 31, 2002, the year ended December 31, 2003 and for the six months ended June 30, 2003 and 2004 (unaudited), 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 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 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 was payable at each balance sheet date. Such liabilities have been presented on the balance sheet as "Liability 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 $9,047, $9,440, and $9,483 at December 31, 2002 and 2003, and June 30, 2004 (unaudited), of which $8,067, $8,227 and $8,259 was restricted, respectively, and have been presented on the balance sheet as part of "Deposits and other". Under the severance pay law, restricted funds may not be withdrawn or pledged until the respective

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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, 2001, 2002 and 2003, and for the six month periods ended June 30, 2003 and 2004 (unaudited) were $516, $456, $511, $156, and $316, respectively, which includes losses (income) amounting to $(49), $8, $65, $34, and $46, respectively, generated from the regular deposits and amounts accrued in severance funds.

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 $135, $925, $1,181, $572 and $2,283 for the years ended December 31, 2001, 2002 and 2003, and for the six months ended June 30, 2003 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 and other financial guarantees obtained by the Parent and issued on behalf of the Company totaling $19,736 and $27,558 at December 31, 2003 and June 30, 2004 (unaudited). Management does not expect any material losses to result from these off-balance-sheet instruments 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

On June 30, 2004 (unaudited), a subsidiary of the Company entered into a letter of credit and loan agreement ("LOC Agreement") with a bank pursuant to which the bank agreed to issue one or more letters of credit in an amount not to exceed $15 million in the aggregate, which LOC agreement has an initial term which expires on June 30, 2007, and which is automatically extended for successive one-year periods unless notice is provided by either the Company or the bank to the contrary. 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 into a loan, bearing interest at LIBOR plus 4.0%, and matures on the succeeding expiration date of the LOC Agreement. There are various restrictive covenants in the LOC Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, and minimum coverage ratio. On June 30, 2004 (unaudited), a letter of credit amounting to $8,125, and subsequent to June 30, 2004, another letter of credit amounting to $3,644 was issued under the LOC Agreement, which have been used to replace cash on deposit in reserve funds that were used as a pledge against the OFC Notes and the Beal Bank Credit Agreement. The amount on one of the letters of credit will increase by $2,674 in December 2004.

Grants and royalties

The Company, through OSL, has historically 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 $42, $700, $1,171, $500, and $1,139 for the years ended December 31, 2001, 2002 and 2003, and for the six months ended June 30, 2003 and 2004 (unaudited), respectively. Such royalties are capped at the amount of the grants received plus interest at LIBOR, and the cap at December 31, 2003 and June 30, 2004 (unaudited), amounted to $7,050 and $6,617, respectively, of which approximately $5,268 and $4,919 of the cap, respectively, increases based on the LIBOR rate, as defined.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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 June 30, 2004 (unaudited), excluding bonuses and benefits, was approximately $2.0 million.

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 June 30, 2004 (unaudited) approximated $0.9 million.

Contingencies

In August 2003, Ormesa agreed to enter into binding arbitration with the Imperial Irrigation District in connection with Imperial Irrigation District's claim that Ormesa is obligated to pay scheduling and transmission charges in the amount of $529 through the effective date of relinquishment of nominated capacity for two of the Ormesa Project plants. Ormesa contends that it is not obligated to pay the subject charges after the January 1, 2003, effective date of the Energy Services Agreement that Ormesa entered into with the Imperial Irrigation District. The Company believes that the dispute will be resolved in 2004 and that any outcome will not have a material impact on the Company's operations or relationship with the Imperial Irrigation District.

In response to an order issued by a California State Court of Appeal, the California Public Utilities Commission ("CPUC"), has commenced an administrative proceeding in order to address short run avoided cost pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The court directed that the CPUC modify short run avoided cost pricing on a retroactive basis to the extent that the CPUC determined that short run avoided cost prices were not sufficiently "accurate" or "correct." If the short run avoided cost prices charged during the period in question were determined by the CPUC to not be "accurate" or "correct," retroactive price adjustments could be required for any of the Company's Qualifying Facilities in California whose payments are tied to short run avoided cost pricing, including the Heber 1, Heber 2, Mammoth and Ormesa projects. Currently it is not possible to predict the outcome of such proceeding, however, any retroactive price adjustment required to be made in relation to any of the Company's projects may require such projects to make refund payments, which could materially effect the financial condition, future results and cash flow of the Company.

SG is party to litigation related to a dispute over amounts owed to the plaintiffs under certain operating agreements. SG has initiated settlement discussions with the plaintiff and the Company believes that any outcome will not have a material impact on the Company's results of operations.

The Company is a defendant in various other legal suits 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.

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

Certain of the Company's projects are subject to contested 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.

19.    Subsequent events (unaudited)

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 (1) any draws made on any standby letter of credits issued by the Parent for the benefit of the Company and (2) 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.

Finance arrangements

In connection with the acquisition transaction between OSL and the Parent, the Company amended certain terms of its debt related to Loans 1 and 4, and the Bridge Loan (Note 5), pursuant to which the Company is subject to various financial covenants, including maintaining certain levels of debt service coverage ratios and a debt to equity ratio.

In July 2004, the Company also entered into an agreement with a financial institution pursuant to which the Company has assumed, as the primary obligor, existing contingent obligations of approximately $17.2 million in outstanding letters of credit that were previously obtained by the Parent (see letters of credit under Note 18).

Interest Rate Lock Agreement

In anticipation of the Company's plans to refinance the cost of the Puna project, on October 12, 2004, the Company entered into a treasury rate lock agreement ("Rate Lock Agreement") with a financial institution, at a locked-in treasury rate of 4.2075%, with a notional amount of $62.5 million, and terminating on December 31, 2004 (the "Determination Date"). The rate lock is based on a 10-year treasury security that matures in August 2014. Pursuant to the Rate Lock Agreement, if the base treasury rate on the Determination Date is greater than 4.2075%, the counterparty will be required to pay the Company a floating amount; however, if the base treasury rate is less than 4.2075%, the Company will be required to pay to the counterparty the floating amount. If the base treasury rate equals 4.2075% on the Determination Date, no payment will be required to be made by either party. Based on treasury rates and the yield curve on October 16, 2004, each 1 basis point difference between the locked-in rate and the base treasury rate equalled approximately $50,000.

Cash Dividend

On October 21, 2004, the Company's board of directors declared and authorized the payment of a cash dividend in the aggregate amount of $2.5 million, conditional upon and effective as of the effective date the Company's initial public offering.

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

Ormat Technologies, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(dollars in thousands, except per share amounts)

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. The Company has not granted any options under the 2004 Incentive Plan; however, the Company intends to grant options to purchase up to 200,000 shares of common stock to employees and options to purchase up to 30,000 shares of common stock to non-employee directors prior to the effective date of the Company's initial public offering. The exercise price of the options will be the price of the shares of the common stock offered in the initial public offering. Such options will expire ten years from the date of grant, with vesting at 25%, 25% and 50%, in year two, three, and four, respectively, after the date of grant.

20.    Restatement

The accompanying consolidated balance sheets as of December 31, 2002 and 2003, and the consolidated statements of stockholder's equity for each of the three years in the period ended December 31, 2003 have been revised to reclassify certain amounts due to/from Parent, originally reported as an asset/liability, as a component of stockholder's equity. The Company has determined that certain divisional equity of the power generation business originally reported as amounts due to/from Parent is more appropriately reported as a component of stockholder's equity. Accordingly, the amounts due to/from Parent and stockholder's equity were increased (reduced) by $1,806 and $(4,549) as of December 31, 2002 and 2003, respectively. Additionally, the components of stockholder's equity have been modified to separately reflect the purchased power generation business's divisional equity, which (reduced) increased retained earnings by $(10,988), $1,562, $8,405, and $6,714 as of December 31, 2000, 2001, 2002, and 2003, respectively.

21.    Stock Split

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 the accompanying consolidated financial statements have been restated to give retroactive effect to the reverse stock split for all periods presented. The par value of the common stock remained at $0.001 per share. Additionally, the Company 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 to 200,000,000 authorized shares of $0.001 par value common stock.

Puna Geothermal Venture

Financial Statements

As of December 31, 2002 and 2003, and for the Year Ended
December 31, 2002 and for Periods from January 1, 2003 to
December 10, 2003 and December 11, 2003 to December 31,
2003 and

Unaudited Financial Statements

As of March 31, 2004 and for the Three-Months Ended
March 31, 2003 and 2004

Report of Independent Auditors

To the Partners of
Puna Geothermal Venture

In our opinion, the accompanying balance sheet present fairly, in all material respects, the financial position of Puna Geothermal Venture (the "Company") at December 31, 2002, and the results of its operations, partners' equity, and its cash flows for the period from January 1, 2003 to December 10, 2003 and for the year ended December 31, 2002, 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 statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audits provide a reasonable basis for our opinion.

As discussed in Notes 2 and 8, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

As discussed in Notes 1 and 2 to the financial statements, on December 11, 2003, CE Puna I Corporation, a subsidiary of Constellation Power Corporation, acquired the entire partnership interest of AMOR VIII Corporation, resulting in the Company being wholly owned by Constellation Power Corporation, through its subsidiaries. The financial statements for the period subsequent to December 10, 2003 have been prepared on the basis of accounting arising from this acquisition.

/s/ PricewaterhouseCoopers LLP

Honolulu, Hawaii
April 30, 2004, except for Notes 3 and 9,
    as to which the date is July 1, 2004

Report of Independent Auditors

To the Partners of
Puna Geothermal Venture

In our opinion, the accompanying balance sheet present fairly, in all material respects, the financial position of Puna Geothermal Venture (the "Company") at December 31, 2003, and the results of its operations, partners' equity, and its cash flows for the period from December 11, 2003 to December 31, 2003, 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 statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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.

As discussed in Notes 2 and 8, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

As discussed in Notes 1 and 2 to the financial statements, on December 11, 2003, CE Puna I Corporation, a subsidiary of Constellation Power Corporation, acquired the entire partnership interest of AMOR VIII Corporation, resulting in the Company being wholly owned by Constellation Power Corporation, through its subsidiaries. The financial statements for the period subsequent to December 10, 2003 have been prepared on the basis of accounting arising from this acquisition.

/s/ PricewaterhouseCoopers LLP

Honolulu, Hawaii
April 30, 2004, except for Notes 3 and 9,
    as to which the date is July 1, 2004

Puna Geothermal Venture
Balance Sheets
December 31, 2002 and 2003 and March 31, 2004

				Predecessor Company				Successor Company
				December 31, 2002				December 31, 2003				March 31, 2004
												(unaudited)
Assets
Current assets
Cash and cash equivalents				$	1,194,294			$	4,618,961			$	5,111,961
Restricted cash (Note 3)					6,107,759				3,063,035				3,068,807
Advances					—				2,240				2,321
Accounts receivable — HELCO					363,474				1,975,136				1,878,977
Spare parts inventory					2,087,529				4,511,926				4,511,926
Other current assets					71,006				105,690				77,205
Total current assets					9,824,062				14,276,988				14,651,197
Plant and equipment
Plant and equipment					208,700,816				196,309,698				196,319,826
Less accumulated depreciation					52,029,567				58,827,358				60,281,276
					156,671,249				137,482,340				136,038,550
Construction in progress					2,019,245				52,724				52,724
					158,690,494				137,535,064				136,091,274
Deferred financing costs					1,205,321				1,071,449				1,037,981
Other assets					31,535				31,535				123,233
Total assets				$	169,751,412			$	152,915,036			$	151,903,685
Liabilities and Partners' Equity
Current liabilities
Note payable to Credit Suisse, current portion (Note 3)				$	3,678,051			$	4,004,990			$	3,024,176
Trade accounts payable					2,861,678				932,662				286,299
HELCO sanction (Note 5)					608,831				203,005				18,808
Payable to custodian					26,443				—				—
Accrued expenses					483,299				638,573				247,561
COSI — Puna, Inc. payables					887,871				897,263				1,355,780
Constellation Power, Inc. payables					264,000				—				66,000
Total current liabilities					8,810,173				6,676,493				4,998,624
Noncurrent liabilities
Swap agreements (Note 4)					4,758,265				3,692,233				2,769,130
Note payable to Credit Suisse, noncurrent portion (Note 3)					44,300,097				40,294,892				40,294,892
Asset retirement obligation					—				2,041,043				2,080,844
Total liabilities					57,868,535				52,704,661				50,143,490
Partners' equity
Partners' capital					116,641,142				103,902,608				104,529,325
Accumulated other comprehensive loss					(4,758,265	)			(3,692,233	)			(2,769,130	)
Total partners' equity					111,882,877				100,210,375				101,760,195
Total liabilities and partners' equity				$	169,751,412			$	152,915,036			$	151,903,685

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

Puna Geothermal Venture
Statements of Operations
Year Ended December 31, 2002, Period from January 1, 2003 to December 10, 2003, Period from December 11, 2003 to December 31, 2003, and Three Months Ended March 31, 2003 and 2004

				Predecessor Company								Successor Company				Predecessor Company				Successor Company
				Year Ended December 31, 2002				Period from January 1, 2003 to December 10, 2003				Period from December 11, 2003 to December 31, 2003				Three Months Ended March 31,
																2003				2004
																(unaudited)
Operating revenues, all from a single customer
Electricity sales				$	4,465,946			$	9,485,176			$	728,746			$	1,581,283			$	4,607,244
Capacity payments					1,859,310				7,901,795				620,882				314,557				996,132
Total operating revenues					6,325,256				17,386,971				1,349,628				1,895,840				5,603,376
Operating expenses
Operating expenses					5,392,745				5,607,777				579,585				1,120,728				1,613,993
General and administration expenses					1,888,530				1,481,763				122,759				448,528				519,195
Royalties and land lease expenses (Note 6)					711,308				1,125,392				54,765				343,838				499,051
Depreciation and amortization					6,182,169				6,466,810				418,530				1,509,138				1,483,163
Accretion of asset retirement obligations (Note 8)					—				158,804				9,826				41,066				39,801
Capacity sanction expenses					608,831				313,473				—				108,076				18,808
Total operating expenses					14,783,583				15,154,019				1,185,465				3,571,374				4,174,011
Non-operating income (expenses)
Interest income					80,262				43,508				1,964				16,212				17,849
Interest expense					(3,801,492	)			(3,293,191	)			(174,916	)			(885,427	)			(820,497	)
Net income (loss) before cumulative effect of change in accounting principle					(12,179,557	)			(1,016,731	)			(8,789	)			(2,544,749	)			626,717
Cumulative effect of change in accounting principle (Note 8)					—				1,157,265				—				1,157,265				—
Net income (loss)				$	(12,179,557	)		$	(2,173,996	)		$	(8,789	)		$	(3,702,014	)		$	626,717
Proforma income tax provision (benefit) (unaudited)				$	(4,628,200	)		$	(826,100	)		$	(3,300	)		$	(1,406,800	)		$	238,200
Proforma net income (loss) reflecting tax provision (Note 2) (unaudited)				$	(7,551,357	)		$	(1,347,896	)		$	(5,489	)		$	(2,295,214	)		$	388,517

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

Puna Geothermal Venture
Statements of Partners' Equity
Year Ended December 31, 2002, Period from January 1, 2003 to December 10, 2003, Period from December 11, 2003 to December 31, 2003, and Three Months Ended March 31, 2004

				Partners' Capital																				Accumulated Other Comprehensive Loss				Total Partners' Equity
				Capital												Preferred Capital				Total Partners' Capital
				AMOR VIII Corporation				CE Puna I				CE Puna L.P.				CE Puna L.P.
Balance at January 1, 2002				$	21,430,098			$	—			$	37,686,019			$	54,643,835			$	113,759,952			$	(2,595,000	)		$	111,164,952
Capital contribution					—				—				—				15,060,747				15,060,747				—				15,060,747
Comprehensive loss
Change in unrealized holding loss					—				—				—				—				—				(2,163,265	)			(2,163,265	)
Partnership loss for 2002					(121,795	)			—				(12,057,762	)			—				(12,179,557	)			—				(12,179,557	)
Total comprehensive loss																													(14,342,822	)
Balance at December 31, 2002					21,308,303				—				25,628,257				69,704,582				116,641,142				(4,758,265	)			111,882,877
Capital contribution					—				—				964,726				9,675,735				10,640,461				—				10,640,461
Comprehensive loss
Change in unrealized holding loss					—				—				—				—				—				265,699				265,699
Partnership loss for the period from January 1, 2003 to December 10, 2003					(12,093	)			—				(2,161,903	)			—				(2,173,996	)			—				(2,173,996	)
Total comprehensive loss																													(1,908,297	)
Balance at December 10, 2003				$	21,296,210			$	—			$	24,431,080			$	79,380,317			$	125,107,607			$	(4,492,566	)		$	120,615,041
Balance at December 11, 2003				$	—			$	100,000			$	24,431,080			$	79,380,317			$	103,911,397			$	(4,492,566	)		$	99,418,831
Comprehensive income
Change in unrealized holding loss					—				—				—				—				—				800,333				800,333
Partnership loss for the period from December 11, 2003 to December 31, 2003					—				(88	)			(8,701	)			—				(8,789	)			—				(8,789	)
Total comprehensive income																													791,544
Balance at December 31, 2003					—				99,912				24,422,379				79,380,317				103,902,608				(3,692,233	)			100,210,375
Comprehensive loss (unaudited)
Change in unrealized holding loss					—				—				—				—				—				923,103				923,103
Partnership income for the period from January 1, 2004 to March 31, 2004					—				6,268				620,449				—				626,717				—				626,717
Total comprehensive loss																													1,549,820
Balance at March 31, 2004 (unaudited)				$	—			$	106,180			$	25,042,828			$	79,380,317			$	104,529,325			$	(2,769,130	)		$	101,760,195

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

Puna Geothermal Venture
Statements of Cash Flows
Year Ended December 31, 2002, Period from January 1, 2003 to December 10, 2003, Period from December 11, 2003 to December 31, 2003, and Three Months Ended March 31, 2003 and 2004

				Predecessor Company								Successor Company				Predecessor Company				Successor Company
				Year Ended December 31, 2002				Period from January 1, 2003 to December 10, 2003				Period from December 11, 2003 to December 31, 2003				Three Months Ended March 31,
																2003				2004
																(unaudited)
Cash flows from operating activities
Net income (loss)				$	(12,179,557	)		$	(2,173,996	)		$	(8,789	)		$	(3,702,014	)		$	626,719
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation and amortization					6,182,169				6,466,810				418,530				1,509,138				1,483,163
Accretion of asset retirement obligations					—				158,804				9,826				41,066				39,801
Cumulative effect of change in accounting principle					—				1,157,265				—				1,157,265				—
Changes in
Accounts receivable – HELCO					1,244,851				(1,856,173	)			244,511				(416,285	)			96,158
Spare parts inventory					(216,253	)			(2,424,397	)			—				—				—
Other current and non-current assets					145,495				198				(37,122	)			(619	)			(81	)
Accounts payable and accrued expenses					(372,589	)			749,936				(229,334	)			121,396				(832,172	)
COSI – Puna, Inc. payables					399,507				(171,951	)			662,069				—				—
Constellation Power, Inc. payables					198,000				220,000				—				66,000				66,000
Net cash provided by (used in) operating activities					(4,598,377	)			2,126,496				1,059,691				(1,224,053	)			1,479,588
Cash flows from investing activities
Capital expenditures					(9,515,147	)			(8,454,072	)			(349,641	)			(6,798,633	)			—
Decrease (increase) in restricted cash					(3,103,908	)			3,046,688				(1,964	)			3,063,989				(5,772	)
Net cash used in investing activities					(12,619,055	)			(5,407,384	)			(351,605	)			(3,734,644	)			(5,772	)
Cash flows from financing activities
Principal payments on note payable					(3,228,513	)			(2,697,452	)			(980,814	)			(899,079	)			(980,814	)
Capital contributions					15,060,747				9,675,735				—				5,397,753				—
Net cash provided by (used in) financing activities					11,832,234				6,978,283				(980,814	)			4,498,674				(980,814	)
Increase (decrease) in cash and cash equivalents					(5,385,198	)			3,697,395				(272,728	)			(460,023	)			493,002
Cash and cash equivalents
Beginning of period					6,579,492				1,194,294				4,891,689				1,194,294				4,618,961
End of period				$	1,194,294			$	4,891,689			$	4,618,961			$	734,271			$	5,111,963
Other cash flow information
Cash paid during the period for interest				$	3,800,766			$	3,267,676			$	199,480			$	885,427			$	820,496
Noncash investing activity
Accounts payable converted to Partners' capital				$	—			$	964,726			$	—			$	—			$	—

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

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

1.	Organization and Operations

Puna Geothermal Venture ("PGV"), a Hawaii General Partnership, operates under the Second Amended and Restated Partnership Agreement dated December 2, 1996 (the "Partnership Agreement"). Prior to December 11, 2003, the partners of PGV were CE Puna Limited Partnership ("CE Puna"), a subsidiary of Constellation Power Corporation and AMOR VIII Corporation ("AMOR"). Each partner had a 50% interest. However, under the Partnership Agreement and other agreements between the partners, CE Puna has provided a larger percentage of PGV's capital and, therefore, is entitled to a greater percentage of PGV's income or loss, tax benefits and cash flow. In particular, CE Puna is to receive 100% of net cash flow until its Preferred Capital, together with a cumulative Preferred Capital Return of 10% per annum, is paid. On December 11, 2003, CE Puna I Corporation ("CE Puna I"), a subsidiary of Constellation Power Corporation, consummated an agreement to purchase the entire partnership interest of AMOR. At December 31, 2003, the partners are CE Puna I and CE Puna, subsidiaries of Constellation Power Corporation.

PGV developed and is operating a geothermal energy project on the island of Hawaii in the State of Hawaii. PGV sells the electricity it generates to Hawaii Electric Light Company, Inc. ("HELCO") under the terms of a long-term power purchase agreement. PGV began generating electricity commercially in 1993.

During 2002, PGV encountered problems with the production capacity and injection wells related to geothermal resources and production levels fell significantly below minimum performance requirements under the Power Purchase Agreement ("PPA") (Note 5) with HELCO. Such non-compliance with the PPA subjected PGV to PPA-based sanctions (Note 5).

In January 2003, PGV finished development of a well which increased the production under the PPA with HELCO and, in April 2003, PGV finished development of another well that further increased production. The costs of completing these projects were funded by capital contributions from CE Puna.

Management expects to generate positive cash flows from operations in fiscal 2004 in amounts sufficient to fund debt service requirements.

2.	Summary of Significant Accounting Policies

Basis of Presentation

On December 11, 2003, Constellation Power Corporation ("Constellation") closed on the purchase of the remaining interest in PGV that it did not already own. As a result, PGV is wholly owned by Constellation Power Corporation, through its subsidiaries. The purchase was accounted for as an acquisition of an asset, as opposed to the acquisition of a business, and is subject to the purchase method of accounting. Starting on December 11, 2003, PGV's financial statements reflected Constellation's (through its subsidiaries) "pushed down" accounting basis. The change in the partnership equity as a result of this acquisition was an approximately $21.2 million decrease in Partners' capital.

The following reconciles PGV's partners' capital as of December 10, 2003 to Constellation's "pushed down" accounting basis as of December 11, 2003:

Partners' capital as of December 10, 2003				$	125,107,607
Acquisition of AMOR VIII Corporation's investment in PGV by Constellation
Constellation's acquisition cost of AMOR VIII's interest					100,000
AMOR VIII's capital account					(21,296,210	)
Constellation's "pushed down" accounting basis at December 11, 2003				$	103,911,397

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

PGV's plant and equipment was written down by approximately $21.2 million; there were no other changes in the basis of any other assets and liabilities as a result of the "push down."

Interim Financial Data

The interim financial data for the three months ended March 31, 2004 and 2003 is unaudited; however, in the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results of the interim periods.

Cash Equivalents

PGV considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash

PGV funds reserve accounts for new wells, debt service, working capital and major maintenance repairs as required by its financing agreement.

Spare Parts Inventory

Spare parts inventory is stated at cost determined on a weighted average basis.

Plant and Equipment

Plant and equipment consists of costs incurred during the development and construction of the power plant, the wellfield and transmission lines (the "plant"). Construction period interest totaling $18,423,973 was capitalized in connection with development and construction of the plant and has been allocated to the assets to which it relates. The plant went in service on August 1, 1993.

Plant and equipment is depreciated using the straight-line method over the lesser of the estimated useful lives of the assets (generally 35 years) or the number of years remaining in the power purchase agreement with HELCO (34.33 years at August 1, 1993.)

Deferred Financing Costs

The expense of issuance of the long-term note payable is being amortized over the fifteen-year life of the note payable under the interest method.

Income Taxes

No provision for federal or state income taxes is made in the financial statements as the individual partners are responsible for reporting their respective shares of PGV's income, loss, deductions and credits to taxing authorities. The proforma net income (loss) on the statements of operations reflects a tax provision (benefit) of 38%, the effective rate of the company that acquired CE Puna I and CE Puna's ownership interest (see Note 9).

Financial Instruments

The carrying amount of cash and cash equivalents and restricted cash approximates fair value because of the short maturity of these instruments. The carrying amount of long-term debt approximates fair value because its interest rate is variable. The estimated termination cost associated with the interest rate swap at December 31, 2003, which represents fair value, is approximately $3,692,000.

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

Use of Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of the contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, various future economic factors, which are difficult to predict and are beyond the control of PGV. Therefore, actual amounts could differ from these estimates.

Impairment of Long-Lived Assets

Long-lived assets subject to the requirements of Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, as amended by SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, are evaluated for impairment through a review of undiscounted expected future cash flows. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the asset, an impairment loss is recognized. As a result of the change in PGV's ownership in 2003 and PGV's inability to meet the minimum performance requirements as set forth in its power purchase agreement (Note 5), a detailed impairment analysis was performed. The result of this analysis concluded that the sum of the undiscounted expected future cash flows was more than the carrying amount of its long-lived assets. Accordingly, PGV recognized no impairment losses of its long-lived assets in 2003 or in any other periods presented.

Asset Retirement Obligation

On July 22, 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). Under SFAS 143, retirement obligations associated with tangible long-lived assets acquired are to be recognized at fair value in the period in which incurred, effective for financial statements issued for fiscal years beginning after June 15, 2002. PGV adopted SFAS 143 beginning January 1, 2003. See Note 8 for further discussion.

Derivative Instruments

On January 1, 2001, PGV adopted SFAS No. 133, as amended by SFAS No. 138, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). Under SFAS 133, all derivative instruments are recognized in the balance sheet at their fair values. PGV's interest rate swap agreements qualify as a cash flow hedge under SFAS 133. See Note 4 for further discussion.

Concentrations of Credit Risk

Financial instruments that potentially subject PGV to a concentration of credit risk primarily consist of cash and cash equivalents and trade accounts receivable.

PGV's cash and cash equivalents are deposited with two financial institutions in the United States of America and may exceed federally insured amounts. PGV has not experienced any losses on its cash and cash equivalents.

PGV's customer base is comprised of one single customer, HELCO. Loss of or default by this customer could have an adverse effect upon PGV's financial position, results of operations and cash flows.

PGV's production wells are subject to volatility and potential shutdown on exhaustion. A shutdown of a well, as occurred in 2002, could have adverse effects on PGV's ability to produce ample power in accordance with the Power Purchase Agreement (see Note 5), subjecting PGV to reduced revenues and sanctions by HELCO in compensation of the inability to meet specified energy production levels.

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

3.	Note Payable

PGV has entered into a Credit Agreement dated as of December 2, 1996 with Credit Suisse, which provides for a 15-year term loan in an amount not to exceed $65,387,594. Substantially all of the assets of PGV are pledged as collateral on amounts due under the Credit Agreement. Principal is due quarterly. Amounts outstanding under the Credit Agreement bear interest at LIBOR plus 1.50% or the lender's Base Rate plus .75%, at PGV's option. On the fifth and tenth anniversary of the closing of the Credit Agreement, the interest rate increases by 25 basis points. In addition, the interest rate may be increased by 25 basis points if PGV fails to maintain at least a 1.25:1 debt service coverage ratio. The interest rate at December 31, 2003 and 2002 was 2.94% and 3.56%, respectively.

As required under the Credit Agreement, Constellation Investments, Inc., an affiliate of CE Puna, established several reserves and guarantees in order to fund specific needs of PGV. Under the agreement, a Debt Service Reserve, a New Well Field Reserve and an Underground Injection Control ("UIC") Guaranty were established. PGV is required, per the amended Credit Agreement, to maintain $3.0 million in the New Well Field Reserve for the purpose of funding well improvements as structured in PGV's Restoration Plan. The Debt Service Reserve Guaranty includes a guaranty of $4.5 million by Constellation Investments, Inc. and a Debt Service Reserve to be maintained by PGV of $1.8 million. The reserve balances recorded as restricted cash by PGV as of December 31, 2002, 2003 and March 31, 2004 were as follows:

												March 31,
				2002				2003				2004
												(unaudited)
New Well Field Reserve				$	3,073,759			$	2,224			$	2,224
Debt Service Reserve					1,815,644				1,831,786				1,835,261
Maintenance Reserve					625,990				631,479				632,660
Working Capital Reserve					592,366				597,546				598,662
				$	6,107,759			$	3,063,035			$	3,068,807

These reserve accounts are classified as current restricted cash since they are used and replenished for servicing current debt and for funding current operations.

Under terms of the Revised Credit Agreement, reserve accounts were funded at closing for debt service, working capital and major maintenance repairs. Additional payments into these and other reserve accounts will occur as provided in the Revised Credit Agreement. Distributions to the partners are made after all required funding of reserves.

At December 31, 2003, the scheduled maturities under the Credit Agreement are as follows:

Years Ending
2004				$	4,004,990
2005					4,413,661
2006					5,108,405
2007					5,925,752
2008					6,579,627
Thereafter					18,267,447
				$	44,299,882

See Note 9 for subsequent event.

4.	Derivative Instruments

As required under the Credit Agreement to reduce the impact of changes in interest rates on its variable rate debt, PGV entered into 10-year interest rate swap agreements on approximately 75%

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

of the amounts outstanding under the Credit Agreement. The swap agreements qualify for hedge accounting as a cash flow hedge. The average fixed LIBOR is 6.67% under the swap agreements.

For the periods from December 11, 2003 to December 31, 2003, from January 1, 2003 to December 10, 2003, and for the year ended December 31, 2002, unrealized holding gains of $800,333 and $265,699 and unrealized holding loss of $2,163,265, respectively, were recorded in accumulated other comprehensive income/loss to recognize the change in fair value of the swap agreements. An unrealized holding gain of $923,103 was recorded for the three months ended March 31, 2004 (unaudited).

PGV made payments of $1,814,620 under the swap agreements for the year ended December 31, 2002. Payments totaled $1,447,950 for the period January 1, 2003 to December 10, 2003 and $480,157 for the period December 11, 2003 to December 31, 2003. PGV made payments of $231,065 for the three months ended March 31, 2004 (unaudited).

PGV may be exposed to a potential loss in the event of nonperformance by the other parties to the swap agreements, but PGV does not anticipate any such nonperformance. The notional value of the amounts outstanding under the swap agreements is approximately $32 million.

The swap agreements were terminated on June 3, 2004. The unrealized holding loss for the period April 1, 2004 through June 2, 2004 amounted to approximately $31,000 (unaudited).

5.	Power Purchase Agreement

PGV has entered into a long-term non-cancelable power purchase agreement with HELCO. HELCO agreed to purchase up to 30 MW of net output during peak hours and up to 22 MW of net output during off peak hours through the year 2027. The agreement specifies energy rates of the greater of avoided costs of 6.56¢ per kWh for the first 25 MW of peak energy and 5.43¢ per kWh for the first 22 MW of off peak energy. Energy rates for production in excess of 25 MW for peak hours and in excess of 22 MW for off peak hours are greater of the avoided energy payment rates of 4.325¢ per kWh for peak hours and 3.325¢ per kWh for off peak hours. In addition, PGV receives capacity payments for providing peak period energy. Capacity payments are 3.39¢ per kWh for the first 25 MW and 2.14¢ per kWh for the additional 5 MW based on annual capacity payments of $4 million and $504,750, respectively, and 4,718 peak hours in a year.

PGV is subject to sanctions in the power purchase agreement in cases where PGV is not able to provide the agreed upon power output, within a 5% yield. Such sanctions do not result in the agreement becoming cancelable at HELCO's discretion. In 2003 and 2002, PGV was not able to meet the specified goals for power output and as such, was subject to sanctions based on the following: 1) reductions are made to the monthly capacity payments noted above for deficiencies at the above rates and 2) on an annual basis, shortfalls of the on-peak availability provide for payments due of $7,992 per full percentage point below 95% to and including 80% and $11,875 per full percentage point less than 80%. Pursuant to the agreement as summarized above, PGV recognized capacity sanction expenses of $608,831 in fiscal 2002, $313,473 in the period January 1, 2003 to December 10, 2003, and $18,808 in the three-months ended March 31, 2004 (unaudited), based on the capacity shortfalls for these periods.

6.	Royalty and Lease Agreements

PGV has entered into various long-term royalty and lease agreements related to the use of geothermal resources and to the land on which the facility is situated. Such agreements call for PGV to pay royalty payments based on gross revenues derived from energy sales. Royalties are remitted to the State of Hawaii based on steam value at approximately 3% of gross revenue. Royalties to the State of Hawaii were $179,753 in 2002, $497,530 from January 1, 2003 to December 10, 2003 and $30,373 from

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

December 11, 2003 to December 31, 2003. Royalties for the three months ended March 31, 2004 were $157,550 (unaudited). Royalties are remitted to Thermal Power based on steam value. Royalties to Thermal Power were $69,988 in 2002, $191,227 from January 1, 2003 to December 10, 2003 and $11,674 from December 11, 2003 to December 31, 2003. Royalties for the three months ended March 31, 2004 were $66,911 (unaudited). Royalties are remitted to the lessor of the facility site and associated properties, Kapoho Land Partnership ("KLP"), at approximately 3% of steam value. Royalty payments to KLP are subject to minimum payments of $260,520 per year with the minimum payment made for 2003 and 2002. In addition, KLP receives operating lease payments of $167,107 annually for the use of the site. Minimum royalty payments are subject to adjustment every five years based upon changes in the CPI. Payments for the use of the site are subject to renegotiation every five years based on rental value of comparable properties.

At December 31, 2003, the total remaining minimum commitments for royalties and operating leases, excluding the effects of future renegotiations, are as follows:

Years Ending
2004				$	427,627
2005					427,627
2006					427,627
2007					427,627
2008					427,627
Thereafter					8,124,913
				$	10,263,048

7.	Related Party Transactions

During December 1996, PGV and COSI Puna, Inc., an affiliate of Constellation Power, Inc., entered into an Operation and Maintenance Agreement effective as of December 2, 1996. COSI Puna, Inc.'s fees under the agreement are 10% of the total labor plus related burden costs. The fee for 2002 was $251,676 and payments to COSI Puna, Inc. for payroll related costs and fees totaled $2,719,084 in 2002. In connection with CE Puna I's acquisition of AMOR's ownership interest in PGV, COSI Puna, Inc. agreed to waive payment of certain fees payable at the acquisition date. Such payable amounted to $480,726. PGV has recognized the forgiveness of this payable as a capital contribution in the period ended December 10, 2003.

Two employees of Constellation Power, Inc. ("CPI") serve as Owner's Representative and Financial Manager of PGV. In addition, other employees of CPI and its affiliates perform human resources, risk management, environmental and safety, financial and consultation services for PGV. The cost for such services in 2002 totaled $264,000. In connection with CE Puna I's acquisition of AMOR's ownership interest in PGV, CPI agreed to waive payment of all fees payable at the acquisition date. Such payable amounted to $484,000. PGV has recognized the forgiveness of this payable as a capital contribution in the period ended December 10, 2003.

8.	Asset Retirement Obligation

Effective January 1, 2003, PGV adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides the accounting requirements for recognizing an estimated liability for legal obligations associated with the retirement of tangible long-lived assets. PGV measures the liability at fair value when incurred and capitalizes a corresponding amount as part of the book value of the related long-lived assets. The increase in the capitalized cost is included in determining depreciation expense over the estimated useful life of these assets. Since the fair value of the asset retirement obligations ("ARO") is determined using a present value approach, accretion of the liability due to

Puna Geothermal Venture
Notes to Financial Statements
December 31, 2002 and 2003 and March 31, 2004

the passage of time is recognized each period to "Accretion of asset retirement obligations" in PGV's Statements of Operations until the settlement of the liability. A gain or loss is recorded when the liability is settled after retirement. The adoption of SFAS No. 143 on January 1, 2003 resulted in an increase to plant and equipment of $715,148, net of accumulated depreciation and the establishment of an asset retirement obligation liability of $1,872,413. The cumulative effect of this change for periods prior to January 1, 2003 of $1,157,265 is shown as the cumulative effect of change in accounting principle in the Statements of Operations.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, and timing of settlement. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment will be made to the plant and equipment balance.

The change in the "Asset retirement obligation" liability during 2003 was as follows:

Liability at January 1, 2003				$	1,872,413
Accretion expense through December 31, 2003					158,804
Accretion expense – December 11, 2003 to December 31, 2003					9,826
Liability at December 31, 2003					2,041,043
Accretion expense – January 1, 2004 to March 31, 2004 (unaudited)					39,801
Liability at March 31, 2004 (unaudited)				$	2,080,844

The pro-forma asset retirement obligation PGV would have recognized as of January 1, 2002, had PGV implemented SFAS No. 143 as of that date, was approximately $1,760,146 based on the information, assumptions, and interest rates as of January 1, 2003 used to determine the $1,872,413 liability recognized upon the adoption of SFAS No. 143. The following discloses the pro forma effect of the implementation on the Company's net loss for the year ended December 31, 2002, had SFAS No. 143 been adopted by the Company on January 1, 2002:

Net loss, as reported				$	(12,179,557	)
Effect on net loss had SFAS No. 143 been applied					(129,160	)
Net loss, as adjusted				$	(12,308,717	)

9.	Subsequent Event

Constellation Power Corporation sold its interest in CE Puna I and CE Puna to an unrelated third party on June 3, 2004. In connection with this transaction, the Company's note payable to Credit Suisse was paid in full, and the Credit Agreement and Revised Credit Agreement with Credit Suisse and swap agreements were terminated.

Combined Heber and Affiliates

(Debtors-in-Possession)
Report on Audits of Combined Financial Statements
As of December 31, 2002 and December 17, 2003,
And for the years ended December 31, 2001 and 2002, and
for the period from January 1, 2003 to December 17, 2003

Report of Independent Auditors

To the Partners of Combined Heber and Affiliates

In our opinion, the accompanying combined balance sheet and the related combined statements of operations, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Heber Geothermal Company, Heber Field Company, and Second Imperial Geothermal Company (collectively "Heber and Affiliates" or the "Company") at December 31, 2002 and December 17, 2003, and the results of their operations and their cash flows for the years ended December 31, 2001 and 2002, and for the period from January 1, 2003 to December 17, 2003 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 auditing standards generally accepted in the United States of America, which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the combined financial statements, Covanta Energy Corporation and 123 of its subsidiaries, including the Company, filed voluntary petitions on April 1, 2002 with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company's Debtor's Third Amended Joint Plan of Reorganization Under Chapter 11 (Heber Plan) was substantially consummated on December 18, 2003, and the Company emerged from bankruptcy.

As discussed in Note 1 to the financial statements, on December 18, 2003, OrCal Geothermal, Inc. acquired the partnership interests in the Company.

As discussed in Note 5 to the financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets.

/s/ PricewaterhouseCoopers LLP

Sacramento, California
July 19, 2004

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Balance Sheets (in thousands)

				December 31, 2002				December 17, 2003
Assets
Current assets:
Cash				$	57			$	—
Restricted cash and cash equivalents					2,583				1,897
Accounts receivable					9,815				7,183
Prepaid expenses					811				258
Total current assets					13,266				9,338
Property, plant and equipment, net					78,086				69,713
Restricted cash and cash equivalents					3,003				4,064
Total assets				$	94,355			$	83,115
Liabilities and Partners' Capital
Current liabilities:
Accounts payable and accruals				$	3,570			$	2,729
Notes payable					12,519				—
Current portion of finance obligation					10,736				6,112
Total current liabilities					26,825				8,841
Finance obligation, net of current portion					19,729				13,617
Liabilities subject to compromise					51,386				—
Asset retirement obligation					—				2,101
Total liabilities					97,940				24,559
Commitments and contingencies (Notes 4, 6 and 8)
Partners' Capital					(3,585	)			58,556
Total liabilities and partners' capital				$	94,355			$	83,115

The accompanying notes are an integral part of these financial statements

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Statements of Operations (in thousands)

				Year Ended December 31, 2001				Year Ended December 31, 2002				Period from January 1, 2003 to December 17, 2003
Revenues, all from a single customer:
Energy				$	60,140			$	51,291			$	52,417
Capacity					12,570				12,556				12,507
Capacity bonus					1,500				1,230				1,207
					74,210				65,077				66,131
Cost of revenues:
Operating expenses					24,978				26,451				28,775
Depreciation and amortization					9,000				9,088				8,708
					33,978				35,539				37,483
Gross margin					40,232				29,538				28,648
General and administrative expenses					8,515				7,488				29
Income from operations					31,717				22,050				28,619
Other income (expense):
Gain on discharge of liabilities subject to compromise					—				—				31,460
Recovery of bad debt provision					2,109				—				—
Reorganization costs					—				(3,289	)			(4,029	)
Interest income					2,005				141				99
Interest expense					(7,412	)			(3,929	)			(1,794	)
Income before cumulative effect of change in accounting principle					28,419				14,973				54,355
Cumulative effect of change in accounting principle					—				—				(1,660	)
Net income				$	28,419			$	14,973			$	52,695
Pro forma net income reflecting the adoption of SFAS 143 applied retroactively (Note 5) (unaudited)				$	28,268			$	14,822			$	54,355
Pro forma income tax provision (unaudited)				$	9,929			$	5,690			$	20,024
Pro forma net income reflecting tax provision (Note 1) (unaudited)				$	18,490			$	9,283			$	32,671

The accompanying notes are an integral part of these financial statements

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Statements of Partners' Capital (in thousands)

Balance, December 31, 2000				$	(23,064	)
Distributions					(11,865	)
Net income					28,419
Balance, December 31, 2001					(6,510	)
Distributions					(12,048	)
Net income					14,973
Balance, December 31, 2002					(3,585	)
Distributions					(2,577	)
Contributions					12,023
Net income					52,695
Balance, December 17, 2003				$	58,556

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

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Statements of Cash Flows (in thousands)

				Year Ended December 31, 2001				Year Ended December 31, 2002				Period from January 1, 2003 to December 17, 2003
Cash flows from operating activities:
Net income				$	28,419			$	14,973			$	52,695
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization					9,000				9,088				8,708
Accretion of asset retirement obligation					—				—				150
Gain on discharge of liabilities subject to compromise					—				—				(31,460	)
Recovery of doubtful account					(2,109	)			—				—
Cumulative effect of change in accounting principle					—				—				1,660
Changes in operating assets and liabilities:
Accounts receivable					(21,695	)			24,908				2,632
Prepaid expenses					125				70				553
Accounts payable and accrued expenses					2,254				(3,155	)			(841	)
Liabilities subject to compromise					—				—				(19,926	)
Due to related entities					(11,006	)			13,533				—
Net cash provided by operating activities					4,988				59,417				14,171
Cash flows from investing activities:
Change in restricted cash and cash equivalents					(984	)			(61	)			(375	)
Capital expenditures					(1,458	)			(3,334	)			(44	)
Net cash used in investing activities					(2,442	)			(3,395	)			(419	)
Cash flows from financing activities:
Distributions to partners					(11,865	)			(12,048	)			(2,577	)
Contributions from partners					—				—				12,023
Principal payment on finance obligation					(12,364	)			(13,093	)			(10,736	)
Payments on notes payable					—				(9,141	)			(12,519	)
Proceeds from (payments on) other long-term liabilities					21,691				(21,691	)			—
Net cash used in financing activities					(2,538	)			(55,973	)			(13,809	)
Net increase (decrease) in cash and cash equivalents					8				49				(57	)
Cash and cash equivalents, beginning of period					—				8				57
Cash and cash equivalents, end of period				$	8			$	57			$	—
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Interest				$	5,052			$	5,890			$	1,792
Supplemental non-cash investing and financing activities:
Effect of adopting of SFAS No. 143:
Asset retirement cost				$	—			$	—			$	291
Asset retirement obligation				$	—			$	—			$	1,951
Reclassification of amounts due to related entities and accounts payable to liabilities subject to compromise				$	—			$	51,386			$	—

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

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

1.    Business and Significant Accounting Policies

Basis of combination and presentation

The accompanying financial statements have been prepared by combining the following three legal entities, all of which were under common control, through affiliates, by Covanta Energy Corporation ("CEC") for all periods presented prior to December 18, 2003, and effective December 18, 2003 (see discussion below regarding sale of company), by OrCal Geothermal, Inc. ("OrCal"), a wholly owned subsidiary of Ormat Nevada, Inc. (ONI), which in turn is a wholly owned subsidiary of Ormat Technologies, Inc.:

•	Second Imperial Geothermal Company ("SIGC" or "Heber 2"), a California limited partnership, that was formed on November 24, 1992 for the purpose of developing, constructing and operating a geothermal electrical generating facility located in Heber, California.

•	Heber Geothermal Company ("HGC" or "Heber 1"), a California general partnership, that was formed on August 12, 1983 for the purpose of designing, constructing and operating a geothermal electrical generating station located in Heber, California.

•	Heber Field Company ("HFC"), a California general partnership, that was formed on November 1, 1991 for the purpose of acquiring and operating a geothermal field located in Heber, California, and selling the geothermal fluid to HGC and to SIGC.

The combination of the above entities is collectively referred to as "Heber and Affiliates" or the "Company". Intercompany accounts and transactions have been eliminated in the combination.

Bankruptcy and sale transaction

On April 1, 2002 ("Petition Date"), CEC and 123 of its domestic subsidiaries (collectively the "Debtors") filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the "Bankruptcy Code") in the United States Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court"). CEC and these subsidiaries, which include the Company, have been operating their businesses as debtors in possession pursuant to the Bankruptcy Code.

The Company's Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants Statement of Position 90-7 ("SOP 90-7"), Financial Reporting by Entities in Reorganization under the Bankruptcy Code. Accordingly, all pre-petition liabilities believed to be subject to compromise have been segregated in the balance sheet and classified as liabilities subject to compromise, at the estimated amount of allowable claims. As of December 31, 2002 such liabilities consisted mainly of amounts due to related entities (Note 7). Liabilities not believed to be subject to compromise are separately classified as current and non-current.

On September 29, 2003, the court entered an order approving competitive bidding and auction procedures for the purpose of obtaining the highest or best offer for the sale of the Company. On November 19, 2003 the Debtors held an auction before the Court. As a result of the auction, the Debtors determined that the offer submitted by OrCal, was the best and highest bid.

On November 21, 2003, the Bankruptcy Court confirmed the Debtor's Third Amended Joint Plan of Reorganization Under Chapter 11 (Heber Plan) and approved the sale of interests to OrCal. On December 18, 2003, each of the conditions precedent to the Confirmation Date pursuant to Heber Plan occurred or was waived in accordance with the Heber Plan, and the Company was sold to OrCal for a combined purchase price of approximately $180 million.

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

Cash

Cash consists of deposit accounts with banks.

Restricted cash and cash equivalents

Under the terms of the lease agreement (Note 4), the Company was required to maintain a debt service reserve and operating fund accounts that have been classified as restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts. The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents. Due to the revolving nature of the operating fund account, the amounts are classified as current assets. Due to the long-term nature of the debt service reserve account, the amounts are classified as non-current assets.

Concentration of credit risk

Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable. The Company places its temporary cash investments with high credit quality financial institutions located in the United States of America. At December 31, 2002 and December 17, 2003, the Company maintained all of its deposits in three U.S. financial institutions that were federally insured up to $100 per financial institution. All of the Company's revenues, and the related receivable balances, are earned from one customer, Southern California Edison Company ("SCE"). The Company has historically been able to collect on all of its receivable balances from SCE, accordingly no provision for doubtful accounts has been made.

Property, plant and equipment

Property, plant and equipment are stated at cost. All costs associated with acquisition, development and construction of power plant facilities are capitalized. Major improvements are capitalized, and repairs and maintenance costs are expensed. Power plants were depreciated using the straight-line method over the estimated service period of 24 to 28 years. The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently in operating income.

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

Long-lived assets 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. As further discussed in Note 6, Heber 1 is currently operating at a level that is close to the minimum performance requirements set forth in its power purchase agreement, however, the Company believes that no impairment for long-lived assets exists as the fair value of the assets, based on, an independent valuation of such long-lived assets in connection with the sale of the Company discussed in Note 1, was greater than the net book value of such assets. While management currently believes that no impairment exists for long-lived assets, future estimates as to the recoverability of such assets may change based on revised circumstances.

Derivative instruments

Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature,

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value 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 that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

The Company is subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15 (DIG Issue No. C15), Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also under DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. The Company has power sales agreements that qualify as derivative instruments under DIG Issue No. C15 because they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. The adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on the Company's consolidated financial position and results of operations.

In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 superseded DIG Issue No. C11 Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception, and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company). In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires contracts that did not previously qualify for the normal purchases normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortized such fair value over the remaining contract period. Upon adoption of DIG Issue No. C20, the Company elected the normal purchase and normal sales scope exception under FAS No. 133 related to its power purchase agreements. Such adoption did not have a material impact on the Company's consolidated financial position and results of operations.

Revenue recognition

Revenue from the sale of electricity is recorded based upon output delivered and capacity provided at rates as specified under terms of long-term power purchase agreements (Note 6).

Income taxes

The net income of the Company for income tax purposes is the responsibility of the individual partners. Accordingly, no provision for income taxes has been recorded in the accompanying financial statements. The pro forma net income on the statement of operations reflects a tax provision of 38%, the effective rate of the company that acquired the Company's ownership interest.

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

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

and liabilities and disclosure of contingent assets and liabilities at the date of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Fair value of financial instruments

The carrying amount of cash, restricted cash and cash equivalents approximates fair value because of the short maturity of those instruments. The fair value of long-term debt is estimated based on the current borrowing rates for similar issues, which approximates carrying amount.

Recently issued accounting pronouncements

In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. The amendments in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. In addition, SFAS No. 149 amends the definition of an "underlying" to conform it to language used in FIN No. 45 and amends certain other existing pronouncements. The provisions of SFAS No. 149 that relate to SFAS No. 133 "Implementation Issues" that have been effective for periods that began prior to June 15, 2003 should continue to be applied in accordance with their respective effective dates. The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company adopted the provisions of SFAS No. 149 effective July 1, 2003, which did not have a material impact on its results of operations and financial position as of December 17, 2003.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability because that financial instrument embodies an obligation of the issuer. The requirements of SFAS No. 150 are effective for financial instruments entered into or modified after May 31, 2003. For financial instruments created prior to the issuance date of SFAS No. 150, transition shall be achieved by reporting the cumulative effect of a change in accounting principle. The Company adopted the provisions of SFAS No. 150 effective July 1, 2003, which did not have a material impact on its results of operations and financial position as of December 17, 2003.

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

2.    Property, Plant and Equipment

Property, plant and equipment, consists of the following:

				December 31, 2002				December 17, 2003
Power plant facility				$	154,870			$	154,915
Asset retirement cost					—				527
					154,870				155,442
Less accumulated depreciation					(76,784	)			(85,729	)
				$	78,086			$	69,713

Included in the power plant facility are assets recorded under capital lease, as further discussed in Note 4.

3.    Notes Payable

On December 17, 1999, the Company entered into a note agreement with General Electric Capital Corporation ("GECC") for $21.7 million. Under the agreement, principal was due by July 31, 2003. Interest was payable quarterly and was computed at 7.5% per annum through March 14, 2001. Then, for the periods from March 14, 2001 to January 31, 2002 and from January 31, 2002 to July 31, 2003, interest was computed at a rate per annum of LIBOR plus 2.75% and LIBOR plus 4.75%, respectively.

The notes were fully paid during the period from January 1, 2003 to December 17, 2003.

4.    Finance Obligation

Construction of the Heber 2 project was financed through a $115 million construction loan obtained by SIGC from GECC. On September 1, 1993, SIGC sold the project to GECC for a purchase price equal to the balance of the construction loan and simultaneously agreed to lease back the project under a lease with an initial term that would have expired in 2008.

The lease was collateralized by all of SIGC assets including the power purchase agreement (PPA) (Note 6), geothermal leases, SCE payments and cash reserve through an escrow agreement.

All revenues from the project were required to be deposited into a series of escrow accounts administered by an independent escrow agent. The related project agreements provided for the disbursement of funds by the escrow agent for the project's operating costs and lease payments, as well as the establishment of certain long-term cash escrow accounts. During the initial lease term, these long-term cash escrow accounts could have been used in limited situations to pay current operating and lease expenses to the extent that project revenues were not sufficient to fund such expenses.

In connection with OrCal's purchase of the Company, the lease was cancelled and Ormat Technologies, Inc. purchased the lessor position from GECC.

5.    Asset Retirement Obligation

The Company adopted SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, effective January 1, 2003. Under SFAS No. 143, entities are required to record 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 capping wells and post-closure costs of geothermal power

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

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, an entity settles the obligation for its recorded amount or incurs a gain or loss. On January 1, 2003 the Company recorded a cumulative effect of change in accounting principle of $1,660. As a result of adopting the provisions of SFAS No. 143, the net income for period from January 1, 2003 to December 17, 2003, decreased by approximately $165.

The following table summarizes the impact on the Company balance sheet following the adoption of SFAS No. 143:

				Balance at December 31, 2002				Change Resulting From Application of SFAS No. 143				Balance at January 1, 2003
Property, plant and equipment				$	154,870			$	527			$	155,397
Accumulated depreciation					(76,784	)			(236	)			(77,020	)
Net property, plant and equipment				$	78,086			$	291			$	78,377
Non-current asset retirement obligation				$	—			$	1,951			$	1,951

The unaudited pro-forma changes to the non-current asset retirement obligation, based on the information, assumptions, and interest rates as of January 1, 2003, are presented below to show what the Company would have reported if the provisions of SFAS No. 143 had been in effect for the periods presented below:

				Year Ended December 31, 2002				For the Period From January 1, 2003 to December 17, 2003
Balance, beginning of period				$	1,800			$	1,951
Accretion expense					151				150
Balance, end of period				$	1,951			$	2,101

6.    Power Purchase Agreements

The Company has two power purchase agreements (PPAs) with SCE. The PPAs provide for the sale of capacity and energy through their respective terms, one expiring in 2015 and the other in 2023. Under the PPAs, the Company receives a fixed energy payment through April 30, 2007, 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.

The temperature of the geothermal resource at the Heber 1 project has declined from the date on which the project commenced operations and as a result is currently operating at a level that is close to the minimum performance requirements set forth in its power purchase agreement. If the Company fails to upgrade the facilities and the project's performance deteriorates below minimum capacity requirements, the Company will be obligated to pay a one-time penalty to SCE of approximately $500,000 per each MW of reduced capacity.

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

7.    Related Party Transactions

Operation and Maintenance Contracts

The Heber plant was operated by Covanta Imperial Power Services, Inc ("CIPS"), an affiliated entity, under a long term agreement, for the same term as the PPA. In return for providing all personnel, equipment, materials, supplies and services to operate and maintain the plant, CIPS received a fixed fee, which escalates by 5% annually, and received reimbursement for its non-labor costs.

HFC was operated by Covanta Geothermal Operations, Inc ("CGO"), an affiliated entity, under a long term agreement similar to CIPS agreement with HGC.

The Heber 2 plant was operated by Covanta SIGC Geothermal Operations, Inc. ("SIGC Operator"), an affiliated entity, under a long term agreement that extended for the life of the PPA. SIGC Operator was responsible for providing all customary operations and maintenance services. SIGC Operator was reimbursed for all costs incurred in running the plant. The contract also provided for an annual bonus to be paid to the operator if electricity production and on-peak capacity factors exceeded specified levels.

Amounts recorded for operation and maintenance are as follows:

				Year Ended December 31, 2001				Year Ended December 31, 2002				Period from January 1, 2003 to December 17, 2003
O&M expenses				$	9,935			$	9,316			$	9,375
Operating Bonus					1,642				1,657				1,682
				$	11,577			$	10,973			$	11,057

Management Services

Management services were provided by ERC Energy, Inc (an affiliated entity) to HGC and HFC, and by Amor 14 (an affiliated entity) to SIGC. For the years ended December 31, 2001 and 2002 and for the period from January 1, 2003 to December 17, 2003 the fees relating to those services amounted to $228, $240 and $243, respectively.

Allocated Administrative Costs

Administrative costs incurred by CEC were allocated to the Company. Such costs amounted to $7,226 and $7,337 for the years ended December 31, 2001 and 2002, respectively. No such costs were allocated to the Company in 2003.

As of December 31, 2002, amounts due to related entities was $50,749, which resulted from expenses to be paid under the operations and maintenance contracts, management service fees, and allocated administrative costs. In 2003, all amounts due to related entities were determined to be rejected claims under the bankruptcy proceedings, and as such the balance as of December 31, 2002 has been included in liabilities subject to compromise on the accompanying balance sheet. The outstanding balance of $31,460 as of December 17, 2003, was discharged and recognized as a gain on discharge of liabilities subject to compromise on the accompanying statement of operations.

8.    Commitment and contingencies

Contingencies

The lessors owning interest in the Heber Geothermal Area (an area where the Company obtains its geothermal resource) filed a claim in the Company's bankruptcy proceedings totaling approximately

Combined Heber and Affiliates
(California Limited Partnerships)
(Debtors-in-Possession)
Notes to Financial Statements (in thousands)

$80 million. The Company reached a full and final settlement with a group of the royalty related claims totaling $2.175 million, which was fully executed on October 6, 2003 and approved by the bankruptcy court on October 10, 2003. In addition, it was agreed that the method of calculating royalties would remain the same. The Company also paid legal fees of $550 related to that group. Such amounts have been reflected in operating expenses in the accompanying statement of operations for the period from January 1, 2003 to December 17, 2003.

For those royalty related claims not included in the group settlement, the Company began negotiations to settle such claims. The Company had accrued approximately $744 as of December 17, 2003 as their best estimate of the settlements remaining, including amounts not yet paid for the group settlement mentioned above, which is included in account payable and accruals on the accompanying balance sheet. In 2004, a settlement was reached with most of the remaining parties for approximately $478. The Company believes that the remaining $266 accrued will satisfy the remaining parties not yet fully settled or those for which settlements have been reached but have not yet paid.

For lessors with non-royalty surface right related claims, the Company agreed to pay a one time payment of $390, and increase prospective annual rental and/or severance payments by approximately $67 per year, which will be adjusted for the cost of living each year.

In response to an order issued by a California State Court of Appeal, the California Public Utilities Commission ("CPUC"), has commenced an administrative proceeding in order to address short run avoided cost pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The court directed that the CPUC modify short run avoided cost pricing on a retroactive basis to the extent that the CPUC determined that short run avoided cost prices were not sufficiently "accurate" or "correct." If the short run avoided cost prices charged during the period in question were determined by the CPUC to not be "accurate" or "correct," retroactive price adjustments could be required for either of the Company's Qualifying Facilities. Currently it is not possible to predict the outcome of such proceeding, however, any retroactive price adjustment required to be made in relation to either of the Company's projects may require such projects to make refund payments or receive less from future revenues, which could materially affect the financial condition, future results and cash flow of the Company.

Commitment

HFC pays monthly royalties under several mineral right leases. The monthly royalties total approximately 5% of the HGC's and SIGC's revenues, respectively, less transmissions and scheduling charges. Royalty expenses recorded for the years ended December 31, 2001 and 2002, and for the period from January 1, 2003 to December 17, 2003 totaled $4,341, $3,194 and $3,509, respectively.

Mammoth Pacific, L.P.

Report on Audits of Financial Statements
As of December 31, 2002 and September 30, 2003,
and for the year ended December 31, 2002, and for
nine-month period ended September 30, 2003
And
Unaudited Financial Statements
for the nine-month period ended September 30,
2002

Report of Independent Auditors

To the Partner of Mammoth Pacific, L.P. (OrMammoth, Inc.)

In our opinion, the accompanying balance sheets and the related statements of operations, of partners' capital and of cash flows present fairly, in all material respects, the financial position of Mammoth Pacific, L.P. ("Partnership") at December 31, 2002 and September 30, 2003, and the results of its operations and its cash flows for the year ended December 31, 2002 and for the nine-month period ended September 30, 2003 in conformity with accounting principles generally accepted in the United States of America. 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 audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the financial statements, effective January 1, 2003, the Partnership adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets.

/s/ PricewaterhouseCoopers LLP

Sacramento, California
January 26, 2004

Mammoth Pacific, L.P.
(A California Limited Partnership)
Balance Sheets
December 31, 2002 and September 30, 2003

				December 31, 2002				September 30, 2003
Assets
Current assets:
Cash and cash equivalents				$	4,416,984			$	8,096,196
Accounts receivable					2,705,284				3,140,124
Prepaid expenses and other					1,282,268				902,713
Total current assets					8,404,536				12,139,033
Property, plant and equipment, net					93,198,635				90,144,731
Total assets				$	101,603,171			$	102,283,764
Liabilities and Partners' Capital
Current liabilities:
Accounts payable				$	14,561			$	118,933
Accrued and other liabilities					678,997				296,512
Due to related entities					168,900				238,579
Total current liabilities					862,458				654,024
Due to related entities					752,631				709,210
Asset retirement obligation					—				2,930,664
Total liabilities					1,615,089				4,293,898
Commitments and contingencies (Notes 3, 4, 5 and 6)
Partners' capital					99,988,082				97,989,866
Total liabilities and partners' capital				$	101,603,171			$	102,283,764

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

Mammoth Pacific, L.P.
(A California Limited Partnership)
Statements of Operations
For the year ended December 31, 2002 and for the nine-month periods ended
September 30, 2002 and 2003

				Year Ended December 31, 2003				Nine Months Ended September 30,
								2002				2003
								(Unaudited)
Revenues:
Energy				$	10,040,290			$	6,790,268			$	8,624,754
Capacity					4,282,968				3,883,062				3,725,617
Capacity bonus					265,228				177,758				181,116
Total revenues					14,588,486				10,851,088				12,531,487
Cost of revenues:
Operating expenses					4,510,896				3,239,707				3,550,965
Royalties					685,392				490,725				902,012
Property taxes					823,682				606,902				648,346
Depreciation and amortization					5,294,823				3,968,353				4,004,851
Gross margin					3,273,693				2,545,401				3,425,313
General and administrative expenses					114,620				86,110				153,000
Income from operations					3,159,073				2,459,291				3,272,313
Other income:
Interest income					411,036				398,062				36,471
Income before change in accounting principle					3,570,109				2,857,353				3,308,784
Cumulative effect of change in accounting prinicple					—				—				(2,107,000	)
Net income				$	3,570,109			$	2,857,353			$	1,201,784
Proforma net income reflecting the adoption of SFAS No. 143 (Note 3) applied retroactively				$	3,334,109			$	2,680,353			$	3,308,784
Proforma income tax provision (unaudited)				$	1,356,641			$	1,085,794			$	456,678
Proforma net income reflecting tax provision (Note 1) (unaudited)				$	2,213,468			$	1,771,559			$	745,106

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

Mammoth Pacific, L.P.
(A California Limited Partnership)
Statements of Partners' Capital
For the year ended December 31, 2002 and for the nine-month period ended
September 30, 2003

				General Partners								Limited Partners
				Mammoth Geothermal Company				CD Mammoth Lakes I				Pacific Geothermal Company				CD Mammoth Lakes I				CD Mammoth Lakes II				Total Partners' Capital
Balance, January 1, 2002				$	59,615,568			$	1,216,644			$	1,216,644			$	29,199,462			$	30,416,106			$	121,664,424
Distributions					(12,370,760	)			(252,465	)			(252,465	)			(6,059,148	)			(6,311,613	)			(25,246,451	)
Net income					1,749,354				35,701				35,701				856,826				892,527				3,570,109
Balance, December 31, 2002					48,994,162				999,880				999,880				23,997,140				24,997,020				99,988,082
Distributions					(1,568,000	)			(32,000	)			(32,000	)			(768,000	)			(800,000	)			(3,200,000	)
Net income					588,873				12,018				12,018				288,428				300,446				1,201,784
Balance, September 30, 2003				$	48,015,035			$	979,898			$	979,898			$	23,517,568			$	24,497,466			$	97,989,866

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

Mammoth Pacific, L.P.
(A California Limited Partnership)
Statements of Cash Flows
For the year ended December 31, 2002 and for the nine-month periods ended
September 30, 2002 and 2003

				Year Ended December 31, 2002				Nine Months Ended September 30,
								2002				2003
				(Unaudited)
Cash flows from operating activities:
Net income				$	3,570,109			$	2,857,353			$	1,201,784
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation					5,294,823				3,968,353				4,004,851
Acccretion of asset retirement obligation					—				—				165,664
Cumulative effect of change in accounting principle					—				—				2,107,000
Changes in operating assets and liabilities:
Accounts receivable					13,072,566				12,370,819				(434,840	)
Other receivables					8,153,363				8,153,363				—
Prepaid expenses and other					(223,864	)			83,091				379,555
Accounts payable					(449,893	)			(169,485	)			104,372
Accrued and other liabilities					(2,725,554	)			(1,856,123	)			(382,485	)
Due to related entities					107,057				(47,369	)			26,258
Net cash provided by operating activities					26,798,607				25,360,002				7,172,159
Cash flows from investing activities:
Change in restricted cash					378,117				378,117				—
Capital expenditures					(1,962,913	)			(1,806,909	)			(292,947	)
Net cash used in operating activities					(1,584,796	)			(1,428,792	)			(292,947	)
Cash flows from financing activities:
Distributions to Partners					(25,246,451	)			(22,846,451	)			(3,200,000	)
Net cash used in financing activities					(25,246,451	)			(22,846,451	)			(3,200,000	)
Net (decrease) increase in cash and cash equivalents					(32,640	)			1,084,759				3,679,212
Cash and cash equivalents, beginning of period					4,449,624				4,449,624				4,416,984
Cash and cash equivalents, end of period				$	4,416,984			$	5,534,383			$	8,096,196
Supplemental disclosure of cash flow information:
Effect of adopting of SFAS No. 143 (Note 3):
Asset retirement cost, net				$	—			$	—			$	658,000
Asset retirement obligation				$	—			$	—			$	2,765,000

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

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

1.    Business and Summary of Significant Accounting Policies

Business

Mammoth Pacific, L.P., a California limited partnership (the Partnership), owns and operates three geothermal electric generation plants located in Mammoth Lakes, California. Such geothermal plants are collectively referred to herein as the "Project".

The partners are Mammoth Geothermal Company (MGC) and Pacific Geothermal Company (PGC), which are both wholly owned subsidiaries of Covanta Energy Corporation (CEC), and CD Mammoth Lakes I (CDI) and CD Mammoth Lakes II (CDII), which are both wholly owned subsidiaries of Constellation Energy Inc., which is a wholly owned subsidiary of Constellation Holdings, Inc., which is a wholly owned subsidiary of Baltimore Gas and Electric Corporation.

The partners' general and limited partnership interests as of December 31, 2002 and September 30, 2003 are as follows

General partners:

MGC        49%
CDI            1%

Limited partners:

PGC            1%
CDI            24%
CDII           25%

All income, loss, tax deductions and credits, cash distributions from operations, and net proceeds from dissolution and liquidation of the Partnership shall be allocated to the partners in percentages equal to their partnership interests.

Interim financial data

The interim financial data for the nine months ended September 30, 2002 is unaudited; however, in the opinion of the Partnership, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for the interim period.

Cash and cash equivalents

The Partnership considers all investments purchased with an original maturity of three months or less to be cash equivalents.

Concentration of credit risk

Financial instruments that potentially subject the Partnership to concentration of credit risk consist principally of temporary cash investments and accounts receivable. The Partnership places its temporary cash investments with high credit quality financial institutions located in the United States of America. At December 31, 2002 and September 30, 2003, the Partnership maintained all of its deposits in one U.S. financial institution that is federally insured up to $100,000. All of the Partnership's revenues, and the related receivable balances, are earned from one power company, Southern California Edison Company.

Property, plant and equipment

Property, plant and equipment are stated at cost. All costs associated with acquisition, development and construction of power plant facilities are capitalized. Major improvements are capitalized, and

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

repairs and maintenance costs are expensed. Power plants are depreciated using the straight-line method over the estimated service period of 28 years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets: Transportation equipment, five years, Furniture and fixtures, five to seven years. The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently.

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

Long-lived assets 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

Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value 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 that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

The Company is subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15 (DIG Issue No. C15), Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also under DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. The Company has power sales agreements that qualify as derivative instruments under DIG Issue No. C15 because they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. The adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on the Company's consolidated financial position and results of operations.

In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 superseded DIG Issue No. C11 Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception, and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company). In conjunction with initially applying the implementation guidance, DIG Issue No.C20 requires contracts that did not previously qualify for the

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

normal purchases normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortized such fair value over the remaining contract period. Upon adoption of DIG Issue No. C20, the Company elected the normal purchase and normal sales scope exception under FAS No. 133 related to its power purchase agreements. Such adoption did not have a material impact on the Company's consolidated financial position and results of operations.

Income taxes

The net income of the Partnership for income tax purposes is the responsibility of the individual partners. Accordingly, no provision for income taxes has been recorded in the accompanying financial statements. The proforma net income on the statement of operations reflects a tax provision of 38%, the effective rate of the company that acquired MGC and PGC's ownership interest (Note 7).

Revenue recognition

Revenue from the sale of electricity is recorded based upon output delivered and capacity provided at rates as specified under terms of long-term power purchase agreements (see Note 4).

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 disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Fair value of financial instruments

The fair value of cash and cash equivalents, accounts receivable, and accounts payable approximate their reported carrying amounts because of the short maturity of those instruments.

Recently issued accounting pronouncements

In July 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. They also issued SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, and SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in August and October 2001, respectively.

SFAS No. 141 requires all business combinations initiated after June 30, 2001 be accounted for under the purchase method. SFAS No. 141 supersedes Accounting Principles Board (APB) Opinion No. 16, Business Combinations, and SFAS No. 38, Accounting for Pre-acquisition Contingencies of Purchased Enterprises, and is effective for all business combinations initiated after June 30, 2001.

SFAS No. 142 addresses the financial accounting and reporting for acquired goodwill and other intangible assets. Under the new rules, the Partnership is no longer required to amortize goodwill and other intangible assets with indefinite lives, but will be subject to periodic testing for impairment. SFAS No. 142 supersedes APB Opinion No. 17, Intangible Assets. The Partnership adopted the provisions of SFAS No. 142 effective January 1, 2002, which did not have a material impact on its results of operations and financial position, as the Partnership did not have any material amounts of goodwill and other intangible assets.

As further discussed in Note 3, the Partnership adopted the provisions of SFAS No. 143 effective January 1, 2003.

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

SFAS No. 144 establishes a single accounting model for the impairment or disposal of long-lived assets, including discontinued operations. SFAS No. 144 superseded SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and APB Opinion No. 30, Reporting the Results of Operations-- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. The Partnership adopted the provisions of SFAS No. 144 effective January 1, 2002, which did not have a material impact on its results of operations and financial position.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. The amendments in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. In addition, SFAS No. 149 amends the definition of an "underlying" to conform it to language used in FIN No. 45 and amends certain other existing pronouncements. The provisions of SFAS No. 149 that relate to SFAS No. 133 "Implementation Issues" that have been effective for periods that began prior to June 15, 2003 should continue to be applied in accordance with their respective effective dates. The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Partnership adopted the provisions of SFAS No. 149 effective July 1, 2003, which did not have a material impact on its results of operations and financial position as of September 30, 2003.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. SFAS No. 150 establishes standards for how an issuer classifies and measures in its statement of financial position certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability because that financial instrument embodies an obligation of the issuer. The requirements of SFAS No. 150 are effective for financial instruments entered into or modified after May 31, 2003. For financial instruments created prior to the issuance date of SFAS No. 150, transition shall be achieved by reporting the cumulative effect of a change in accounting principle. The Partnership adopted the provisions of SFAS No. 150 effective July 1, 2003, which did not have a material impact on its results of operations and financial position as of September 30, 2003.

2.    Property, Plant and Equipment

Property, plant and equipment, consists of the following:

				December 31,				September 30,
				2002				2003
Plant and related equipment				$	152,196,497			$	152,181,247
Transportation equipment					181,442				181,442
Furniture and fixtures					117,665	��			120,667
Asset retirement cost					—				1,097,000
					152,495,604				153,580,356
Less accumulated depreciation					(59,296,969	)			(63,435,625	)
				$	93,198,635			$	90,144,731

3.    Asset Retirement Obligation

The Partnership adopted SFAS No. 143 effective January 1, 2003. Under SFAS No. 143, entities are required to record the fair value of a legal liability for an asset retirement obligation in the period in

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

which it is incurred. The Partnership's legal liabilities include capping wells and post-closure costs of geothermal power producing sites. When a new liability for asset retirement obligations is recorded, the Partnership 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, an entity settles the obligation for its recorded amount or incurs a gain or loss. On January 1, 2003 the Partnership recorded a cumulative effect of change in accounting principle of $2,107,000, net of related tax benefit of $0. As a result of adopting the provisions of SFAS No. 143, the net income for the nine-month period ended September 30, 2003 decreased by approximately $166,000. The pro-forma amounts shown on the statements of operations have been adjusted for the effect of retroactive application of SFAS No. 143.

The following table summarizes the impact on the Partnership's balance sheet following the adoption of SFAS No. 143:

								Change
				Balance at				Resulting from				Balance at
				December 31,				Application of				January 1,
				2002				SFAS No. 143				2003
Property, plant and equipment				$	152,495,604			$	1,097,000			$	153,592,604
Accumulated depreciation					(59,296,969	)			(439,000	)			(59,735,969	)
Net property, plant and equipment				$	93,198,635			$	658,000			$	93,856,635
Non-current asset retirement obligation				$	—			$	2,765,000			$	2,765,000

The unaudited pro-forma changes to the non-current asset retirement obligation, based on the information, assumptions, and interest rates as of January 1, 2003, are presented below to show what the Partnership would have reported if the provisions of SFAS No. 143 had been in effect for the periods presented below:

				Year Ended				Nine Months Ended
				December 31,				September 30,
				2002				2003
Balance at beginning of period				$	2,565,000			$	2,765,000
Accretion expense					200,000				165,664
Balance at end of period				$	2,765,000			$	2,930,664

4.    Power Purchase Agreements

The Partnership has three power purchase agreements (the PPA's) with Southern California Edison Company (SCE), that provide for the sale of capacity and energy through their respective terms, expiring from 2015 to 2020. Under the PPA's, the Partnership received payments based on SCE's short-run avoided cost (SRAC) and receives a fixed energy payment starting in May 2002 through April 2007, and thereafter based on SCE's SRAC. The PPA's provide for firm capacity and bonus payments established by the contracts and are paid to the Partnership each month through the contracts' term based on plant performance. Bonus capacity payments are earned based on actual capacity available during certain peak hours.

5.    Commitments and Contingencies

The geothermal resources being utilized by the Project are owned by unrelated parties, which receive royalties based on a percentage of gross revenues from the sale of energy.

Mammoth Pacific, L.P.
(A California Limited Partnership)
Notes to Financial Statements

Effective January 1, 1995, the Partnership entered into an operating agreement with a wholly owned subsidiary of CEC (the Operator), for the operation and maintenance of the Project. Operator fees are equal to the Operator's labor costs and overhead, plus a $15,000 annual administration fee. Total expenses incurred under this agreement were approximately $1,851,200, $1,296,300 and $1,396,200 for the year ended December 31, 2002, and for the nine-month periods ended September 30, 2002 (unaudited) and 2003, respectively, of which approximately $147,100 and $203,300 was included in due to related entities at December 31, 2002 and September 30, 2003, respectively.

The Partnership is planning to construct a pipeline and two new production wells for a total expected cost of approximately $5 million to be completed by January 2006.

Subsequent to September 30, 2003, in response to an order issued by a California State Court of Appeal, the California Public Utilities Commission, "CPUC", has commenced a proceeding to address SRAC pricing for Qualifying Facilities for the period December 2000 to March 2001. The court directed that the CPUC modify SRAC pricing on a retroactive basis to the extent the CPUC determined that SRAC prices were not sufficiently "accurate" or "correct." If the SRAC prices during the period in question were determined by the CPUC to not be "accurate" or "correct," retroactive price adjustments could be required. Currently it is not possible to predict the outcome of such proceeding, however, any retroactive price adjustment may require the Partnership to make refund payments or receive less from future revenues, which could materially affect the financial condition, future results and cash flows.

6.    Related Party Transactions

MGC has been designated as the managing general partner and is reimbursed for direct expenses and allocated costs incurred on behalf of the Partnership. Total expenses incurred were approximately $73,600, $11,300 and $152,700 for the year ended December 31, 2002, and for the nine-month periods ended September 30, 2002 (unaudited) and 2003, respectively.

Included in the amount due to related entities are amounts due to MGC of approximately $752,600 and $709,200 as of December 31, 2002 and September 30, 2003, respectively, for advances received. Such amounts are to be repaid monthly, subject to available operating cash flow, over a 20-year period beginning January 1, 1996.

7.    Subsequent Events

On December 18, 2003, the partnership interests owned by MGC and PGC were sold to an unrelated entity.

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6,250,000 Shares

Common Stock

PROSPECTUS
                  2004

LEHMAN BROTHERS
Sole Book-Running Manager

DEUTSCHE BANK SECURITIES
Joint Lead Manager

RBC CAPITAL MARKETS

WELLS FARGO SECURITIES

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.    Other Expenses of Issuance and Distribution

The following table sets forth the various expenses, other than the underwriting discounts and commissions, payable by us in connection with the sale and distribution of the securities being registered. All amounts shown are estimates, except the Securities and Exchange Commission registration fee, the National Association of Securities Dealers, Inc. filing fee and the New York Stock Exchange application fee.

SEC registration fee				$	14,571
NASD filing fee				$	12,000
New York Stock Exchange application fee				$	200,000
Accounting fees and expenses				$	1,200,000
Legal fees and expenses				$	750,000
Printing and engraving expenses				$	550,000
Transfer agent fees and expenses				$	14,900
Blue sky fees and expenses				$	3,000
Miscellaneous fees and expenses				$	384,029
Total				$	3,128,500

Item 14.    Indemnification of Directors and Officers

Section 145 of the Delaware General Corporation Law provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with any threatened, pending or completed actions, suits or proceedings in which such person is made a party by reason of such person being or having been a director, officer, employee or agent to Ormat Technologies, Inc. The Delaware General Corporation Law provides that Section 145 is not exclusive of other rights to which those seeking indemnification may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise.

Section 102(b)(7) of the Delaware General Corporation Law permits a corporation to provide in its certificate of incorporation that a director of the corporation shall not be personally liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability for any breach of the director's duty of loyalty to the corporation or its stockholders, for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, for unlawful payments of dividends or unlawful stock repurchases, redemptions or other distributions, or for any transaction from which the director derived an improper personal benefit.

Article Eleventh of Ormat Technologies, Inc.'s certificate of incorporation provides that a director of Ormat Technologies, Inc. shall not be liable to Ormat Technologies, Inc. or its stockholders for monetary damages for breach of fiduciary duty as a director to the fullest extent permitted by Delaware law. In addition, Section 10.1 of Ormat Technologies, Inc.'s by-laws provides that Ormat Technologies, Inc. shall indemnify its directors and officers to the fullest extent permitted by Delaware law, including all expenses liability and loss actually and reasonably incurred or suffered by such director or officer in connection therewith in defending or otherwise participating in any proceeding in advance of its final disposition.

Prior to the completion of this offering, we intend to enter into indemnification agreements with our directors and officers. The indemnification agreements provide indemnification to our directors and officers under certain circumstances for acts or omissions which may not be covered by directors' and officers' liability insurance, and may, in some cases, be broader than the specific indemnification provisions contained under Delaware law. We have also obtained directors' and officers' liability insurance, which insures against liabilities that our directors or officers may incur in such capacities.

II-1

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Item 15.    Recent Sales of Unregistered Securities

On June 30, we issued 1,160,714 shares of our common stock to Ormant Industries in connection with the capitalization of an outstanding loan in the amount of $20.0 million with Ormant Industries. We have relied on the private placement exemption pursuant to Section 4(2) of the Securities Act of 1933, as amended, with respect to the issuance of such shares.

Item 16.    Exhibits and Financial Statement Schedules

Exhibit No.				Document
	1.1			Form of Underwriting Agreement*
	3.1			Second Amended and Restated Certificate of IncorporationIncorporation*
	3.2			Second Amended and Restated By-lawsBy-laws*
	4.1			Form of Common Share Stock Certificate*Certificate
	4.2			Form of Preferred Share Stock Certificate*
	4.3			Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust CompanyCompany*
	5.1			Opinion of Chadbourne & Parke LLP, related to the shares of common stock being sold in the initial public offering
	8.1			Opinion of Chadbourne & Parke LLP, related to tax mattersmatters*
	10.1			Financing Agreements
	10.1.1			Foreign Currency Loan Agreement, dated June 1, 2004, between Ormat Technologies, Inc. and United Mizrahi Bank LTD.*
	10.1.2			Amended and Restated Bridge Loan Agreement, dated October 2, 2003, by and between Ormat Nevada, Inc. and Bank Leumi USA*
	10.1.3			Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M.*
	10.1.4			Credit Agreement, dated as of December 31, 2002, among ORMESA LLC, United Capital, a division of Hudson United Bank and the Lenders party to such agreement from time to time*
	10.1.5			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*
	10.1.6			Credit Agreement, dated May 13, 1996, between Ormat-Leyte and Export-Import Bank of the United States*
	10.1.7			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*
	10.1.8			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*

II-2

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Exhibit No.				Document
	10.1.9			Loan Agreement, dated October 1, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.10			Amendment No. 1 to Loan Agreement, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.11			Capital Note, dated December 22, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.12			Amendment to Capital Note, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.13			Guarantee Fee Agreement, dated January 1, 1999, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.14			Reimbursement Agreement, dated July 15, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.15			Services Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.1.16			Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United BankBank*
	10.1.17			First Amendment to Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United BankBank*
	10.1.18			Subordination Agreement, dated June 30, 2004, by and between Ormat Technologies, Inc. and Hudson United BankBank*
	10.2			Purchase Agreements
	10.2.1			Purchase and Sale Agreement, dated April 22, 2004, by and among Constellation Power, Inc. and Cosi Puna, Inc. and ORNI 8 LLC and Ormat Nevada, Inc.*
	10.2.2			Purchase Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.3			Power Purchase Agreements
	10.3.1			Power Purchase Contract, dated July 18, 1984, between Southern California Edison Company and Republic Geothermal, Inc.*
	10.3.2			Amendment No. 1, to the Power Purchase Contract, dated December 23, 1988, between Southern California Edison Company and Ormesa Geothermal*
	10.3.3			Power Purchase Contract, dated June 13, 1984, between Southern California Edison Company and Ormat Systems, Inc.*
	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*
	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*
	10.3.6			Settlement Agreement and Amendment No. 2, to Power Purchase Contract, dated August 7, 1995, between HGC and Southern California Edison Company*
	10.3.7			Power Purchase Contract dated, April 16, 1985, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.8			Amendment No. 1, dated as of October 23, 1987, between Southern California Edison Company and Second Imperial Geothermal Company*

II-3

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Exhibit No.				Document
	10.3.9			Amendment No. 2, dated as of July 27, 1990, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.10			Amendment No. 3, dated as of November 24, 1992, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.11			Amended and Restated Power Purchase and Sales Agreement, dated December 2, 1986, between Mammoth Pacific and Southern California Edison Company*
	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*
	10.3.13			Power Purchase Contract, dated April 15, 1985, between Mammoth Pacific and Southern California Edison Company*
	10.3.14			Amendment No. 1, dated as of October 27, 1989, between Mammoth Pacific and Southern California Edison Company*
	10.3.15			Amendment No. 2, dated as of December 20, 1989, between Mammoth Pacific and Southern California Edison Company*
	10.3.16			Power Purchase Contract, dated April 16, 1985, between Southern California Edison Company and Santa Fe Geothermal, Inc.*
	10.3.17			Amendment No. 1, to Power Purchase Contract, dated October 25, 1985, between Southern California Edison Company and Mammoth Pacific*
	10.3.18			Amendment No. 2, to Power Purchase Contract, dated December 20, 1989, between Southern California Edison Company and Pacific Lighting Energy Systems*
	10.3.19			Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Mammoth Pacific*
	10.3.20			Interconnection Facilities Agreement, dated October 13, 1985, by and between Southern California Edison Company and Mammoth Pacific (II)*
	10.3.21			Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Pacific Lighting Energy Systems*
	10.3.22			Interconnection Agreement, dated August 12, 1985, by and between Southern California Edison Company and Heber Geothermal Company*
	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*
	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*
	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*
	10.3.26			Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal*
	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*
	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*

II-4

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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 PartnershipPartnership*
	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 PartnershipPartnership*
	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*
	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*
	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*
	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*
	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*
	10.3.36			Leyte Optimization Project BOT Agreement, dated August 4, 1995, by and between PNOC-Energy Development Corporation and Ormat Inc.*
	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.*
	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.*
	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*
	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*
	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*‡‡‡
	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*‡‡‡
	10.3.43			Energy Services Agreement, dated February 2003, by and between Imperial Irrigation District and ORMESA, LLC*
	10.3.44			Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company*

II-5

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Exhibit No.				Document
	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*
	10.3.46			Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puna Geothermal Venture*
	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*
	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*
	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*
	10.4			Leases
	10.4.1			Ormesa BLM Geothermal Resources Lease CA 966‡*
	10.4.2			Ormesa BLM License for Electric Power Plant Site CA 24678‡‡*
	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*
	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†*
	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†*
	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†*
	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*
	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*
	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*
	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*
	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*
	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*
	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†*

II-6

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Exhibit No.				Document
	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*
	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*
	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*
	10.4.17			Lease Agreement, dated April 7, 1972, by and between Nowlin Partnership, as Lessor, and Standard Oil Company of California, as Lessee*
	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*
	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†*
	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†*
	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†*
	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*
	10.4.23			Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee†*
	10.4.24			Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee†*
	10.4.25			Unprotected Lease Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	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†*
	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†*
	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*
	10.4.29			Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee†*
	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†*

II-7

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Exhibit No.				Document
	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†*
	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*
	10.5			General
	10.5.1			Engineering, Procurement and Construction Contract, dated August 23, 2002, by and between Tuaropaki Power Company Limited and Ormat Pacific Inc.*
	10.5.2			Amendment No. 1, to Engineering, Procurement and Construction Contract, dated, 2003, by and between Tuaropaki Power Company Limited and Ormat Pacific Inc.*
	10.5.3			Engineering, Procurement and Construction Contract, dated 2003, by and between Contact Energy Limited and Ormat Pacific Inc.*
	10.5.4			Patent License Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.5.5			Form of Registration Rights Agreement by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.6.1			Ormat Technologies, Inc. 2004 Incentive Compensation PlanPlan*
	10.6.2			Form of Incentive Stock Option AgreementAgreement*
	10.6.3			Form of Nonqualified Stock Option AgreementAgreement*
	10.7			Form of Executive Employment Agreement of Lucien Bronicki*
	10.8			Form of Executive Employment Agreement of Yehudit Bronicki*
	10.9			Form of Executive Employment Agreement of Yoram Bronicki*
	10.10.1			Form of Executive Employment Agreement of Hezy RamRam*
	10.10.2			Amendment No. 1 to Form of Executive Employment Agreement of Hezy RamRam*
	10.11			Form of Indemnification AgreementAgreement*
	21.1			Subsidiaries of the registrantregistrant*
	23.1			Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm
	23.2			Consent of Chadbourne & Parke LLP (contained in Exhibit 5.1)
	23.3			Consent of Dan Falk*
	23.4			Consent of Edward R. Muller*
	23.5			Consent of Jacob J. Worenklein*
	23.6			Consent of Yoram BronickiBronicki*
	24.1			Power of attorney (Included on signature page of the registration statement)
	99.1			Material terms with respect to BLM geothermal resources leases*
	99.2			Material terms with respect to BLM site leases*
	99.3			Material terms with respect to agreements addressing renewable energy pricing and payment issues*

	*Previously filed.

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted portions have been separately filed with the Securities and Exchange Commission.

II-8

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‡	We have entered into other BLM geothermal resources leases that are substantially similar in terms with this exhibit. Any deviation in terms with this exhibit have been described in Exhibit 99.1.

‡‡	We have entered into other BLM site leases that are substantially similar in terms with this exhibit. Any deviation in terms with this exhibit have been described in Exhibit 99.2.

‡‡‡	We have entered into other agreements addressing renewable energy pricing and payment issues with Southern California Edison Company that are substantially similar in terms with these exhibits. Any deviation in terms with these exhibits have been described in Exhibit 99.3.

Item 17.    Undertakings

(a)	The undersigned Registrant hereby undertakes to provide to the underwriters at the closing certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

(b)

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers, and controlling persons of the Registrant pursuant to the provisions described in "Item 14—Indemnification of Directors and Officers" above, or otherwise, the Registrant has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification by the Registrant against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(c)	The undersigned Registrant hereby undertakes that:

	(1)	For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

	(2)	For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-9

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Amendment No. 23 to the registration statement (No. 333-117527) to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of New York, on October 22,November 5, 2004.

ORMAT TECHNOLOGIES, INC.

By:  /s/ Yehudit Bronicki                    

Name: Yehudit Bronicki Title: President

Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 23 to the registration statement (No. 333-117527) has been signed by the following persons in the capacities on October 22,November 5, 2004

Signature		Title
*		Chairman of the Board and Director
Lucien Bronicki
/s/ Yehudit Bronicki		Director, Chief Executive Officer and President (Principal Executive Officer)
Yehudit Bronicki
*		Director (Principal Financial Officer, Controller and Principal Accounting Officer)
Connie Stechman

*By:   /s/ Yehudit Bronicki                

Yehudit Bronicki

Attorney-In-Fact

II-10

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EXHIBIT INDEX

Exhibit No.				Document
	1.1			Form of Underwriting Agreement*
	3.1			Second Amended and Restated Certificate of IncorporationIncorporation*
	3.2			Second Amended and Restated By-lawsBy-laws*
	4.1			Form of Common Share Stock Certificate*Certificate
	4.2			Form of Preferred Share Stock Certificate*
	4.3			Form of Rights Agreement by and between Ormat Technologies, Inc. and American Stock Transfer & Trust CompanyCompany*
	5.1			Opinion of Chadbourne & Parke LLP, related to the shares of common stock being sold in the initial public offering
	8.1			Opinion of Chadbourne & Parke LLP, related to tax mattersmatters*
	10.1			Financing Agreements
	10.1.1			Foreign Currency Loan Agreement, dated June 1, 2004, between Ormat Technologies, Inc. and United Mizrahi Bank LTD.*
	10.1.2			Amended and Restated Bridge Loan Agreement, dated October 2, 2003, by and between Ormat Nevada, Inc. and Bank Leumi USA*
	10.1.3			Credit Facility Agreement, dated September 5, 2000, between Ormat Momotombo Power Company and Bank Hapoalim B.M.*
	10.1.4			Credit Agreement, dated as of December 31, 2002, among ORMESA LLC, United Capital, a division of Hudson United Bank and the Lenders party to such agreement from time to time*
	10.1.5			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*
	10.1.6			Credit Agreement, dated May 13, 1996, between Ormat-Leyte and Export-Import Bank of the United States*
	10.1.7			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*
	10.1.8			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*
	10.1.9			Loan Agreement, dated October 1, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.10			Amendment No. 1 to Loan Agreement, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.11			Capital Note, dated December 22, 2003, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.12			Amendment to Capital Note, dated September 20, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.13			Guarantee Fee Agreement, dated January 1, 1999, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.14			Reimbursement Agreement, dated July 15, 2004, by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.1.15			Services Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.1.16			Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United BankBank*

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Exhibit No.				Document
	10.1.17			First Amendment to Letter of Credit and Loan Agreement, dated June 30, 2004, by and between Ormat Nevada, Inc., and Hudson United BankBank*
	10.1.18			Subordination Agreement, dated June 30, 2004, by and between Ormat Technologies, Inc. and Hudson United BankBank*
	10.2			Purchase Agreements
	10.2.1			Purchase and Sale Agreement, dated April 22, 2004, by and among Constellation Power, Inc. and Cosi Puna, Inc. and ORNI 8 LLC and Ormat Nevada, Inc.*
	10.2.2			Purchase Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.3			Power Purchase Agreements
	10.3.1			Power Purchase Contract, dated July 18, 1984, between Southern California Edison Company and Republic Geothermal, Inc.*
	10.3.2			Amendment No. 1, to the Power Purchase Contract, dated December 23, 1988, between Southern California Edison Company and Ormesa Geothermal*
	10.3.3			Power Purchase Contract, dated June 13, 1984, between Southern California Edison Company and Ormat Systems, Inc.*
	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*
	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*
	10.3.6			Settlement Agreement and Amendment No. 2, to Power Purchase Contract, dated August 7, 1995, between HGC and Southern California Edison Company*
	10.3.7			Power Purchase Contract dated, April 16, 1985, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.8			Amendment No. 1, dated as of October 23, 1987, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.9			Amendment No. 2, dated as of July 27, 1990, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.10			Amendment No. 3, dated as of November 24, 1992, between Southern California Edison Company and Second Imperial Geothermal Company*
	10.3.11			Amended and Restated Power Purchase and Sales Agreement, dated December 2, 1986, between Mammoth Pacific and Southern California Edison Company*
	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*
	10.3.13			Power Purchase Contract, dated April 15, 1985, between Mammoth Pacific and Southern California Edison Company*
	10.3.14			Amendment No. 1, dated as of October 27, 1989, between Mammoth Pacific and Southern California Edison Company*
	10.3.15			Amendment No. 2, dated as of December 20, 1989, between Mammoth Pacific and Southern California Edison Company*
	10.3.16			Power Purchase Contract, dated April 16, 1985, between Southern California Edison Company and Santa Fe Geothermal, Inc.*
	10.3.17			Amendment No. 1, to Power Purchase Contract, dated October 25, 1985, between Southern California Edison Company and Mammoth Pacific*
	10.3.18			Amendment No. 2, to Power Purchase Contract, dated December 20, 1989, between Southern California Edison Company and Pacific Lighting Energy Systems*
	10.3.19			Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Mammoth Pacific*

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Exhibit No.				Document
	10.3.20			Interconnection Facilities Agreement, dated October 13, 1985, by and between Southern California Edison Company and Mammoth Pacific (II)*
	10.3.21			Interconnection Facilities Agreement, dated October 20, 1989, by and between Southern California Edison Company and Pacific Lighting Energy Systems*
	10.3.22			Interconnection Agreement, dated August 12, 1985, by and between Southern California Edison Company and Heber Geothermal Company*
	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*
	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*
	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*
	10.3.26			Plant Connection Agreement for the Ormesa Geothermal Plant, dated October 1, 1985, by and between Imperial Irrigation District and Ormesa Geothermal*
	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*
	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*
	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 PartnershipPartnership*
	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 PartnershipPartnership*
	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*
	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*
	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*
	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*
	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*
	10.3.36			Leyte Optimization Project BOT Agreement, dated August 4, 1995, by and between PNOC-Energy Development Corporation and Ormat Inc.*
	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.*
	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.*

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Exhibit No.				Document
	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*
	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*
	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*‡‡‡
	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*‡‡‡
	10.3.43			Energy Services Agreement, dated February 2003, by and between Imperial Irrigation District and ORMESA, LLC*
	10.3.44			Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company*
	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*
	10.3.46			Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puna Geothermal Venture*
	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*
	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*
	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*
	10.4			Leases
	10.4.1			Ormesa BLM Geothermal Resources Lease CA 966‡*
	10.4.2			Ormesa BLM License for Electric Power Plant Site CA 24678‡‡*
	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*
	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†*
	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†*
	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†*
	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*
	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*
	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*

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Exhibit No.				Document
	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*
	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*
	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*
	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†*
	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*
	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*
	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*
	10.4.17			Lease Agreement, dated April 7, 1972, by and between Nowlin Partnership, as Lessor, and Standard Oil Company of California, as Lessee*
	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*
	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†*
	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†*
	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†*
	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*
	10.4.23			Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee†*
	10.4.24			Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee†*
	10.4.25			Unprotected Lease Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	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†*
	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†*

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Exhibit No.				Document
	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*
	10.4.29			Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee†*
	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†*
	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†*
	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*
	10.5			General
	10.5.1			Engineering, Procurement and Construction Contract, dated August 23, 2002, by and between Tuaropaki Power Company Limited and Ormat Pacific Inc.*
	10.5.2			Amendment No. 1, to Engineering, Procurement and Construction Contract, dated, 2003, by and between Tuaropaki Power Company Limited and Ormat Pacific Inc.*
	10.5.3			Engineering, Procurement and Construction Contract, dated 2003, by and between Contact Energy Limited and Ormat Pacific Inc.*
	10.5.4			Patent License Agreement, dated July 15, 2004, by and between Ormat Industries Ltd. and Ormat Systems Ltd.*
	10.5.5			Form of Registration Rights Agreement by and between Ormat Technologies, Inc. and Ormat Industries Ltd.*
	10.6.1			Ormat Technologies, Inc. 2004 Incentive Compensation PlanPlan*
	10.6.2			Form of Incentive Stock Option AgreementAgreement*
	10.6.3			Form of Nonqualified Stock Option AgreementAgreement*
	10.7			Form of Executive Employment Agreement of Lucien Bronicki*
	10.8			Form of Executive Employment Agreement of Yehudit Bronicki*
	10.9			Form of Executive Employment Agreement of Yoram Bronicki*
	10.10.1			Form of Executive Employment Agreement of Hezy RamRam*
	10.10.2			Amendment No. 1 to Form of Executive Employment Agreement of Hezy RamRam*
	10.11			Form of Indemnification AgreementAgreement*
	21.1			Subsidiaries of the registrantregistrant*
	23.1			Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm
	23.2			Consent of Chadbourne & Parke LLP (contained in Exhibit 5.1)
	23.3			Consent of Dan Falk*
	23.4			Consent of Edward R. Muller*
	23.5			Consent of Jacob J. Worenklein*
	23.6			Consent of Yoram BronickiBronicki*
	24.1			Power of attorney (Included on signature page of the registration statement)
	99.1			Material terms with respect to BLM geothermal resources leases*
	99.2			Material terms with respect to BLM site leases*
	99.3			Material terms with respect to agreements addressing renewable energy pricing and payment issues*

*	Previously filed.

†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted portions have been separately filed with the Securities and Exchange Commission.

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‡	We have entered into other BLM geothermal resources leases that are substantially similar in terms with this exhibit. Any deviation in terms with this exhibit have been described in Exhibit 99.1.

‡‡	We have entered into other BLM site leases that are substantially similar in terms with this exhibit. Any deviation in terms with this exhibit have been described in Exhibit 99.2.

‡‡‡	We have entered into other agreements addressing renewable energy pricing and payment issues with Southern California Edison Company that are substantially similar in terms with these exhibits. Any deviation in terms with these exhibits have been described in Exhibit 99.3.

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