SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
|TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
Commission file number: 001-32347
ORMAT TECHNOLOGIES, INC.
(Exact name of registrant as specified in its charter)
6225 Neil Road, Suite 300, Reno, Nevada 89511-1136
(Address of principal executive offices)
Registrant’s telephone number, including area code: (775) 356-9029
Securities Registered Pursuant to Section 12(b) of the Act:
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act.
Large accelerated filer Accelerated filer Non-accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
As of June 30, 2006, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $426,858,875 based on the closing price as reported on the New York Stock Exchange.
The number of outstanding shares of common stock of Ormat Technologies, Inc., as of February 28, 2007, was 38,111,108 par value $0.001 per share.
Documents Incorporated by Reference: Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Registrant’s Proxy Statement for its Annual Meeting of Stockholders, which will be filed not later than 120 days after December 31, 2006.
ORMAT TECHNOLOGIES, INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2006
TABLE OF CONTENTS [to update page #]
Cautionary Note Regarding Forward-Looking Statements
This annual report includes ‘‘forward-looking statements’’ within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future, including such matters as our projections of annual revenues, expenses and debt service coverage with respect to our debt securities, future capital expenditures, business strategy, competitive strengths, goals, development or operation of generation assets, market and industry developments and the growth of our business and operations, are forward-looking statements. When used in this annual report, the words ‘‘may’’, ‘‘will’’, ‘‘could’’, ‘‘should’’, ‘‘expects’’, ‘‘plans’’, ‘‘anticipates’’, ‘‘believes’’, ‘‘estimates’’, ‘‘predicts’’, ‘‘projects’’, ‘‘potential’’, or ‘‘contemplate’’ or the negative of these terms or other comparable terminology are intended to identify forward-looking statements, although not all forward-looking statements contain such words or expressions. The forward-looking statements in this report are primarily located in the material set forth under the headings ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ contained in Part II, Item 7, ‘‘Risk Factors’’ contained in Part I, Item IA, and ‘‘Notes to Financial Statements’’ contained in Part II, Item 8 of this annual report, but are found in other locations as well. These forward-looking statements generally relate to our plans, objectives and expectations for future operations and are based upon management’s current estimates and projections of future results or trends. Although we believe that our plans and objectives reflected in or suggested by these forward-looking statements are reasonable, we may not achieve these plans or objectives. You should read this annual report completely and with the understanding that actual future results and developments may be materially different from what we expect due to a number of risks and uncertainties, many of which are beyond our control. We will not update forward-looking statements even though our situation may change in the future.
Specific factors that might cause actual results to differ from our expectations include, but are not limited to:
|•||significant considerations and risks discussed in this annual report;|
|•||operating risks, including equipment failures and the amounts and timing of revenues and expenses;|
|•||geothermal resource risk (such as the heat content of the reservoir, useful life and geological formation);|
|•||environmental constraints on operations and environmental liabilities arising out of past or present operations, including the risk that we may not have, and in the future may be unable to procure, any necessary permits or other environmental authorization;|
|•||construction or other project delays or cancellations;|
|•||financial market conditions and the results of financing efforts;|
|•||political, legal, regulatory, governmental, administrative and economic conditions and developments in the United States and other countries in which we operate;|
|•||the enforceability of the long-term power purchase agreements for our projects;|
|•||contract counterparty risk;|
|•||weather and other natural phenomena;|
|•||the impact of recent and future federal, state and local regulatory proceedings and changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry and incentives for the production of renewable energy in the United States and elsewhere, changes in environmental and other laws and regulations to which our company is subject, as well as changes in the application of existing laws and regulations;|
|•||current and future litigation;|
|•||our ability to successfully identify, integrate and complete acquisitions;|
|•||competition from other similar geothermal energy projects, including any such new geothermal energy projects developed in the future, and from alternative electricity producing technologies;|
|•||the effect of and changes in economic conditions in the areas in which we operate;|
|•||market or business conditions and fluctuations in demand for energy or capacity in the markets in which we operate;|
|•||the direct or indirect impact on our company’s business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance; and,|
|•||the effect of and changes in current and future land use and zoning regulations, residential, commercial and industrial development and urbanization in the areas in which we operate.|
ITEM 1. BUSINESS
Unless the context otherwise requires, all references in this annual report to ‘‘Ormat’’, ‘‘the Company’’, ‘‘we’’, ‘‘us’’, ‘‘our company’’, ‘‘Ormat Technologies’’ or ‘‘our’’ refer to Ormat Technologies, Inc. and its consolidated subsidiaries. The ‘‘OFC Senior Secured Notes’’ refers to the 8¼% Senior Secured Notes due 2020 that were issued in February 2004 by our subsidiary, Ormat Funding Corp. The ‘‘OrCal Senior Secured Notes’’ refers to the 6.21% Senior Secured Notes due 2020 that were issued in December 2005 by our subsidiary, OrCal Geothermal Inc.
We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in each case using equipment that we design and manufacture. We conduct our business activities in two business segments. In our Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In our Products Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants.
Most of the projects that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Therefore, electricity produced from geothermal energy sources contributes significantly less to local and regional incidences of acid rain and global warming than energy produced by burning fossil fuels. Geothermal energy is also an attractive alternative to other sources of energy as part of a national diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.
In addition to our geothermal energy business, we have developed and continue to develop products that produce electricity from recovered energy or so-called ‘‘waste heat.’’ We also own and are constructing new recovered energy projects to be owned and operated by us. Recovered energy or waste heat represents residual heat that is generated as a by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Such residual heat, that would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without emissions.
Company Contact and Sources of Information
We file annual, quarterly and periodic reports, proxy statements and other information with the Securities and Exchange Commission, which we refer to as the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the Internet at that website.
On May 31, 2006, we submitted to the New York Stock Exchange (NYSE) an Annual Written Affirmation, in the prescribed form and with no qualifications, regarding our compliance with the
NYSE’s Corporate Governance listing standards. In addition, our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports are available at our website www.ormat.com for downloading, free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above. The content of our website, however, is not part of this annual report.
You may request a copy of our SEC filings, as well as the foregoing corporate documents, at no cost to you, by writing to the Company address appearing in this annual report or by calling us at (775) 356-9029.
Our Power Generation Business
We own or control, and operate geothermal and recovered energy projects in the United States. We also own or control, and operate geothermal projects in Guatemala, Kenya, Nicaragua, and the Philippines. We continue to pursue opportunities to acquire and develop similar projects throughout the world. Most of our projects are located in regions where there is, or is expected to be, demand for additional generating capacity. We increased our net ownership interest in generating capacity by 51 megawatts (MW) between December 31, 2005 and December 31, 2006, resulting from the following: An increase of 19 MW, attributable to the acquisition of an additional 79.0% ownership interest in the Zunil project in Guatemala; an increase of 22 MW, attributable to the construction of the OREG 1 recovered energy project; an increase of 6 MW, attributable to the Gould geothermal power plant; and an increase of 5 MW, attributable to increased generating capacity of our existing geothermal power plants resulting from improvements to the geothermal well fields of some of our existing projects. We experienced a 1 MW reduction in generating capacity at our Brady project as a result of cooling. During the fourth quarter of 2006, we completed the construction of the Desert Peak 2 project in Nevada, which added 12 MW to our generating capacity. We have not yet declared this project commercially operational, which would trigger our obligation to provide the contracted generating capacity under the power purchase agreement.
In the year ended December 31, 2006, revenues from our electricity segment were $195.5 million, constituting approximately 72.7% of our total revenues in 2006. Revenues from the sale of electricity by our domestic projects were $162.8 million, constituting approximately 83.3% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign projects were $32.6 million, constituting approximately 16.7% of our total revenues from the sale of electricity.
The table below summarizes key information relating to our projects that are in operation as of December 31, 2006:
Projects in Operation
|(1)||We own and operate all of our projects, except the Momotombo project in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government, and the Mammoth and Leyte projects, in which we have a 50% and 80% ownership interest, respectively.|
|(2)||References to generating capacity refers to the gross capacity less auxiliary power, in the case of all of our existing domestic projects and the Momotombo and Olkaria III projects (two of our foreign projects), and to the generating capacity that is subject to the ‘‘take or pay’’ power purchase agreements in the case of the Leyte and Zunil projects (another two of our foreign projects). We determine the generating capacity figures in any given year from available historical operational data of our operating projects taking into account resource capabilities. This column represents the generating capacity of the project, not our net ownership in such generating capacity.|
|In any given year, the actual power generation of a particular project may differ from that project’s generating capacity due to operational issues affecting performance during that year. In 2006, the total actual power generation of the projects we operate in the U.S. was 1,998,660 MWh lower than the energy potential commensurate with our generating capacity due to operational factors discussed elsewhere in this annual report.|
|(3)||The Heber Complex includes the Heber 1 and 2 projects and the Gould project.|
|(4)||The Steamboat Complex includes the Steamboat 1 and 1A projects, the Steamboat 2 and 3 projects, the Burdette project and the Steamboat Hills project. The Galena 2 project, which is currently in final completion tests, will be added to the Steamboat Complex.|
|(5)||The initial term of the power purchase agreement expired on December 31, 2006, but is being renewed automatically on an annual basis.|
|(6)||We have completed construction in the fourth quarter of 2006, but have not yet declared commercial operation under the power purchase agreement.|
|(7)||The Leyte project will be transferred to the power purchasing utility in September 2007 for no consideration. This will reduce our foreign generation capacity by 49 MW.|
|(8)||The power purchase agreement for the Olkaria III project will expire in 2020 or, if Phase II of the project is constructed and completed, 20 years from the completion of such Phase II. Phase II of this project involves the construction of additional facilities that we expect would add approximately 35 MW of generating capacity to this project. See ‘‘Description of our Projects’’ below.|
The tables below summarize key information relating to the projects that are currently under construction and under development:
Projects under Construction
|(1)||The new construction in the Steamboat Complex includes the 4 MW Steamboat Hills project and the 10 MW Galena 2 project.|
|(2)||We have entered into an interim agreement with Southern California Edison Company and are currently negotiating a long-term power purchase agreement. See ‘‘Description of our Projects’’ below.|
|(3)||We have completed construction in the fourth quarter of 2006, but have not yet declared commercial operation.|
|(4)||The power purchase agreement for the Olkaria III Phase II project will expire 20 years from the completion of Phase II.|
Projects under Development
Almost all of the revenues that we currently derive from the sale of electricity are pursuant to long-term power purchase agreements. Approximately 74.4% of our total revenues in the year ended December 31, 2006 from the sale of electricity by our domestic projects were derived from power purchasers that currently have investment grade credit rating. The purchasers of electricity from our foreign projects are either state-owned entities or private entities. We have obtained political risk insurance from the Multilateral Investment Guarantee Agency of the World Bank Group (MIGA) or from Zurich Re, a private sector political risk insurer, for all of our foreign projects (other than the Leyte project) in order to cover a portion of any loss that we may suffer upon the occurrence of certain political events covered by such insurance.
Development, Construction and Acquisition. We have experienced significant growth in recent years, principally through the acquisition of geothermal power plants from third parties and the expansion and enhancement of our existing projects, including the following: (i) during 2006 we completed the acquisition of an additional 79.0% ownership interest in the Zunil project in Guatemala which increased our ownership capacity by 19 MW, (ii) during the third quarter of 2006 we completed the construction of the Gould project, which added 6 MW to the Heber complex; (iii) in October 2006, we completed the construction of the first owned recovered energy power plant, OREG 1, which added 22 MW to our generating capacity; and (iv) during the third quarter of 2006 we completed the enhancement program at the Mammoth and Momotombo projects, which added 5 MW to our generating capacity. We currently expect to continue growing our power generation business through:
|•||the development and construction of new geothermal and recovered energy-based power plants;|
|•||the expansion and enhancement of our existing projects;|
|•||the acquisition of additional geothermal and other renewable assets from third parties; and|
|•||the entry into geothermal leases for future development.|
As part of these efforts, we regularly monitor requests for proposals from, and submit bids to, investor-owned and other electric utilities in the United States to provide additional generating capacity, primarily in the western United States where geothermal resources are generally concentrated. During the third quarter of 2006, we responded to several requests for proposals issued by different utilities interested in purchasing renewable energy and we have been informed that some of our proposals, covering approximately 150 MW of proposed capacity in Nevada, California and Idaho, have been short-listed for further evaluation. There can be no assurance, however, that we will be chosen from the short list or that we will succeed in negotiating power purchase agreements with the various utilities. We also respond to international tenders issued by foreign state-owned electric
utilities for the development, construction and operation of new geothermal power plants. In addition, we apply our technological expertise to upgrade the facilities of our existing geothermal power plants and to continuously monitor and manage our existing geothermal resources in order to increase the efficiency and generating capacity of such facilities.
We are currently in varying stages of development of new projects and construction of new and existing projects. Based on our current development and construction schedule, which is subject to change at any time and which may not be met in its entirety, we expect to declare commercial operation of the 12 MW Desert Peak 2 project during the first half of 2007 and we expect to add between 227 to 251 MW in generating capacity from geothermal and recovered energy power plants in the United States by the end of 2009. Outside of the U.S., we expect to declare commercial operation of the 20 MW Amatitlan project in Guatemala, during the first half of 2007, and to complete the construction of the 35 MW project in Kenya by the end of 2008.
We are a member in a consortium, which is in the process of developing a geothermal power project in Indonesia of approximately 300 MW that is expected to come on line in phases between 2010 and 2012. The consortium is currently negotiating a power purchase agreement with a local utility. We estimate that our minority interest equivalent will range between 45 MW to 60 MW.
Our Products Business
We design, manufacture and sell products for electricity generation and provide the related services described below. Generally, we manufacture products only against customer orders and do not manufacture products for our own inventory.
Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or ‘‘OEC’’s. Our customers include contractors and geothermal plant owners and operators. We recently sold one of our air-cooled OEC units to Tauropaki Power Company of New Zealand
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 recently signed a supply contract with ENAGAS S.A. of Madrid, Spain, for the supply of one OEC for a new Recovered Energy Generation (REG) power plant.
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. We have supplied remote power units to be installed on the Sakhalin pipeline in Russia.
Engineering, Procurement and Construction (EPC) of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. Recent examples of our construction activities include the design and construction of the Alliance REG plants in Canada and the Ngawha geothermal power plant in New Zealand.
In the year ended December 31, 2006, our revenues from our products business were $73.5 million, constituting approximately 27.3% of our total revenues.
We were formed by Ormat Industries Ltd. (also referred to in this annual report as the ‘‘Parent,’’ ‘‘Ormat Industries,’’ ‘‘the parent company’’ or ‘‘our parent’’) in 1994 in the State of Delaware for the purpose of investing and holding ownership interests in power projects, as well as constructing and operating power plants owned by us and by third parties. Ormat Industries, which is based in Israel, is an international power systems company whose predecessor, Ormat Turbines Ltd., was founded in 1965 by Lucien and Dita Bronicki for the principal purpose of developing equipment for the production of a clean, renewable and generally sustainable form of energy. Ormat Industries sold to us its business relating to the manufacturing and sale of energy-related equipment and services. Following this sale, we now hold all of Ormat Industries’ power generation products business. Ormat Industries owns 64% of our outstanding common stock.
Most of our projects in operation produce electricity from geothermal energy. Geothermal energy is a clean, renewable and generally sustainable energy source that, because it does not utilize combustion in the production of electricity, releases significantly lower levels of emissions, principally steam, than those that result from energy generation based on the burning of fossil fuels. Geothermal energy is derived from the natural heat of the earth when water comes sufficiently close to hot molten rock to heat the water to temperatures of 300 degrees Fahrenheit or more. The heated water then ascends toward the surface of the earth where, if geological conditions are suitable for its commercial extraction, it can be extracted by drilling geothermal wells. The energy necessary to operate a geothermal power plant is typically obtained from several such wells which are drilled using established technology that is in some respects similar to that employed in the oil and gas industry. Geothermal production wells are normally located within approximately one to two miles of the power plant as geothermal fluids cannot be transported economically over longer distances due to heat and pressure loss. The geothermal reservoir is a renewable source of energy if natural ground water sources and reinjection of extracted geothermal fluids are adequate over the long-term to replenish the geothermal reservoir following the withdrawal of geothermal fluids and if the well field is properly operated. Geothermal energy projects typically have higher capital costs (primarily as a result of the costs attributable to well field development) but tend to have significantly lower variable operating costs, principally consisting of maintenance expenditures, than fossil fuel-fired power plants that require ongoing fuel expenses.
Geothermal Power Plant Technologies
Geothermal power plants generally employ either binary systems or conventional flash systems. In our projects, we also employ our proprietary technology of combined geothermal cycle systems. See ‘‘Our Technology’’.
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 saturated steam, which drives a turbine generator to produce electricity. In some cases, the brine at the outlet of the separator is flashed a second time (dual flash), providing additional steam at lower pressure used in the low pressure section of the steam turbine to produce additional electricity. Steam exhausted from the steam turbine is condensed in a surface or direct contact condenser cooled by cold water from a cooling tower. The non-condensable gases (such as carbon dioxide) are removed through the removal system in order to optimize the performance of the steam turbines. The condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected back into the geothermal resource through a series of injection wells. The flash technology is depicted in the graphic below.
In some instances, the wells directly produce dry steam (the flashing occurring under ground). In such cases, the steam is fed directly to the steam turbine and the rest of the system is similar to the flash power plant described above.
The geothermal energy industry in the United States experienced significant growth in the 1970s and 1980s, followed by a period of consolidation of owners and operators of geothermal assets in the 1990s. The industry, once dominated by large oil companies and investor-owned electric utilities, now includes several independent power producers. During the 1990s, growth and development in the geothermal energy industry occurred primarily in foreign markets, and only minimal growth and development occurred in the United States. Since 2001, there has been renewed interest in geothermal energy in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation, due to the increasing cost of natural gas, and as legislative and regulatory incentives, such as state renewable portfolio standards, have become more prevalent.
Although electricity generation from geothermal resources is currently concentrated in California, Nevada, Hawaii and Utah, there are opportunities for development in other states such as Alaska, Arizona, Idaho, New Mexico and Oregon due to the availability of geothermal resources and, in some cases, a favorable regulatory environment in such states.
A 2006 forecast of the Western Governors Association (WGA) projects the addition of geothermal installations with generating capacity of approximately 13,000 MW by 2025, out of which 5,600 MW is expected to be added by 2015. This forecast is based on existing, known geothermal resources and does not take into account any positive effects on generating capacity resulting from new technology, such as enhanced utilization of existing geothermal bases and engineered geothermal systems (according to the WGA, Geothermal Taskforce Report from January 2006).
In January 2007, the Massachusetts Institute of Technology published a study that projects a potential of 100,000 MW of generating capacity from geothermal power plants if the development of enhanced geothermal systems is successful.
An additional factor fueling recent growth in the renewable energy industry is global concern about the environment. Power plants that use fossil fuels generate higher levels of air pollution and their emissions have been linked to acid rain and global warming. In response to an increasing demand for ‘‘green’’ energy, many countries have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the United States, Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, Minnesota, Montana, Nevada, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island, Texas, Vermont, Washington, Wisconsin and the District of Colombia have all adopted renewable portfolio standards, renewable portfolio goals, or other similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources. Of these twenty-three states, fifteen states and the District of Columbia (including California, Nevada and Hawaii, where we have been the most active in our geothermal energy development and in which all of our U.S. geothermal projects are located) define geothermal resources as ‘‘renewables’’. A bill establishing renewable portfolio standards is currently before the Kansas legislature.
We believe that these legislative measures and initiatives present a significant market opportunity for us. For example, California generally requires that each investor-owned electric utility company operating within the state increase the amount of renewable generation in its resource mix by 2% per year so that 20% of its retail sales are procured from eligible renewable energy sources by 2010, ahead of the previous statutory mandated target of December 2017. Presently, approximately 11% of the electricity generated in California is derived from renewable resources (not counting hydroelectricity as renewable power). Nevada’s renewable portfolio standard requires each Nevada electric utility to obtain 9% of its annual energy requirements from renewable energy sources in 2007-2008, which requirement thereafter increases by 3% every two years until 2015, when 20% of such annual energy requirements must be provided from renewable energy sources or energy efficiency projects. At least three-quarters of the annual total requirements must come only from renewable energy projects.
Hawaii’s renewable portfolio standard requires each Hawaiian electric utility to obtain 8% of its net electricity sales from renewable energy sources by December 31, 2005, 10% by December 31, 2010 and 20% by December 31, 2020.
In addition, a new Act was signed into law in California to reduce carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies. One such strategy may involve the use of market-based trading of emissions rights that will allow some greenhouse gas sources to over-control their emissions and sell the rights to their surplus reductions to other sources for whom the cost of reducing emissions would be significantly more costly. Although programs under the Act will take some time to develop, its requirements, particularly the creation of a market-based trading mechanism to achieve compliance with emissions caps, should be highly advantageous to in-state energy generating sources that have low carbon emissions such as geothermal energy.
The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit,’’ which in 2006 was 1.9 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. The owner of the project must choose between the production tax credit and the 10% investment tax credit described above. In either case, under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. Whether we claim the production tax credit or the investment credit, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a production tax credit, there is no reduction in the tax basis for depreciation.
Collectively, these tax benefits (to the extent fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new project.
The Kyoto Protocol entered into force on February 16, 2005, making the Protocol’s emission targets for the 2008 to 2012 period legally binding on the more than 30 developed countries, including the EU members, Russia, Japan, Canada, New Zealand, Norway and Switzerland, all of which have ratified the Protocol. We expect that the effect of the Kyoto Protocol will be to encourage renewable energy installation outside of the United States, as the United States has not ratified the Kyoto Protocol.
Outside of the United States, the majority of power generating capacity has historically been owned and controlled by governments. During the past decade, however, many foreign governments have privatized their power generation industries through sales to third parties and have encouraged new capacity development and/or refurbishment of existing assets by independent power developers. These foreign governments have taken a variety of approaches to encourage the development of competitive power markets, including awarding long-term contracts for energy and capacity to independent power generators and creating competitive wholesale markets for selling and trading energy, capacity and related products. Some countries have also adopted active governmental programs designed to encourage clean renewable energy power generation. For example, China, where we are currently trying to develop a project, has recently enacted a Renewable Energy Law (effective January 1, 2006) defining fiscal incentives, priority dispatching, preferential pricing and other supporting mechanisms, and has announced long-term targets for renewable energy capacity growth, including mandatory renewable portfolio standards for large generation utilities. Several Latin American countries have rural electrification programs and renewable energy programs. For example, Guatemala, where our Zunil and Amatitlan projects are located, approved in November 2003 a law
which creates incentives for power generation from renewable energy sources by, among other things, providing economic and fiscal incentives such as exemptions from taxes on the importation of relevant equipment and various tax exemptions for companies implementing renewable energy projects. We believe that these developments and governmental plans will create opportunities for us to acquire and develop geothermal power generation facilities internationally as well as create additional opportunities for us to sell our remote power units and other products.
In addition to our geothermal power generation activities, we have also identified recovered energy-based power generation as a significant market opportunity for us in North America and the rest of the world. We are initially targeting the North American market, where we expect that recovered energy-based power generation will be derived principally from compressor stations along interstate pipelines, from midstream gas processing facilities, and from processing industries in general. Several states, as well as the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Nevada, Connecticut, New Mexico and Hawaii allow electric utilities to include recovered energy-based power generation in calculating their compliance with renewable portfolio standards. In addition, North Dakota, South Dakota and the U.S. Department of Agriculture (through the Rural Utilities Service) have approved recovered energy-based power generation units as renewable energy resources, which qualifies recovered energy-based power generators (whether in those two states or elsewhere in the United States) for federally funded, low interest loans. We believe that the European market has similar potential and we expect to leverage our early success in North America in order to expand into Europe and other markets worldwide. In North America alone, we estimate the potential total market for recovered energy-based generation to be approximately 1,000 MW.
Competitive Assets. Our assets are competitive for the following reasons:
|•||Contracted Generation. All of the electricity generated by our geothermal power plants is currently sold pursuant to long-term power purchase agreements, providing generally predictable cash flows.|
|•||Baseload Generation. All of our geothermal power plants supply a part of the baseload capacity of the electric system in their respective markets, meaning that they operate to serve all or a part of the minimum power requirements of the electric system in such market on an around-the-clock basis. Because our projects supply a part of the baseload needs of the respective electric system and are only marginally weather dependent, we have a competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent dependent on precipitation), which compete with us to meet electric utilities’ renewable portfolio requirements but which cannot serve baseload capacity because of the weather dependence and thus intermittent nature of these other renewable energy sources.|
|•||Competitive Pricing. Geothermal power plants, while site specific, are economically feasible to develop, construct, own and operate in many locations, and the electricity they generate is generally price competitive as compared to electricity generated from fossil fuels or other renewable sources under existing economic conditions and existing tax and regulatory regimes.|
Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating projects produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable energy source. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Such clean and sustainable characteristics of geothermal energy give us a competitive advantage over fossil fuel-based electricity generation as countries increasingly seek to balance environmental concerns with demands for reliable sources of electricity.
High Efficiency from Vertical Integration. Unlike our competitors in the geothermal industry, we are a fully-integrated geothermal equipment, services and power provider. We design, develop and manufacture most of the equipment we use in our geothermal power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our projects efficiently and to respond to operational issues in a timely and cost-efficient manner. Moreover, given the efficient communications among our subsidiary that designs and manufactures the products we use in our operations and our subsidiaries that own and operate our projects, we are able to quickly and cost effectively identify and repair mechanical issues and to have technical assistance and replacement parts available to us as and when needed.
Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector. Key members of our senior management team have worked in the power industry for most of their careers and average over 20 years of industry experience.
Technological Innovation. We own or have rights to use approximately 70 patents relating to various processes and renewable resource technologies. All of our patents are internally developed and therefore costs related thereto are expensed as incurred. Our ability to draw upon internal resources from various disciplines related to the geothermal power sector, such as geological expertise relating to reservoir management, and equipment engineering relating to power units, allows us to be innovative in creating new technologies and technological solutions.
No Exposure to Fuel Price Risk. A geothermal power plant does not need to purchase fuel (such as coal, natural gas, or fuel oil) in order to generate electricity. Thus, once the geothermal reservoir has been identified and estimated to be sufficient for use in a geothermal power plant and the drilling of wells is complete, the plant is not exposed to fuel price or fuel delivery risk.
Our strategy is to continue building a geographically balanced portfolio of geothermal and recovered energy assets, and to continue to be a leading manufacturer and provider of products and services related to renewable energy. We intend to implement this strategy through:
|•||Development and Construction of New Projects — continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal and recovered energy-based power projects and entering into long-term power purchase agreements providing stable cash flows in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development and which meet our investment criteria;|
|•||Developing Recovered Energy Projects — establishing a first-to-market leadership position in recovered energy projects in North America and building on that experience to expand into other markets worldwide;|
|•||Acquisition of New Assets — acquiring from third parties additional geothermal and other renewable assets that meet our investment criteria;|
|•||Increasing Output from Our Existing Projects — increasing output from our existing geothermal power projects by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery; and|
|•||Technological Expertise — investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities.|
Operations of our Power Generation Segment
How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the acquisition) of the relevant plant. If we do not own all of the interest in a power plant, we enter into a shareholders agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with our project. Our ability to transfer or sell our interest in certain projects may be restricted by certain purchase options or rights of first refusal in favor of our project partners or the project’s power purchasers and/or certain change of control and assignment restrictions in the underlying project and financing documents. All of our domestic projects, with the exception of the Puna project, which is an Exempt Wholesale Generator (EWG), are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and are eligible for regulatory exemptions from most provisions of the Federal Power Act (FPA) and certain state laws and regulations.
How We Obtain Development Sites and Geothermal Resources. For domestic projects, we either lease or own the sites on which our power plants are located. In our foreign projects, our lease rights for the plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases) or a concession or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land. A geothermal resource lease (or sublease) or a concession or other agreement will usually give us the right to explore, develop, operate and maintain the geothermal field including, among other things, the right to drill wells (and if there are existing wells in the area, to alter them) and build pipelines for transmitting geothermal fluid. In certain cases, the holder of rights in the geothermal resource is a governmental entity and in other cases a private entity. Usually, the terms of the lease
(or sublease) and concession agreement correspond to the terms of the relevant power purchase agreement. In certain other cases, we own the land where the geothermal resource is located, in which case there are no restrictions on its utilization.
How We Sell Electricity. In the United States, the purchasers of power from our projects are typically investor-owned electric utility companies. Outside of the United States, the purchaser is typically a state-owned utility or distribution company or a recently privatized state-owned entity and we typically operate our facilities pursuant to rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically called power purchase agreements) for the sale of electricity or the conversion of geothermal resources into electricity. A project’s revenues under a power purchase agreement usually consist of two payments: energy payments and capacity payments (although our recent power purchase agreements provide for energy payments only). Energy payments are normally based on a project’s electrical output actually delivered to the purchaser measured in kilowatt hours, with payment rates either fixed or indexed to the power purchaser’s ‘‘avoided’’ costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties, such as us). Capacity payments are normally calculated based on the generating capacity or the declared capacity of a project available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of our domestic projects located in California are eligible for capacity bonus payments under the respective power purchase agreements upon reaching certain levels of generation.
How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries, (Ormat Nevada Inc., for our domestic projects) to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective projects; however, each project draws upon our available collective resources and experience and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup and other operational functions are pooled within each project complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our project availability goals.
We currently operate and maintain approximately 410 MW of generating capacity (See Note (2) page 7 for an explanation of how we determine the generating capacity of our projects). Since our acquisitions in California, Hawaii and Nevada, as a result of our vertical integration, our proprietary technology and our operational and maintenance expertise, we have been successful in increasing the capacity, efficiency and performance of most of our acquired facilities and were able to use the staff required to operate these facilities more efficiently. For example, we have been able to increase the output of the Mammoth project by approximately 4 MW following its acquisition in December 2003. We have also increased the capacity of the Heber Complex by 13 MW (out of which 3 MW were used for auxiliary power).
Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our projects can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents at our projects.
How We Finance Our Power Plants. Historically, we have funded our projects with a combination of non-recourse or limited recourse debt, lease financing, parent company loans and internally generated cash. Such leveraged financing permits the development of projects with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular project’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the financing documents.
Non-recourse debt or lease financing refers to debt or lease arrangements involving debt repayments or lease payments that are made solely from the project’s revenues (rather than our revenues or revenues of any other project) and generally are secured by the project’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in that project affiliate. These forms of financing are referred to as ‘‘project financing.’’ Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service (including lease payments) and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service.
In the event of a foreclosure after a default, our project affiliate owning the project would only retain an interest in the assets, if any, remaining after all debts and obligations have been paid in full. In addition, incurrence of debt by a project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge in favor of the project’s lenders securing the project’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.
Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for the project affiliate in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular project, distributions received by us from other projects and other sources of cash available to us may be required to be used to satisfy these obligations. To the extent of these limited recourse obligations, creditors of a project financing of a particular project may have direct recourse to us.
How We Mitigate International Political Risk. We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. The policies are issued by entities which specialize in such policies, such as MIGA, and from private sector providers, such as Zurich Re, AIG and other such companies. To date, our political risk insurance contracts are with MIGA and Zurich Re. Such insurance policies cover, in general and subject to the limitations and restrictions contained therein, 80% to 90% of our revenue loss derived from a specified governmental act such as confiscation, expropriation, riots, the inability to convert local currency into hard currency and, in certain cases, the breach of agreements. We have obtained such insurance for all of our foreign projects in operation except for the Leyte project.
|•||In February 2007, the Nevada Public Utilities Commission approved two new 20-year power purchase agreements that two of our subsidiaries entered into on August 3, 2006 with Nevada Power Company, a subsidiary of Sierra Pacific Resources, for the sale of energy to be produced from the Carson Lake (near Fallon) and Buffalo Valley Power Plants, two new geothermal power plants to be built in Lander and Churchill Counties in northern Nevada. The Carson Lake and Buffalo Valley projects are both projected to come on line in late 2009. These new plants are expected to increase the total output supplied from us to Sierra Pacific Resources by between 36 and 60 MW.|
|•||On January 31, 2007, we entered into two contracts with a combined value of $9.0 million with Enpower Green Energy Generation, Inc. for the supply of two OEC units for two REG plants to be located on the Duke Energy T South Pipeline System in British Columbia, Canada. The equipment is to be supplied within 13 to 14 months of February 27, 2007, the effective date of both contracts.|
|•||On January 19, 2007, our subsidiary developing the Olkaria III project entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement, with Kenya Power and Lighting Co. (KPLC), the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed after receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of Phase II of the project is expected, upon completion, to add approximately 35 MW to the existing facility, bringing the project’s total capacity to approximately 48 MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million.|
|•||In January 2007, one of our subsidiaries entered into a Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) regarding five new Recovered Energy Generation (REG) Power Plants along the Northern Border Pipeline in the States of Montana, North Dakota and Minnesota. According to the Option Agreement, Basin Electric will work towards fulfilling certain conditions with the goal to confirm that it is ready to enter into a definitive 25-year power purchase agreement. These conditions include the interconnection and rights to the site on which the power plants will be constructed. We have already secured the rights to the waste heat for two of the new power plants and will continue to work towards obtaining the rights to the remaining three new power plants. The approval for construction of the new power plants is expected during 2007 after both parties have fulfilled their prerequisite obligations under the Power Purchase Option Agreement.|
|•||In January 2007, two of our subsidiaries entered into supply and engineering, procurement and construction contracts with Ngawha Generation Ltd., a subsidiary of Top Energy Limited for a new geothermal power plant in Ngawha, New Zealand. The contracts are for a total of approximately $20 million, with construction of the power plant expected to be completed within 20 months from the contract date. Top Energy Limited is an environmentally friendly, local electricity network company in New Zealand.|
|•||In December 2006, one of our subsidiaries entered into geothermal leases in the North Brawley known geothermal resource area in Imperial County, California. These geothermal leases secured 1,270 acres and we are in discussion with other land owners in this area to secure additional leases. We expect to begin drilling activity to explore the resource upon receipt of the necessary drilling permits, which we expect will be granted in the first half of 2007.|
|•||On December 19, 2006, we completed a sale of 2,500,000 shares of common stock to Lehman Brothers in a block trade at a price of $37.50 per share, under a shelf registration statement filed in early 2006. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $92.5 million.|
|•||In November 2006, the California Public Utilities Commission (CPUC) approved several five-year agreements entered into with Southern California Edison (SCE) in May and June 2006 establishing new renewable energy pricing for our existing power purchase aqgreements . These new agreements fix the energy rates payable by SCE for the five-year period beginning May 1, 2007 for our Ormesa, Heber 1, Heber 2 and Mammoth geothermal projects located in California. Under the new agreements, the geothermal energy produced by these projects will be sold at an average fixed energy rate of $62.74 per MWh, starting with a rate of $61.50 per MWh for the first year, with an annual escalation of 1% thereafter. The new agreements will come into effect when the current Renewable Energy Pricing Agreement terminates on April 30, 2007. The new average energy rate of $62.74 per MWh will replace the existing rate of $53.70 per MWh. The capacity payment and capacity bonus under the respective power purchase agreement for each of the projects remain unchanged.|
|•||During the third quarter of 2006, one of our subsidiaries signed geothermal lease agreements for leases of surface, mineral and geothermal rights, some with the Bureau of Land|
|Management and some with private owners, for: (i) approximately 7,500 acres in the Fallon area in Nevada; (ii) approximately 3,200 acres in the Fireball Ridge area in Nevada; (iii) approximately 16,400 acres in Gabbs Valley, Nevada; and (iv) approximately 640 acres in the Wildhorse prospect in Nevada.|
|•||In October 2006, one of our subsidiaries completed the OREG 1 project along the Northern Border Pipeline in North Dakota and South Dakota. The OREG 1 project consists of four Recovered Energy Generation (REG) plants owned and operated by us with a total generating capacity of approximately 22 MW. Bismarck-based Basin Electric will purchase energy produced by these plants under a 25-year long-term power purchase agreement, which was announced in 2005.|
|•||During the third quarter of 2006, we responded to several requests for proposals issued by different utilities interested in purchasing renewable energy. Recently, we were informed that some of our bids covering approximately 150 MW of proposed capacity in Nevada, California and Idaho have been short-listed for further evaluation. There can be no assurance, however, that we will be chosen from the short list or that we will succeed in negotiating power purchase agreements with the various utilities.|
|•||On August 16, 2006, we acquired from two parties an additional 28.2% partnership interest (27.34% on a fully diluted basis assuming the exercise of an option by a third party) in Orzunil I de Electricidad, Limitada (Orzunil), which owns the Zunil project in Guatemala, thereby increasing our 71.8% ownership interest (69.67% on a fully diluted basis assuming the exercise of an option by a third party) in the Zunil Project to 100% (97% on a fully diluted basis, assuming the exercise of an option by a third party). The total purchase price for both acquisitions was $7.4 million (including acquisition costs of approximately $0.9 million). These acquisitions follow our acquisition of a 50.8% partnership interest (49.28% on a fully diluted basis assuming the exercise of an option by a third party) in Orzunil on March 13, 2006, whereby our subsidiary increased its then existing 21.0% ownership interest in the Zunil Project to 71.8% (69.67% on a fully diluted basis assuming the exercise of an option by a third party). The purchase price we paid for the 50.8% acquisition was $15.4 million (including acquisition costs of approximately $0.6 million).|
|•||In August 2006, the Nevada Public Utilities Commission approved the new 20-year power purchase agreement that our subsidiary entered into with Sierra Pacific Power Company in May 2006 for the sale of energy to be produced from the Galena 3 power plant, which is currently under construction. Under the new power purchase agreement, between 15 MW to 25 MW will be delivered from the Galena 3 project to SPPC for a fixed price of $61 per MWh, or $58 per MWh, assuming the project will be eligible for a production tax credit. These rates escalate at the beginning of each contract year by 1% and include the value of the renewable energy credits.|
|•||In July 2006, a consortium consisting of our wholly owned subsidiary, a unit of Medco Energi Internasional Tbk (Indonesia’s largest private oil and gas company), and Itochu Corp. of Japan won a tender issued by the Indonesian state-owned utility PT PLN (Persero) for the development of the Sarulla, North Sumatra, Indonesia geothermal power project on an independent power producer basis. Medco is the leader of the consortium, whose bid consisted of the completion of the development of the geothermal steam field, construction of the field piping systems and three Ormat designed and supplied power plants with a combined gross capacity of 340 MW, owning and operating the facilities and selling electricity to PLN under a 30-year power purchase agreement expected to be concluded within four months. Our specific responsibilities include the supply of the power plant and setting up and supervising the operations and maintenance of the plants, which will utilize our technology and equipment. The total project cost is projected to be about $600 million. The value of our scope of work for the supply of power plant equipment is expected to be approximately one-third of the total project cost. Release of the supply contracts to us will be made upon the financial closing of the transaction, expected to be 12 months from the effective date of|
|the power purchase agreement. The Sarulla project is to be constructed over the next five years in three phases of 110 to 120 MW each, with the first power generating unit to be operational within 30 months and the last within 48 months from the financial closing. The project will be owned and operated by an Indonesian special purpose company (SPC) that will be established by the consortium members under the framework of a Joint Operating Contract with the concession holder, Pertamina (the state-owned oil and gas company). In addition to our responsibilities as the project’s power plant equipment supplier and supervisor of operations and maintenance, we will participate as a minority shareholder in the SPC.|
|•||On July 26, 2006, we entered into a contract valued at $4.0 million with ENAGAS S.A. of Madrid, Spain, for the supply of one OEC unit for a REG plant located in the ENAGAS gas compression station at Almendralejo, Spain. The equipment is to be supplied and installed within 19 months from the date of the contract.|
|•||On July 20, 2006, we entered into a contract valued at $4.4 million with Geo X GmbH of Ludwigshafen, Germany, for the supply of one OEC unit for a geothermal power plant located in Landau, Germany. The equipment is to be supplied and installed within 17 months from the date of the contract.|
|•||On June 7, 2006, one of our wholly-owned subsidiaries received supply and construction orders for three REG power plants on the Alliance Pipeline. Each facility will have a capacity of 5 MW net and will convert the recovered waste heat from the exhaust of existing gas turbines into electricity. The contracts are in the total amount of $29.0 million. The three plants are expected to be commissioned in 2007 or early 2008.|
|•||On April 26, 2006, we received a notice to proceed on an engineering, procurement and construction (EPC) contract to construct a geothermal power plant for the Raft River project in Idaho, for a total sales price of $20.2 million. Construction of the power plant is expected to be completed in the last quarter of 2007.|
|•||On April 10, 2006, we completed a follow-on public offering of 3,500,000 shares of common stock at a price of $35.50 per share, under a shelf registration statement filed in early 2006. In addition, on April 17, 2006, the underwriters exercised their over-allotment option, thereby purchasing 525,000 additional shares of common stock at the same price. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $135.1 million.|
|•||On April 4, 2006, we signed a contract to supply a 10 MW OEC power unit to PacifiCorp Energy in the Northwest region of the United States. The contract is in the amount of $11.5 million. The existing PacifiCorp plant, to which an additional OEC will be added, uses single-flash technology to produce approximately 23 MW of net power to the grid. The PacifiCorp plant utilizes only steam, which is separated from the brine and delivered to the plant, while the brine is reinjected into the ground. Ormat’s technology enables recovery of heat from the brine before reinjection and PacifiCorp Energy will utilize this new OEC power unit to generate 10 MW of additional power in the OEC without additional resources or wells. The OEC power unit will be delivered in the second quarter of 2007 for installation adjacent to the existing plant.|
Description of Our Projects
In the year ended December 31, 2006, revenues from the sale of electricity by our domestic geothermal projects were $162.8 million, constituting 83.3% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign geothermal projects were $32.6 million, constituting 16.7% of our total revenues from the sale of electricity. During 2006 we began selling electricity from our recovered energy projects, whose construction was completed in 2006.
The financing of certain of our projects and the terms of our power purchase agreements and certain other agreements related to our operations are further described in the ‘‘Description of Certain Material Agreements’’ section.
Our projects in operation in the United States have a generating capacity of approximately 294 MW. Our current domestic projects are located in California, Nevada, Hawaii, North Dakota, and South Dakota. We also have projects under construction or enhancement in California, Nevada and Hawaii.
The Ormesa Complex
The Ormesa complex is located in East Mesa, Imperial County, California. The Ormesa complex consists of six plants. The various plants commenced commercial operations between 1987 and 1989. The plants utilize binary and flash systems. The Ormesa complex has a generating capacity of 47 MW. Part of the electricity generated by two of the plants at the Ormesa complex, GEM 2 and GEM 3, is sold under an interim agreement (as discussed below) and part of it is used to provide auxiliary power for well field operations at the Ormesa complex. The Ormesa project sells its electrical output to Southern California Edison Company (Southern California Edison) under two separate power purchase agreements, which will expire in 2017 and 2018. We are currently in discussions with Southern California Edison to unitize the two power purchase agreements and to increase the amount of power being purchased by an additional 10 MW. The Ormesa project was acquired by us in April 2002, was initially refinanced with project finance debt from United Capital, and was refinanced again with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Ormesa project (and any and all proceeds arising therefrom) and our project subsidiary, Ormesa LLC, the direct owner of the Ormesa project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes.
During 2006, we experienced a relatively high rate of well and pump failure at the Ormesa complex, resulting in increased operating costs and reduced revenues, and a lower availability of the Ormesa well field. As a result, we did not meet the required minimum capacity factor of 80% during the on-peak period for the months of June and September 2006. Consequently, we have been placed on probation for a period not to exceed 15 months. During the probation period, if we fail again to meet the minimum performance requirements, the capacity of the project may be permanently reduced, in which case Southern California Edison would be entitled to a refund. We believe that the risk of not meeting the minimum performance requirements during the probationary period and in the future is very low as we expect to increase the generating capacity of the Ormesa complex by 10 MW to a total of 57 MW by the end of the first quarter of 2007.
In connection with the power purchase agreements for the Ormesa complex, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa complex. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an Interim Agreement, whereby Southern California Edison will continue to procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 Cents/kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations of the long-term power purchase agreement are still under way and there is no guarantee that it will be successfully completed. Management believes that such settlement agreement will not have a material financial impact on us.
The Heber Complex
The Heber complex consists of the Heber 1 project, the Heber 2 project and the Gould project.
The Heber 1 Project. The Heber 1 project is located in Heber, Imperial County, California. The Heber 1 project includes one power plant, which commenced commercial operations in 1985, and a
geothermal resource field. The plant utilizes a dual flash system and has a generating capacity of approximately 38 MW. The Heber 1 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2015. In certain circumstances, Southern California Edison and its affiliated entities have a right of first refusal to acquire the power plant. Upon satisfaction of certain conditions specified in the power purchase agreement and subject to receipt of requisite approvals and negotiations between the parties, our project subsidiary will have the right to demand that Southern California Edison purchase the power plant. The acquisition of the Heber 1 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal Geothermal Inc. (OrCal) of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, Heber Geothermal Company, the direct owner of the Heber 1 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.
The Heber 2 Project. The Heber 2 project is also located in Heber, Imperial County, California. The Heber 2 project includes one power plant which commenced commercial operations in 1993. The plant utilizes a binary system and has a generating capacity of approximately 34 MW. The Heber 2 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2023. The acquisition of the Heber 2 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, Second Imperial Geothermal Company, the direct owner of the Heber 2 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.
The Gould Project. The Gould project is also located in Heber, Imperial County, California. The Gould project consists of a bottoming-cycle OEC at Heber 1 and additional Ormat Integrated Two Level Units (ITLU) at Heber 2 and has total generating capacity of 10 MW. The project sells its electrical output under a new long-term power purchase agreement with Southern California Public Power Authority for a fixed price, which in 2006 was $57.50/MWh, which escalates annually at a rate of 1.5%. This power purchase agreement will expire in 2031. The construction of the Gould project was financed with equity, and was included in the financing of OrCal’s Senior Secured Notes issued on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, OrHeber 2 Inc., the direct owner of the Gould project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes. Recently, our project subsidiary that owns the Gould project reached an agreement with Southern California Public Power Authority to eliminate the obligation under the power purchase agreement to share the production tax credits and in exchange to reduce the fixed price under the power purchase agreement by $2/MWh. We have undertaken to OrCal to make up the difference of $2/MWh such that its overall revenues from the project are not affected.
The Steamboat Complex
The Steamboat complex consists of the Steamboat 1/1A project, the Steamboat 2/3 project, the Burdette project and the Steamboat-Hills project.
The Steamboat 1/1A Project. The Steamboat 1/1A project is located in Steamboat Hills, Washoe County, Nevada. The Steamboat 1/1A project includes two power plants which commenced
commercial operations in 1986 and 1988, respectively. The Steamboat 1/1A project utilizes a binary system and currently has a generating capacity of 2 MW. The Steamboat 1/1A project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 1/1A project was acquired in June 2003 using internally generated cash, and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Steamboat 1/1A project (and any and all proceeds arising therefrom) and our project subsidiary, Steamboat Geothermal LLC, the direct owner of the Steamboat 1/1A project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.
The initial term of the Steamboat 1 power purchase agreement expired at the end of 2006 but we continue to sell electricity by an automatic extension of the power purchase agreement on a year-by-year basis. We are currently negotiating a renewal of the power purchase agreement for the years 2007 and 2008.
The Steamboat 2/3 Project. The Steamboat 2/3 project is also located in Steamboat Hills, Washoe County, Nevada. The Steamboat 2/3 project consists of two power plants which commenced commercial operations in 1992. The Steamboat 2/3 project utilizes a binary system and has a generating capacity of 24 MW. We have experienced protracted failures of two of the project’s turbines, which were not manufactured by us, and we are in the process of replacing the problematic equipment with turbines of our own design and manufacture. The Steamboat 2/3 project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 2/3 project was acquired in February 2004 using internally generated cash and proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Steamboat 2/3 project (and any and all proceeds arising therefrom) and our project subsidiary, Steamboat Development Corp., the direct owner of the Steamboat 2/3 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.
The Burdette Project. The Burdette Project is located in Steamboat, Washoe County, Nevada. The Burdette project has a generating capacity of 21 MW. We completed the construction of this project in November 2005 and we reached commercial operation on February 28, 2006. The project sells and transfers its electrical output and transfers its renewable energy credits to Sierra Pacific Power Company under a power purchase agreement that has a 20-year term ending on December 31, 2026.
The Steamboat-Hills Project. The Steamboat Hills project is also located in Steamboat Hills, Washoe County, Nevada. The Steamboat Hills project is comprised of one plant and commenced commercial operations in 1988. The Steamboat Hills project utilizes a single flash system and water cooled condenser and has a generating capacity of 6 MW, although the capacity under the power purchase agreement is 12.5 MW. The Steamboat Hills project sells its electrical output to Sierra Pacific Power Company pursuant to a power purchase agreement. The project, under the predecessor owner, experienced difficulties operating at full capacity, among other reasons because of a well blow-out. We intend to increase the generating capacity of the Steamboat Hills project by an additional 4 MW in the first half of 2007, to take full advantage of the power purchase agreement. The Steamboat Hills project was acquired in May 2004 using internally generated cash.
The Mammoth Complex
The Mammoth complex is located in Mammoth Lakes, California. The Mammoth complex is comprised of three plants, which commenced commercial operations between 1985 and1990. The Mammoth complex utilizes a binary system and has a generating capacity of 29 MW, including 4 MW
that we added during the course of 2006. Our project subsidiary, OrMammoth, Inc., owns a 50% partnership interest in Mammoth-Pacific, L.P., which owns 100% of the Mammoth complex. The other 50% partnership interest is owned by an unrelated third party. The Mammoth complex sells its electrical output to Southern California Edison under three separate power purchase agreements. Our 50% ownership interest in the Mammoth complex was acquired in December 2003 using internally generated cash and project finance debt from Beal Bank, and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by a pledge of our 50% ownership interest in Mammoth-Pacific, L.P. and our project subsidiary, OrMammoth Inc., has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.
The Brady Complex
The Brady complex consists of the Brady project and the Desert Peak 2 project.
The Brady Project. The Brady project is located in Churchill County, Nevada and includes the Brady plant and the Desert Peak 1 plant. The Brady plant commenced commercial operations in 1992. The Desert Peak 1 plant, which previously formed part of the Brady complex, commenced commercial operations in 1985, but is currently not operational following its shut down, as described below. The Brady project has a generating capacity of approximately 19 MW, utilizing flash and binary systems, and sells its electrical output to Sierra Pacific Power Company under a long-term power purchase agreement that will expire in 2022. In the second half of 2006, following our conclusion that the continued operation of the Desert Peak 1 plant at the Brady complex was not economical, based on the high costs of repair and maintenance that would be required to keep the Desert Peak 1 plant operational, we shut down the Desert Peak 1 plant. We are replacing the disconnected Desert Peak 1 plant with one of the units of the new Desert Peak 2 project and have been supplying electricity generated by such unit of the Desert Peak 2 project to the Brady project such that the overall output from the Brady project and its performance under its power purchase agreement have not been affected by the Desert Peak 1 plant shut down. We are also in the process of drilling a new production well and redrilling another well, with the intent of restoring the Brady project’s generating capacity to 19 MW during the second half of 2007.
The Brady project was acquired in June 2001 using internally generated cash and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Brady project (and any and all proceeds arising therefrom) and our project subsidiary, Brady Power Partners, the direct owner of the Brady project, has jointly and severally with certain of our other subsidiaries, fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes and certain other matters relating to the Brady complex and the OFC Senior Secured Notes.
The Desert Peak 2 Project. The Desert Peak 2 project is located in Churchill County, Nevada (near the Brady project). The Desert Peak 2 project includes a water cooled unit and an air cooled unit, utilizing our OEC units. The aggregate generating capacity of the Desert Peak 2 project is 12 MW. The electrical output from the project will be sold, and renewable energy and environmental credits transferred, to Nevada Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of the project. We expect to declare commercial operation of the Desert Peak 2 project during the first half of 2007. Recently, we have been using a portion of the electrical output from the Desert Peak 2 project to supply the Brady project, as described above. As of February 2007, we no longer supply electricity generated by the Desert Peak 2 project to the Brady project.
The Puna Project
The Puna project is located in the Puna district, Big Island, Hawaii. The Puna plant commenced commercial operations in 1993. The Puna plant utilizes an Ormat geothermal combined cycle system,
and has a generating capacity of 30 MW. The Ormat geothermal combined cycle system consists of a back pressure steam turbine, in which the lower pressure steam exhausted from the turbine is condensed in a binary system. This system assures a higher efficiency of geothermal steam, with a resulting lower steam rate, in resources producing steam above 150psi (10 bar), or even 100psi if the steam has a high non-condensable gas content. The Puna project sells its electrical output to Hawaii Electric Light Company under two power purchase agreements. Although the Puna project has significant geothermal resources, because of existing geological conditions, these resources are difficult to manage. In the past, the Puna project required extensive levels of investment mainly to address problems with the production and injection wells related to the geothermal resources. The Puna project was acquired in June 2004 with the proceeds of parent company loans and short-term bank loans. We completed operating lease transactions in respect of the project, as described under ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’.
During the second half of 2006, we encountered a mechanical problem in two wells. This caused us to limit the output of the project to approximately 20 MW as a precautionary limit. During the first quarter of 2007, we were able to restore the output to 30 MW, the level of the project’s design capacity.
In addition, we intend to increase the output of the Puna project by an additional 8 MW through the addition of OEC units. We are in the process of negotiating a new power purchase agreement for the additional generating capacity that will be available as a result of such activities.
The OREG 1 Project
The OREG 1 project is a REG project that consists of four power plants constructed on gas compressor stations along a natural gas pipeline in North and South Dakota. The project came on line during the third quarter of 2006 and has a generating capacity of 22 MW. Our project subsidiary has entered into a 25-year power purchase agreement with Basin Electric Power Cooperative (Basin Electric) pursuant to which the project sells the electrical output to Basin Electric.
Our projects in operation outside of the United States have a generating capacity of approximately 113 MW. We also have projects under construction in Guatemala and Kenya.
The Leyte Project (The Philippines)
The Leyte project is located in the Philippines, on the Isle of Leyte. The Leyte project consists of four power plants. The Leyte plants utilize steam systems; one conventional flash steam plant and three ORMAT manufactured topping steam turbines and have a combined generating capacity of 49 MW. The ORMAT topping steam turbines generate additional power by using the reduction in pressure to the inlet of the conventional flash steam plant, situated downstream, necessitated when the existing steam field produced steam at a higher pressure than can be accommodated by the conventional flash steam plant. Our project subsidiaries have an 80% partnership interest in Ormat-Leyte Co. Ltd., which owns 100% of the Leyte project. The remaining 20% partnership interest in Ormat-Leyte Co. Ltd. is held by two unrelated third parties. In August 1995, following a build-operate-transfer agreement, which we refer to as BOT, international tender, Ormat Inc. (which later transferred its interest in the BOT agreement to Ormat-Leyte Co. Ltd.) entered into a BOT agreement with PNOC-Energy Development Corporation, a Philippine company wholly owned by Philippine National Oil Company, a government-owned company. Under the BOT agreement, the project will be transferred to PNOC-Energy Development Corporation in September 2007 for no consideration. We do not anticipate any material financial loss as a result of such transfer, although going forward this will reduce our foreign generation capacity by 49 MW. Ormat-Leyte Co. Ltd. has an outstanding non-recourse loan from the Export-Import Bank of the United States, the outstanding balance of which was $3.8 million as of December 31, 2006. The loan is due and payable in approximately equal quarterly installments through July 2007.
The Government of The Philippines has initiated the privatization of its electricity industry. However, we cannot foresee when such privatization may be completed. If such privatization is
achieved in a manner that jeopardizes PNOC-Energy Development Corporation’s or its affiliate’s ability to comply with their obligations under the BOT agreement, the parties are required to negotiate an amendment to the power purchase agreement. Should they fail to reach an agreement, PNOC-Energy Development Corporation has the obligation (and our project subsidiary has the right to require PNOC-Energy Development Corporation) to buy out Ormat-Leyte Co. Ltd.’s rights in the project at a price based upon the net present value of the projected cash flow from the project for the remaining term of the BOT agreement.
The Momotombo Project (Nicaragua)
The Momotombo project is located in Momotombo, Nicaragua. The Momotombo project is comprised of one plant and a geothermal field. The plant was already in existence when we signed the concession agreement for the project in March 1999, and had commenced commercial operations in the mid-1980s utilizing a dual flash system. During 2006 we increased the output of the Momotombo project by 3 MW through a work-over of the project’s existing wells, bringing the generating capacity to approximately 30 MW. The Momotombo project has a power purchase agreement with Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), two corporations which own the power distribution rights in Nicaragua. Our project subsidiary, which operates the Momotombo project, has an outstanding loan from Bank Hapoalim B.M., the outstanding balance of which was $11.3 million as of December 31, 2006.
The Olkaria III Project — Phase I (Kenya)
The Olkaria III project is located in Naivasha, Kenya. The Olkaria III project is comprised of one plant, which commenced commercial operation in August 2000, and a geothermal field. The plant currently has a generating capacity of approximately 13 MW (Phase I). We are working on the construction of Phase II of this project which we expect, upon completion, will increase the generating capacity of the Olkaria III project to approximately 48 MW. A description of Phase II of this project is set forth below in ‘‘Projects under Development.’’ Phase I of the Olkaria III project utilizes a binary system. In November 1998, following an international tender, our project subsidiary entered into a power purchase agreement with the Kenya Power and Lighting Co. Ltd. (KPLC), the Kenyan parastatal electricity transmission and distribution company, which was recently amended and restated in January 2007 . Our project subsidiary leases the site on which the geothermal resources and the plant facilities are located from the Kenyan government, pursuant to an agreement which will expire in 2040. The Kenyan government granted our project subsidiary a license giving it exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended for two additional five-year terms by us. The Kenyan Minister of Energy has the right to terminate or revoke the license in the event our project subsidiary ceases work in or under the license area during a period of six months, or has failed to comply with the terms of the license or the provisions of the law relating to geothermal resources. Our project subsidiary is obligated to pay the Kenyan government monthly fees and royalties based on the amount of power supplied to KPLC.
The Zunil Project (Guatemala)
The Zunil project is located in Zunil, Guatemala. The Zunil project is comprised of one plant which commenced commercial operations in 1999. The plant utilizes a binary system consisting of Ormat Energy Converters and has a generating capacity of 24 MW. The project is owned by Orzunil I de Electricidad, Limitada, which owns 100% of the Zunil project. Another of our subsidiaries provides operation and maintenance services to the project. The Zunil project sells its generating capacity to Instituto Nacional de Electrification pursuant to a power supply agreement. As of the date of this annual report, Orzunil I de Electricidad, Limitada has two senior outstanding non-recourse loans, one from International Finance Corporation (IFC) and the other from the Commonwealth Development Corporation (CDC), the aggregate total balance of which was, as of December 31, 2006, $19.4 million. The loans are due and payable in quarterly installments through November 2011. Each of the IFC and the CDC owned 14.1% of the issued and outstanding partnership interests of Orzunil I de
Electricidad, Limitada. On March 13, 2006 and on August 16, 2006, we consummated the acquisition of an additional 50.8% and 28.2%, respectively, of the ownership interest in the Zunil project and thereby increased our 21% ownership interest to 100% (97% on a fully diluted basis assuming the exercise of an option by a third party).
Projects under Construction
We are in varying stages of construction or enhancement of projects, both domestic and foreign. Based on our current construction schedule, we expect to add new generating capacity of approximately 114 MW in the United States and approximately 55 MW throughout the rest of the world by the end of 2008 or early 2009. This amount will be reduced by the 49 MW (of which we own 80%) of the Leyte project. The following is a description of the projects currently undergoing construction:
The Amatitlan Project (Guatemala)
Our project subsidiary has completed the construction of a geothermal power plant in Amatitlan, Guatemala on a ‘‘build, own and operate’’ or ‘‘BOO’’ basis. The project is currently in final completion tests. The project is comprised of one power plant, which will have a generating capacity of 20 MW, and has obtained the rights to various geothermal production and reinjection wells. The Amatitlan plant uses our Ormat Energy Converters.
The term of the power purchase agreement for the Amatitlan project is 20 years from the date of the commencement of operations at the power plant or 23 years from the date of commencement of the construction work, whichever is later. During a period of two years after the completion of the construction of the power plant, and subject to the signing of an additional agreement with the Instituto Nacional de Electrification and the result of a feasibility test, our project subsidiary may increase the power generating capacity of the power plant through the drilling of additional wells and adding another power plant by up to an aggregate of 50 MW. We anticipate that commercial operation of the Amatitlan project will be declared in the first half of 2007.
The local municipal authorities have claimed that a construction license is required for the project, while our local counsel has advised us that no such license is required under the applicable laws and regulations. We are challenging the claim of the local municipal authorities.
The Galena 2 Project (U.S.)
The construction of the Galena 2 project in Washoe County, Nevada is completed and we are in the start up phase. The project is expected to have a generating capacity of 10 MW. Our project subsidiary will sell electrical output from the plant, and transfer the renewable energy and environmental credits, to Nevada Power Company under a power purchase agreement with a 20-year term that will commence on the first day of the year following the commercial operation date of the plant. The power purchase agreement was signed as part of Nevada Power Company’s efforts to comply with Nevada’s renewable portfolio standards.
The Heber South Project (U.S.)
We have started the construction of a 10 MW power plant, which will be located in what is known as the Heber Known Geothermal Resource Area or Heber KGRA. The construction activity is expected to include the drilling of production and injection wells and the construction of an OEC unit. Completion is expected in the first half of 2008. The power purchase agreement for this addition to the Heber complex is still under negotiation.
The Galena 3 Project (U.S.)
We have started the construction of the Galena 3 project, which will be located in Washoe County, Nevada. The project will increase the output of the Steamboat Complex by 17 MW of power
generation under a 20-year power purchase agreement with Sierra Pacific Power Company. We expect the construction, which will bring the total generating capacity of the Steamboat Complex to approximately 85 MW, to be completed by the end of 2007 or the beginning of 2008.
The Brawley Phase I Project (U.S.)
We have started the construction of a 50 MW power plant, which will be located in the North Brawley known geothermal resource area in Imperial County, California. Drilling started in February 2007 and we are negotiating the power purchase agreement for this project.
The OrSumas Project
The OrSumas project is a REG plant currently in the construction stage and is expected to have a generating capacity of 5 MW. Our project subsidiary has entered into a 20-year power purchase agreement with Puget Sound Energy pursuant to which the project will sell its electrical output to Puget Sound Energy. The power plant will be constructed on a gas compressor station along the Northwest Pipeline in the State of Washington. Our engineering work has identified certain environmental issues on the proposed project site. We are currently in the midst of discussions with the pipeline company regarding these environmental issues for which we are not responsible. The outcome of these discussions may result in a delay or termination of the project activities.
The Olkaria III Project — Phase II (Kenya)
As previously noted, our project subsidiary in Kenya has been working towards the construction of Phase II of the Olkaria III project. As of the date of this report, our project subsidiary has drilled wells and commenced preliminary construction activities but has not begun any material construction activities with respect to Phase II. On January 19, 2007, we entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement with Kenya Power and Lighting Co. (KPLC), the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed after the receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of the second phase of the project is expected, upon completion, to add approximately 35MW to the existing facility, bringing the project’s total capacity to approximately 48MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million.
Under the Amended and Restated Power Purchase Agreement, the parties agreed to (i) shorten the construction period for Phase II to approximately twenty one months commencing from the deposit of the agreed collateral by KPLC, which occurred on February 7, 2007; (ii) change the technical configuration of Phase II such that the plant will use OEC units to generate electricity; and (iii) reduce the tariff payable by KPLC on the total capacity of the plant upon completion of Phase II.
Under the Project Security Agreement, KPLC provided a letter of credit in an amount equal to the value of four months of anticipated revenues from the project under the Amended and Restated Power Purchase Agreement (currently valued at approximately $8 million).
We are currently pursuing construction or enhancement activities in the following projects:
|•||Steamboat Hills project: We plan to complete the construction of an additional 4 MW during the first quarter of 2007; and|
|•||Ormesa project: We plan to complete the construction of an additional 10 MW during the first quarter of 2007; and|
|•||Puna project: We plan to add 8 MW through the construction of OEC units by the end of 2008 or early 2009. We are in discussions with Hawaii Electric Light Company for the sale of additional electrical power from the Puna project.|
Projects under Development and Future Projects
We also have projects under development in the United States, China and Indonesia. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria.
The Carson Lake Project (U.S.)
We are currently developing the Carson Lake project, which will be located in Churchill County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed during 2009. The leases for this project have been obtained through an agreement with the U.S. Department of the Navy, which will get 5% of the revenues as royalties during the first 20 years of operation.
The Buffalo Valley Project (U.S.)
We are currently developing the Buffalo Valley project, which will be on BLM leases located in Lander County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed during 2009.
The OREG II Projects (U.S.)
We recently entered into a Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) regarding five new REG Power Plants, with a total generating capacity of 27.5 MW, along the Northern Border Pipeline in the States of Montana, North Dakota and Minnesota. According to the Option Agreement, Basin Electric will work towards fulfilling certain conditions with the goal of confirming its readiness to enter into a definitive 25-year power purchase agreement. We have already secured the rights to the waste heat for two of the new power plants and will continue to work towards obtaining the rights to the remaining three new power plants. The approval for construction of the new power plants is expected during 2007.
The Brawley Phase II Project (U.S.)
If the results of the drilling activities we are currently undertaking in connection with the Brawley Phase I project will indicate the existence of sufficient geothermal resource, we plan to construct an additional 50 MW power plant, which will be located in the North Brawley known geothermal resource area in Imperial County, California, adjacent to Phase I of the Brawley project.
The Yunnan Project (China)
OrYunnan Geothermal Co., Ltd., which is a joint venture established between our project subsidiary and Yunnan Province Geothermal Development Co., Ltd., owns exclusive rights to develop all of the geothermal resources in Teng Chong County, Baoshan City, in Yunnan Province, southwest China. Our project subsidiary owns 85% of the interests in OrYunnan Geothermal Co. Ltd., which owns all of the ownership interests in the Yunnan project. The area of the geothermal concession is approximately 65 square miles and is located approximately 200 miles southwest of Kunming, the provincial capital of Yunnan, and approximately 40 miles from the border with Myanmar. We estimate the potential of the geothermal resources in the concession area to be between 150 to 200 MW. Initially, our project subsidiary and its partner intend to develop a geothermal field and construct a power plant with a generating capacity of approximately 42 MW, which we estimated would require a capital investment of approximately CNY 776.9 million (approximately $99.6 million calculated at the prevailing exchange rate on December 31, 2006). Our project subsidiary is awaiting Yunnan Provincial Government approval, following which negotiations with the provincial utility company towards the signing of a power purchase agreement may conclude. Following the approval of the Yunnan Provincial Government, the electricity feed-in tariffs would still require central government approval.
Such tariffs will be based on the implementing regulations to be announced shortly. On May 29, 2002, our project subsidiary entered into a memorandum of understanding, which we refer to as an MOU, regarding the main terms of the power purchase agreement and other major project agreements with Yunnan Electric Power Co., Ltd., a state-owned utility company, concerning the purchase of electric power by the utility company from our project subsidiary on a 30-year basis and the related interconnection arrangements. The MOU estimated that the commercial operation date of the plant was to be January 1, 2006. However, we have been in the development stage of the OrYunnan Project for several years and this date will have to be extended for an appropriate period following the completion of the Chinese central government’s approval.
The Sarulla Project (Indonesia)
We are a member of a consortium, which is in the process of developing a geothermal power project in Indonesia of approximately 300 MW that is expected to come on line in phases between 2010 and 2012. We estimate that our minority interest equivalent will range between 45 MW to 60 MW.
In addition to the geothermal projects under construction and development, we have various leases for geothermal resources, in which we have started exploration activity. These geothermal resources include the following:
|•||Grass Valley — Lander County, NV;|
|•||Jersey Valley — Pershing County, NV;|
|•||Magic Hot Springs — Blaine & Camas Counties, Idaho;|
|•||Fireball Ridge — Churchill County, NV;|
|•||Gabbs Valley — Nye County, NV;|
|•||Rock Hills — Esmeralda County, NV.|
Our exploration activity is intended to provide us with an indication and better understanding of the availability of geothermal resources in the areas covered by these leases and will enable us to make a decision regarding their development. We do not expect that our exploration activity will lead to commercial projects in each case.
In addition to the geothermal projects under construction, development or exploration, we have various geothermal leases for future development in the United States and other development rights outside of the United States. These geothermal leases and rights include the following:
|•||Oregon — one site;|
|•||California — three sites;|
|•||Nevada — three sites;|
|•||Hawaii — one site;|
|•||Idaho — three sites;|
|•||Texas — several leases; and|
|•||Outside of the United States — two sites.|
Operations of our Products Segment
Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or OECs. Our customers include contractors and geothermal plant owners and operators.
The consideration for the power units is usually paid in installments, in accordance with milestones set in the supply agreement. Sometimes we agree to provide the purchaser with spare parts (or alternatively, with a non-exclusive license to manufacture such parts). We provide the purchaser with at least a 12-month warranty for such products. We usually also provide the purchaser (often, upon receipt of advances made by the purchaser) with a guarantee, which expires in part upon delivery of the equipment to the site and fully expires at the termination of the warranty period. The guarantees are at times covered by letters of credit. Ormat has not received any claims under the performance guarantees to date.
Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy or so-called ‘‘waste heat’’ that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We view recovered energy generation as a significant market opportunity for us, and plan to utilize two different business models in connection with such business opportunity. The first, which is similar to the model utilized in our geothermal power generation business, consists of the development, construction, ownership and operation of recovered energy-based generation power plants. In this case, we will enter into agreements to purchase industrial waste heat, and into long-term power purchase agreements with off-takers to sell the electricity generated by the recovered energy generation unit that utilizes such industrial waste heat. We expect that the power purchasers in such cases will be investor-owned electric utilities or local electrical cooperatives. In early 2006, we signed a supply contract with UltraTech Cement Ltd. in Mumbai, India for the supply of one OEC for a new REG power plant.
Pursuant to the second business model, we construct and sell the power units for recovered energy-based power generation to third parties for use in ‘‘inside-the-fence’’ installations or otherwise. Our customers include gas processing plant owners and operators, cement plant owners and operators and companies in the process industry. The Neptune recovered energy project is an example of such a model. There, we installed one of our recovered energy-based generation units at Enterprise Product’s Neptune gas processing plant in Louisiana. The unit utilizes exhaust gas from two gas turbines at the plant and is providing electrical power that is consumed internally by the facility (although a portion of the generated electricity is also sold to the local electric utility). Recently we signed two agreements (with ICQ and Ultratech) for the supply of Ormat OEC systems for Recovered Energy Generation plants.
Our recovered energy generation units, if structured properly, may be eligible for favorable tax treatment, such as the seven year modified accelerated cost recovery under relevant U.S. federal tax rules.
Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme climate conditions, whether hot or cold. The remote power units supply energy for remote and unmanned installations and along communications lines and cathodic protection along gas and oil pipelines. Our customers include contractors installing gas pipelines in remote areas. In addition, we manufacture and sell generators for various other uses, including heavy duty direct current generators. Our remote power units were recently supplied to the Sakhalin pipeline in Russia. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.
Engineering, Procurement and Construction (EPC) of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis,
using power units we design and manufacture. Our customers are geothermal power plant owners as well as the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. The consideration for such services is usually paid in installments, in accordance with milestones set in the EPC contract and related documents. We usually provide performance guarantees or letters of credit securing our obligations under the contract. Upon delivery of the plant to its owner, such guarantees are replaced with a warranty guarantee, usually for a period ranging from 12 months to 36 months. The EPC contract usually places a cap on our liabilities for failure to meet our obligations thereunder. For example, we are currently acting as the EPC contractor for the Alliance REG plants in Canada.
We also design and construct the recovered energy generation units on a turnkey basis, and may provide a long-term agreement to supply non-routine maintenance for such units. Our customers are interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators and companies engaged in the process industry. For example, recently we entered into supply and construction contracts with Alliance pipeline in Western Canada for an Ormat Recovered Energy Generation power plant.
In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation and remote power units and other generators, we, from time to time, enter into sales agreements for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory covered by such agreements by such representatives or, in some cases, by other representatives in such territory.
Our manufacturing operations and products are certified ISO 9001, ISO 14001, ASME and TÜV, and we are an approved supplier to many electric utilities around the world.
The Company and its wholly owned subsidiaries have a products backlog of $89.5 million as of February 28, 2007, which includes revenues for the period between January 1, 2007 and February 28, 2007, compared to $81.8 million as of March 15, 2006. The following is a breakdown of the Products Segment backlog:
We expect that our revenues from electricity for the 2007 fiscal year will be approximately $220 million from our wholly owned projects and approximately $18.0 million from our subsidiaries accounted for by the equity method.
Our 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 the Organic Rankine Cycle) and systems (mainly geothermal power plants and industrial waste heat recovery for electricity production). The systems-related patents cover not only a particular component but rather the overall effectiveness of the plant’s systems from the ‘‘fuel’’ (i.e., geothermal fluid, waste heat, biomass or solar) to generated electricity. The duration of such patents ranges from one year to 14 years. No single patent on its own is material to our business.
The products-related patents cover components such as turbines, heat exchanges, seals and controls. The system patents cover subjects such as disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources and use of two-phase fluids. A number of patents cover the combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power.
We are also involved in developing new technology to extract heat from the earth by circulating fluid through an enhanced or man-made reservoir created in naturally low permeable or water-poor rocks. We are undertaking this development in cooperation with GeothermEx Inc., the University of Utah, Energy & Geoscience Institute, the University of Nevada-Reno and the Great Basin Center for Geothermal Energy, with funding support from the United States Department of Energy.
The power generation industry is characterized by intense competition from electric utilities, other power producers, and marketers. In recent years, the United States in particular has seen increasing competition in power sales, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term markets. In the last year, competition from the wind and solar power generation industry has increased. While the current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements, this increased competition may contribute to a reduction in electricity prices for new renewable projects.
In the geothermal power generation sector, our main competitors in the United States are CalEnergy, Calpine (which filed for protection under Chapter 11 of the U.S. Bankruptcy Code in late 2005), Caithness and other smaller-sized developers such as U.S. Geothermal. Some of these companies are also active outside of the United States. Outside of the United States, aside from these companies and ENEL, which is based in Italy, we may face competition from national electric utilities or state-owned oil companies.
In the products business, our main competitors are Mitsubishi, Fuji and Toshiba of Japan, GE/Nuevo Pignone, Ansaldo and Turboden of Italy, Siemens of Germany, Alstom of France and Kaluga of Russia. Recently, two new small players have been trying to penetrate the market. In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets. Recently, United Technologies announced the introduction of a small 200 kW Organic Rankine Cycle unit.
Siemens of Germany as well as other manufacturers of conventional steam turbines are potential competitors in the recovered energy generation business; although we believe that our recovered energy generation system has technological and economical advantages over the Siemens/Kalina technology and, under certain conditions, conventional steam technology.
We also compete with companies engaged in the power generation business from renewable energy sources other than geothermal energy, such as wind power, solar power and hydro-electric power.
None of our competitors competes with us both in the sale of electricity and in the products business.
Most of our revenues from the sale of electricity in the year ended December 31, 2006 were derived from fully-contracted energy and/or capacity payments under long-term power purchase agreements with governmental and private utility companies. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company accounted for 30.0%, 15.1% and 12.8% of revenues, respectively, for the year ended December 31, 2006. Based on publicly available information, as of December 31, 2006, the issuer ratings of Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (a power purchaser for the Desert Peak 2 and Galena 2 projects) were A3 (stable outlook), Ba3 (stable outlook) and Ba3 (stable outlook), respectively, from Moody’s Investors Services and BBB+ (stable outlook), BB− (stable outlook), and BB− (stable outlook), respectively, from Standard & Poor’s Ratings Services and the issuer rating of Hawaii Electric Light Company was BBB+ (negative outlook) from Standard & Poor’s Ratings Services. SCPPA, which has purchased the power from the Gould project since the beginning of 2006, has senior unsecured debt ratings ranging from A1 from Moody’s and A+ from S&P, in each case with a stable ratings outlook. The credit ratings of any power purchaser may decrease from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the power purchase agreements for our foreign power projects.
Our revenues from the products business were derived from contractors or owners or operators of power plants, process companies and pipelines.
Raw Materials, Suppliers and Subcontractors
In connection with our manufacturing activities, we use raw materials such as steel and aluminum. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of such raw materials are readily available from various suppliers.
Since 2005 we have increased the volume of work ordered from subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which allowed us to expand our construction and development capacity on an as-needed basis. We are not dependent on any one subcontractor and expect to be able to replace any subcontractor, or assume such manufacturing and construction activities of our projects ourselves without adverse effect to our operations.
As of December 31, 2006, we employed 774 employees, of which 252 were located in the United States, 363 were located in Israel and 159 were located in other countries. We expect that future growth in the number of our employees will be mainly attributable to the purchase and/or development of new power plants.
None of our employees (other than the Momotombo project employees) are represented by a labor union, and we have never experienced any labor dispute, strike or work stoppage. We consider our relations with our employees to be satisfactory. We believe our future success will depend on our continuing ability to hire, integrate and retain qualified personnel.
We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Industry, Trade and Labor the provisions of a collective bargaining agreement between the Histadrut (the General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations (which includes the Industrialists Association) may apply to some of our non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns cost of living increases, length of the workday, minimum wages, insurance for work-related accidents, procedures for dismissing employees, annual and other vacation, sick pay, determination of severance pay, pension contributions and other conditions of employment. We currently provide such employees with benefits and working conditions which are at least as favorable as the conditions specified in the collective bargaining agreement.
We maintain business interruption insurance, casualty insurance, including flood and earthquake coverage, and primary and excess liability insurance, as well as customary worker’s compensation and automobile insurance and such other insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas and financed in a similar manner. To the extent any such casualty insurance covers both us and/or our projects, on the one hand, and any other person and/or plants, on the other hand, we generally have specifically designated as applicable solely to us and our projects ‘‘all risk’’ property insurance coverage in an amount based upon the estimated full replacement value of our projects (provided that earthquake and flood coverage may be subject to annual aggregate limits depending on the type and location of the project) and business interruption insurance in an amount that also varies from project to project.
We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. Political risk insurance policies are generally issued by entities which specialize in such policies, such as the Multilateral Investment Guarantee Agency (a member of the World Bank Group), and from private sector providers, such as Zurich Re, AIG and other such companies. To date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Re. Such insurance policies cover, in general, and subject to the limitations and restrictions contained therein, 80% to 90% of our revenue loss derived from a specified governmental act, such as confiscation, expropriation, riots, the inability to convert local currency into hard currency and, in certain cases, the breach of agreements. We have obtained such insurance for all of our foreign projects in operation except for the Leyte project.
Regulation of the Electric Utility Industry in the United States
The following is a summary overview of the electric utility industry and applicable federal and state regulations, and should not be considered a full statement of the law or all issues pertaining thereto.
PURPA provides certain benefits described below, if a project is a ‘‘Qualifying Facility’’. There are two types of Qualifying Facilities: cogeneration facilities and small power production facilities. A small power production facility is a Qualifying Facility if (i) the facility does not exceed 80 megawatts, (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and 75% of the total energy input of the facility is from these sources; and (iii) the facility has filed with FERC a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status, that has been granted. The 80 megawatt size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, or waste resources; and (ii) an application for
certification or a notice of self-certification of qualifying status of the facility was submitted to the FERC prior to December 21, 1994, and construction of the facility commenced prior to December 31, 1999.
PURPA exempted Qualifying Facilities from regulation under the Public Utility Holding Company Act of 1935 (PUHCA) and exempts Qualifying Facilities from most provisions of the Federal Power Act (FPA) and state laws relating to the financial, organization and rate regulation of electric utilities. In addition, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utility’s incremental cost of purchasing or producing energy (also known as ‘‘avoided cost’’).
Pursuant to the Energy Policy Act of 2005, FERC has recently issued a final rule that will require Qualifying Facilities to obtain market-based rate authority pursuant to the FPA for sales of energy or capacity (i) from facilities larger than 20 MW in size; (ii) pursuant to a contract executed after March 17, 2006 that is not a contract made pursuant to a state regulatory authority’s implementation of PURPA; or (iii) not pursuant to another provision of a state regulatory authority’s implementation of PURPA. The practical effect of this final rule is to require Qualifying Facilities that are larger than 20 MW in size that seek to engage in non-PURPA sales of power (i.e. power that is sold in a manner that is not pursuant to a pre-existing contract or state implementation of PURPA) to obtain market-based rate authority from FERC for these non-PURPA sales.
The Energy Policy Act of 2005 also allows FERC to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to either (i) independently administered, auction-based day ahead and real time markets for energy and wholesale markets for long-term sales of capacity; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales; or (iii) wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC has recently issued a rule to implement these provisions of the Energy Policy Act of 2005. This rule gives nine (9) utilities the right to apply to eliminate the mandatory purchase obligation if the utility is a member of one of four regional transmission organizations. None of our domestic projects sells power pursuant to contracts with utilities in any of these four regional transmission organizations. The rule also creates a rebuttable presumption that a utility provides nondiscriminatory access if it has an open access transmission tariff in compliance with FERC’s pro forma open access transmission tariff, which is currently under review by FERC to ensure that its provisions prevent undue discrimination in the provision of transmission service. Further, the rule provides a procedure for utilities that are not members of the four named regional transmission organizations to file to obtain relief from the mandatory purchase obligation on a service territory-wide basis, and establishes procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. The rule protects a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into after August 8, 2005 but before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. The rule also protects a Qualifying Facility’s rights under any contract or obligation for the sale of energy in effect or pending approval before the appropriate state regulatory authority or non-regulated electric utility on August 8, 2005.
In addition, the Energy Policy Act of 2005 eliminated the restriction on utility ownership of a Qualifying Facility. Prior to the Energy Policy Act of 2005, electric utilities or electric utility holding companies could not own more than a 50% equity interest in a Qualifying Facility. Under the Energy Policy Act of 2005, electric utilities or holding companies may own up to 100% of the equity interest in a Qualifying Facility.
We expect that our projects will continue to meet all of the criteria required for Qualifying Facilities under PURPA. However, since the Heber Projects have power purchase agreements with Southern California Edison that require Qualifying Facility status to be maintained, maintaining Qualifying Facility status remains a key obligation. If any of the Heber Projects loses its Qualifying
Facility status our operations could be adversely affected. Loss of Qualifying Facility status would eliminate the Heber Project’s exemption from the FPA and thus, among other things, the rates charged by the Heber Projects in the power purchase agreements with Southern California Edison and SCPPA would become subject to FERC regulation. Further, it is possible that the utilities that purchase power from the projects could successfully obtain an elimination of the mandatory-purchase obligation in their service territories. If this occurs, the Project’s existing power purchase agreements will not be affected, but the utilities will not be obligated under PURPA to renew these power purchase agreements or execute new power purchase agreements upon the existing power purchase agreements’ expiration.
PUHCA has been repealed, effective February 8, 2006, pursuant to the Energy Policy Act of 2005. Although PUHCA was repealed, the Energy Policy Act of 2005 created a new Public Utility Holding Company Act of 2005 (PUHCA 2005). Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. If a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC. By virtue of being Qualifying Facilities that make only wholesale sales of electricity, Qualifying Facilities already are not subject to state commissions’ rate, financial and organizational regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to state regulation.
Pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are generally exempt from the FPA. If any of the projects were to lose its Qualifying Facility status, such project could also become subject to the full scope of the FPA and applicable state regulations. The application of the FPA and other applicable state regulations to the projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a project does not lose Qualifying Facility status, pursuant to a final rule issued by FERC pursuant to the Energy Policy Act of 2005, if a power purchase agreement with a project is terminated or otherwise expires, the project will become subject to rate regulation under the Federal Power Act.
If a project was to become subject to FERC’s ratemaking jurisdiction under the FPA as a result of loss of Qualifying Facility status and the power purchase agreement remains in effect, the FERC may determine that the rates currently set forth in the power purchase agreement are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that the project refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from the project, either of which would have an adverse effect on our revenues.
Moreover, the loss of the Qualifying Facility status of any of our projects selling energy to Southern California Edison could also permit Southern California Edison, pursuant to the terms of its power purchase agreement, to cease taking and paying for electricity from the relevant project and to seek refunds for past amounts paid. In addition, the loss of any such status would result in the occurrence of an event of default under the indenture for the bonds and hence would give rise to the ability of the indenture trustee to exercise remedies pursuant to the indenture and the other financing documents.
Our projects in California and Nevada, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The projects each sell or will sell their electrical output under power purchase agreements to electric utilities (Sierra Pacific Power Company, Nevada Power Company, Southern California Edison or Southern California Public Power Authority). All of the utilities except Southern California Public Power Authority are regulated by their respective state public utility commissions. Sierra Pacific Power Company and Nevada Power Company are regulated by the Public Utility Commission of Nevada. Southern California Edison and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission.
Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the Hawaii Public Utility Commission will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost, the cost it would otherwise incur if it produced the energy and capacity itself or purchased it from another source. Our project in Hawaii has a long term power purchase agreement with Hawaii Electric Light Company.
Foreign Regulation of the Electric Utility Industry
The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power project and should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.
Nicaragua. In 1998 two laws were approved by Nicaraguan authorities, Law No. 272-98 and Law No. 271-98, which define the structure of the new energy sector in the country. Law No. 272-98 provides for the establishment of a National Energy Commission, which we refer to as CNE, which is responsible for setting policies, strategies and objectives for such sector and approving indicative plans therefor. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the Nicaraguan Institute of Energy, which we refer to as INE.
In 2002, the National Congress enacted Law No. 443 to regulate the granting of exploration and exploitation concessions for geothermal fields. The INE adopted this law.
In 2007, Nicaragua passed a law amending Law No. 290, which governs the organization of the executive branch. Among other matters, the new law established a new ministry of energy and mining, which has assumed all of the functions and responsabilities of the National Energy Commission (CNE). The new ministry of energy and mining is responsible for administrating Law No. 443 described above, and is also responsible for granting concessions and permits relating to the exploration or exploitation of any energy source, as well as concessions and licensing for generation, transmission and distribution of energy.
The Nicaraguan energy sector has been restructured and partially privatized. Following such restructuring and privatization, the government has retained title and control of the transmission assets and has created the Empresa Estatal de Transmision (ENTRESA), which is in charge of the operation of the transmission system in the country and of the new wholesale market. As part of the recent restructuring of the energy sector, most of the distribution facilities previously owned by the Nicaraguan Electricity Company, the government-owned vertically-integrated monopoly, were transferred to two companies, Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), which in turn were privatized and acquired by an affiliate of Union Fenosa, a large Spanish utility. Following such privatization, the power purchase agreement for our Momotombo project was assigned by the Nicaraguan Electricity Company to DISNORTE and DISSUR. A subsidiary of the Nicaraguan Electricity Company, ENTRESA, owns the transmission grid. In addition, a National Dispatch Center was created to work with ENTRESA and provide for dispatch and wholesale market administration.
Guatemala. The General Electricity Law of 1996 created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the National Electric Energy Commission (CNEE) and a new wholesale power market administrator, the Administrator of the Wholesale Market, for the regulation and administration of such sector. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating the electricity law, overseeing the market and setting rates for transmission services and for electricity service to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Projects in order to promote the development of renewable energy projects in Guatemala. Such law provides certain benefits to companies utilizing renewable energy, including a 10-year corporate income tax; VAT and customs duty exemption and a 10-year business tax exemption.
Kenya. Kenya’s Electric Power Act of 1997 restructured the electricity sector in such country. Among other things, the Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. Kenya Power and Lighting Co. Ltd. (KPLC) is the only licensed public electricity supplier and has a monopoly in the transmission and distribution of electricity in the country. The Act permitted Independent Power Producers (IPPs) to install power generators and sell electricity to KPLC, which is owned by various private, and government entities and which currently purchases energy and capacity from two other IPPs in addition to our Olkaria III project. The Act also created the Electricity Regulation Board, as an independent regulator for the electricity sector. KPLC.’s retail electricity rates are subject to approval by the Electricity Regulation Board.
Philippines. The Philippine’s Electric Power Industry Reform Act of 2001 created the Energy Regulatory Commission, which is an independent quasi-judicial regulatory body mandated to promote competition, encourage market development, ensure customer choice and penalize abuse of market power in the restructured electricity industry. The Energy Regulatory Commission is responsible for the enforcement of the rules and regulations governing the operations of the electricity spot market once it is established and the activities of the spot market operator and other participants to ensure a greater supply and rational pricing of electricity. In addition, the Energy Regulatory Commission determines, fixes, and approves transmission and distribution wheeling charges and retail electricity rates for the captive market of a distribution utility through a methodology that it establishes and enforces. The Energy Regulatory Commission also monitors and takes measures to penalize abuse of market power and anti-competitive or discriminatory behavior by any electric power industry participant.
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 material fines or penalties; however, the Heber 1 and 2 projects received a notice from the California Division of Oil, Gas and Geothermal Resources that the pressure levels at some of the geothermal fluid injection wells were too high, and the California Regional Water Quality Control Board has notified the Heber 1 and 2 projects that recent tests have resulted in lower-than-required survival rates for bioassay toxicity tests conducted on the cooling tower blowdown water discharged under the NPDES (National Pollutant Discharge Elimination System) permit. In order to address the pressure levels at the Heber 1 and 2 projects, the Heber 1 and 2 projects proposed the construction and operation of a pipeline to carry geothermal injection fluid to other project injection wells, which proposal has been accepted as an appropriate solution to the pressure level by the California Division of Oil, Gas and Geothermal Resources. The pipeline was completed in the first quarter of 2005. With the cooperation of the California Regional Water Quality Control Board, Colorado River Basin Region, the Heber 1 and 2 projects are also conducting more frequent monitoring and bioassays, and conducting a Toxicity Identification Evaluation (TIE) study in an effort to determine the source of the apparent cooling tower blowdown water toxicity. If the source of the toxicity is not identified, or cannot easily be corrected, the Heber 1 and 2 projects may instead seek authority to inject the cooling tower blowdown water into the geothermal injection reservoir, as do other geothermal projects in the Imperial Valley.
Our Steamboat Hills Project was recently advised by the Washoe County Water Department that certain changes had been observed in the course of the County’s monitoring of well chemistry and was asked to explain why this was occurring. In the course of our investigation, we discovered that a liner in a geothermal fluid injection well failed, resulting in injection of the spent geothermal fluid at a higher depth than the designed and permitted depth for such injection. The County Water Department and the State have also indicated their concern that the injection well may be situated near a geological fault, which may also be causing the movement of injected fluid into a higher zone of the groundwater aquifer. We engaged an outside geothermal consultant to examine the situation and have since completed the well repair work. We do not believe that the injection well has had a material impact on the aquifer or that it is improperly placed. We have agreed with the State to conduct an expanded monitoring program and to continue to study the issue. If it should be determined that the injection well location is not acceptable, it may be necessary to drill a new injection well to manage the spent geothermal fluids.
As of the date of this annual report, all of the material permits and approvals currently required to operate our projects have been obtained and are currently valid, except for the fact that certain permits for some of the projects are held in the name of predecessor owners and except for those permits which must be transferred or reissued to the correct entity. We believe this will occur in the ordinary course and we have already filed some of these applications. In addition, we are required to obtain permits for both the construction and operational phases of our projects under construction or enhancement. As of the date of this annual report, we have obtained and are in compliance with most of the material permits and approvals currently required for our projects that are under construction or enhancement. There are some permits that need to be obtained in the future. We believe we will be able to obtain those permits and approvals without material delay and without incurring additional material costs.
Environmental Laws and Regulations
Geothermal operations can produce significant quantities of brine and scale, which builds up on metal surfaces in our equipment with which the brine comes into contact. These waste materials, most of which are currently reinjected into the subsurface, can contain various concentrations of hazardous materials, including arsenic, lead, and naturally occurring radioactive materials. We also use various substances, including isobutene, isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used and generated in connection with our equipment manufacturing operations in Israel. As a result, our projects are
subject to numerous domestic and foreign federal, state and local statutory and regulatory standards relating to the use, storage, fugitive emissions and disposal of hazardous substances. The cost of any remediation activities in connection with a spill or other release of such contaminants could be significant.
Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our projects, that has materially impaired any of the project sites, any disposal or release of these materials onto project sites, other than by means of permitted injection wells, could result in material cleanup requirements or other responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that the former facilities and any associated underground storage tanks would have already been encountered if they still existed.
ITEM 1A. RISK FACTORS
Because of the following factors, as well as other variables affecting our business, operating results or financial condition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.
Our financial performance depends on the successful operation of our geothermal power plants, which is subject to various operational risks.
Our financial performance depends on the successful operation of our subsidiaries’ geothermal power plants. In connection with such operations, we derived approximately 72.7% of our total revenues for the year ended December 31, 2006 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:
|•||regular and unexpected maintenance and replacement expenditures;|
|•||shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;|
|•||the presence of hazardous materials on our project sites;|
|•||catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe storms or similar occurrences affecting our projects or any of the power purchasers or other third parties providing services to our projects; and|
|•||the aging of power plants may reduce their availability and increase the cost of their maintenance.|
Any of these events could significantly increase the expenses incurred by our projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of our projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
As mentioned above, the aging of our power plants may reduce their availability and increase maintenance costs due to the need to repair or replace our equipment. For example, in 2006, we had to retube old heat exchanger pipes in our Mammoth complex. Such major maintenance activities impact both the capacity factor of the affected power plant and its operating costs.
Our exploration, development, and operation of geothermal energy resources is subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our projects.
Our business involves the exploration, development and operation of geothermal energy resources. These activities are subject to uncertainties, which vary among different geothermal reservoirs and are in some respects similar to those typically associated with oil and gas exploration, development and exploitation, such as dry holes, uncontrolled releases and pressure and temperature decline, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. Prior to our acquisition of the Steamboat Hills project, one of the wells related to the project experienced an uncontrolled release. In addition, the high temperature and high pressure in the Puna project’s geothermal energy resource requires special reservoir management and monitoring. Further, since the commencement of their operations, several of our projects have experienced geothermal resource cooling in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal projects depends on different factors directly related to the geothermal resource, such as the heat content (the relevant composition of temperature and pressure) of the geothermal reservoir, the useful life (commercially exploitable life) of the reservoir and operational factors relating to the extraction of geothermal fluids. Our geothermal energy projects may suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power projects.
Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures. In the case of the geothermal resource supplying the Heber 1 project and the Heber 2 project, which we refer to collectively as the ‘‘Heber projects’’, and the Gould project (a new power plant at the site of the Heber projects consisting of two Ormat Integrated Two Level Units (ITLU)), pressure drawdown in the center of the well field has caused some localized ground subsidence, while pressure in the peripheral areas has caused localized ground inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface. Potential costs, which cannot be estimated and may be significant, of failing to stabilize site pressures in the Heber and Gould projects’ area include repair and modification of gravity-based farm irrigation systems and municipal sewer piping and possible repair or replacement of a local road bridge spanning an irrigation canal.
Additionally, geothermally active areas, such as the areas in which our projects are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our projects or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the power purchase agreement for the affected project, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances.
Our business development activities may not be successful and our projects under construction may not commence operation as scheduled.
We are currently in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and power purchase agreements, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of construction. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable power purchase agreement, obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.
Currently, we have power plants under development or construction in the United States, Kenya, and China, and we intend to pursue the expansion of some of our existing plants and the development of other new plants. Our completion of these facilities is subject to substantial risks, including:
|•||unanticipated cost increases;|
|•||shortages and inconsistent qualities of equipment, material and labor;|
|•||inability to obtain permits and other regulatory matters;|
|•||failure by key contractors and vendors to timely and properly perform;|
|•||adverse environmental and geological conditions (including inclement weather conditions); and|
|•||our attention to other projects;|
Any one of which could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction or expansion.
We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.
Our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. As of December 31, 2006, we had approximately $512.2 million of total consolidated indebtedness (including indebtedness to our parent company in the amount of $140.2 million), of which approximately $370.0 million represented non-recourse debt and limited recourse debt held by our subsidiaries. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms.
Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic and capital market conditions, credit availability from banks, investor confidence, the continued success of current projects, the credit quality of the projects being financed, the political situation in the country where the project is located and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our projects on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments, parent company loans or the incurrence of additional debt by us.
Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects.
Our foreign projects expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions and policies of foreign governments, any of which risks may delay or reduce our ability to profit from such projects.
We have substantial operations outside of the United States that generated revenues in the amount of $95.4 million for the year ended December 31, 2006, which represented 35.5% of our total revenues for such twelve-month period. Our foreign operations are subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in the
United States, which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:
|•||changes in government policies or personnel;|
|•||changes in general economic conditions;|
|•||restrictions on currency transfer or convertibility;|
|•||changes in labor relations;|
|•||political instability and civil unrest;|
|•||changes in the local electricity market;|
|•||breach or repudiation of important contractual undertakings by governmental entities; and|
|•||expropriation and confiscation of assets and facilities.|
In particular, the Philippines is in the midst of an ongoing privatization of the electric industry, and in Guatemala the electricity sector was partially privatized, and it is currently unclear whether further privatization will occur in the future. Such developments may affect our existing Leyte and Zunil projects and the Amatitlan project (Leyte in the Philippines and Zunil and Amatitlan in Guatemala) currently under construction if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Nicaragua, Union Fenosa, one of the electric utilities, has been experiencing difficulties adjusting the tariffs charged to its customers, thus effecting Union Fenosa’s ability to pay for electricity its purchase from power generators. This may adversely affect our Momotombo project. In Kenya, the government is continuing to make an effort to deliver on campaign promises to reduce the price of electricity and is applying pressure on independent power producers, to lower their tariffs. In addition, Kenya’s government is considering a further restructuring and privatization of the electricity industry and may divide Kenya Power and Lighting Co. Ltd., the power purchaser for our Olkaria III project, into separate entities and then privatize one or more of such resulting entities. Any break-up and potential privatization of Kenya Power and Lighting Co. Ltd. may adversely affect our Olkaria III project. Although we generally obtain political risk insurance in connection with our foreign projects, such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the project lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances.
Our foreign projects and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects and operations.
Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign projects and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign projects and operations.
A significant portion of our net revenue is attributed to payments made by power purchasers under power purchase agreements. The failure of any such power purchaser to perform its obligations under
the relevant power purchase agreement or the loss of a power purchase agreement due to a default would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
A significant portion of our net revenue is attributed to revenues derived from power purchasers under the relevant power purchase agreements. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company have accounted for 30.0%, 15.1% and 12.8%, respectively, of our revenues for the year ended December 31, 2006. Neither we nor any of our affiliates make any representations as to the financial condition or creditworthiness of any purchaser under a power purchase agreement, and nothing in this annual report should be construed as such a representation.
There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their power purchase agreements. For example, as a result of the energy crisis in California, Southern California Edison withheld payments it owed under various of its power purchase agreements with a number of power generators (such as the Ormesa, Heber, and Mammoth projects) payable for certain energy delivered between November 2000 and March 2001 under such power purchase agreements until March 2002. If any of the power purchasers fails to meet its payment obligations under its power purchase agreements, it could materially and adversely affect our business, financial condition, future results and cash flow.
In connection with the power purchase agreements for the Ormesa project, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an Interim Agreement; whereby Southern California Edison will continue procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 cents/ kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations of the long-term power purchase agreement are still under way and there is no guarantee that it will be successfully completed.
Seasonal variations may cause significant fluctuations in our cash flows, which may cause the market price of our common stock to fall in certain periods.
Our results of operations are subject to seasonal variations. This is primarily because some of our domestic projects receive higher capacity payments under the relevant power purchase agreements during the summer months, and due to the generally higher short run avoided costs in effect during the summer months. Some of our other projects may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, future results and cash flow. If our operating results fall below the public’s or analysts’ expectations in some future period or periods, the market price of our common stock will likely fall in such period or periods.
Pursuant to the terms of some of our power purchase agreements with investor-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.
Under the Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake and Buffalo Valley power purchase agreements, we may be required to make payments to the relevant power purchaser in an amount equal to such purchaser’s replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the power purchase agreement and which such power purchaser is forced to obtain from an alternate source. One of the six power purchase agreements was in commercial operation in 2006 and to date the shortfall amount has not been material. Measured against our revenues from the sale of electricity for the year ended December 31, 2006 and assuming no other changes in our revenues, the revenues from such agreements constitute, collectively, less than 4% of our total revenues from the sale of electricity. In addition, we may be required to make payments to the relevant power purchaser in an amount equal
to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant power purchase agreement. We may be subject to certain penalties, and we may also be required to pay liquidated damages if certain minimum performance requirements are not met under certain of our power purchase agreements, all of which could materially and adversely affect our business, financial condition, future results and cash flow. With respect to certain of our power purchase agreements, we may also be required to pay liquidated damages to our power purchaser if the relevant project does not maintain availability of at least 85% during applicable peak periods. The maximum aggregate amount of such liquidated damages for the Steamboat 2 and Steamboat 3 power purchase agreements would be approximately $1.5 million for each project.
The short run avoided costs for our power purchasers may decline, which would reduce our project revenues and could materially and adversely affect our business, financial condition, future results and cash flow.
Under the power purchase agreements for our projects in California, the price that Southern California Edison pays for energy is based upon its short run avoided costs, which are the incremental costs that it would have incurred had it generated the relevant electrical energy itself or purchased such energy from others. Under settlement agreements between Southern California Edison and a number of power generators in California that are Qualifying Facilities, including our subsidiaries, the energy price component payable by Southern California Edison has been fixed through April 2007 and, recently, has been fixed again through April 2012, and thereafter will be based on Southern California Edison’s short run avoided costs, as determined by the California Public Utilities Commission. These short run avoided costs may vary substantially on a monthly basis, and are expected to be based primarily on natural gas prices for gas delivered to California as well as other factors. The levels of short run avoided cost prices paid by Southern California Edison may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison under our power purchase agreements and could materially and adversely affect our business, financial condition, future results and cash flow.
If any of our domestic projects loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.
Most of our domestic projects are Qualifying Facilities pursuant to the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, which largely exempts the projects from the Federal Power Act, which we refer to as FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.
PUHCA was repealed on February 8, 2006. If any of our domestic projects were to lose its Qualifying Facility status, such project could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.
In addition, pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of public utilities in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are largely exempt from the FPA. If a domestic project were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such project pursuant to its power purchase agreements would be subject to the review and approval of the FERC. The FERC, upon such review, may determine that the rates currently set forth in such power purchase agreements are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that some or all of our domestic projects refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic projects, either of which would have an adverse effect on our revenues. Even if a project does not lose its Qualifying Facility status, pursuant to a final rule
issued by FERC on February 2, 2006, if a project’s power purchase agreement is terminated or otherwise expires, that project will become subject to FERC’s ratemaking jurisdiction under the FPA.
Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreements, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.
Pursuant to the Energy Policy Act of 2005, the FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing power purchase agreements between a Qualifying Facility and a utility are not affected. The FERC recently issued a final rule, which could eliminate a utility’s mandatory purchase obligation from Qualifying Facilities in certain regions of the country. The regions do not include areas in which our domestic projects operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. In this rule, the FERC expressly noted that the California Independent System Operator (CAISO) has satisfied one but not all of the criteria for relief from the mandatory purchase obligation. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the project in the region under Federal law upon termination of the existing power purchase agreement or with respect to new projects, which could have an adverse effect on our revenues.
Our financial performance is significantly dependent on the successful operation of our projects, which is subject to changes in the legal and regulatory environment affecting our projects.
All of our projects are subject to extensive regulation and, therefore, changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our projects. The structure of federal and state energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. Our power purchasers or we may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim in our consolidated federal tax returns either an investment tax credit for approximately 10% of the cost of each new geothermal power plant or ‘‘production tax credits’’, which in 2006 was 1.9 cents per kWh and is adjusted annually for inflation, on the first ten years of electricity output. (Production tax credits can only be claimed on new plants put into service between October 23, 2004 and December 31, 2008.) We are also permitted to deduct most of the cost of the power plant as ‘‘depreciation’’ over five years on an accelerated basis. The fact that the deductions are accelerated means that more of the cost is deducted in the first few years than during the remainder of the depreciation period. In addition, we have the ability to transfer the value of these tax incentives when we are not in a position to use them directly. For instance, energy credits can be transferred through lease financing, and production tax credits may be transferred by bringing in another company who can use them as a partner in the project.
President Bush has made it a central theme of his second term to simplify the U.S. tax code. Among the options that may be under consideration are replacing or supplementing the corporate income tax with a value-added-tax, stripping away many tax subsidies, and eliminating taxes on interest, dividends and other returns to capital. Significant tax reform has the potential to have a material effect on our business, financial condition, future results and cash flow. It could reduce or eliminate the value that geothermal companies receive from the current tax subsidies. Any restrictions or tightening of the rules for lease or partnership transactions — whether or not part of major tax reform — could also materially affect our business, financial condition, future results and cash flow.
Any such changes could significantly increase the regulatory-related compliance and other expenses incurred by the projects and could significantly reduce or entirely eliminate the revenues generated by one or more of the projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation, which currently are significant, may increase in the future and could materially and adversely affect our business, financial condition, future results and cash flow; any non-compliance with such laws or regulations may result in the imposition of liabilities which could materially and adversely affect our business, financial condition, future results and cash flow.
Our projects are required to comply with numerous domestic and foreign federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for construction and/or operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the projects could be adversely affected or be subject to fines, penalties or additional costs. In addition, we may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development of the projects. As of the date of this report, we have not yet obtained certain permits and government approvals required for the completion and successful operation of projects under construction or enhancement. In addition, a nearby municipality has informed our Amatitlan project that an additional building permit should be obtained from such municipality before construction commences. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating projects under construction or enhancement and the Amatitlan project, could cause our operations to be limited or suspended. Environmental laws, ordinances and regulations affecting us can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us.
We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our projects.
Our projects are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use isobutane, isopentane, industrial lubricants and other substances at our projects which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the projects, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, in the United States, we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.
We believe that at one time there may have been a gas station located on the Mammoth project site, but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. There may be soil or groundwater contamination and related potential liabilities of which we are unaware related to this site, which may be significant and may adversely and materially affect our operations and revenues.
We may not be able to successfully integrate companies which we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:
|•||failure of the acquired companies to achieve the results we expect;|
|•||inability to retain key personnel of the acquired companies;|
|•||risks associated with unanticipated events or liabilities; and|
|•||the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.|
If any of our acquired companies suffers customer dissatisfaction or performance problems, the same could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or ‘‘spot’’ markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements will engage in ‘‘competitive bid’’ solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain power purchase agreements and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.
The existence of a prolonged force majeure event or a forced outage affecting a project could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks discussed elsewhere in these risk factors, including events such as fires, explosions, earthquakes, landslides, floods, severe storms or other similar events.
If a project experiences an occurrence resulting in a force majeure event, our subsidiary that owns that project would be excused from its obligations under the relevant power purchase agreement. However, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement. Additionally, to the extent that a forced outage has occurred, the relevant power purchaser may not be required to make any capacity and/or energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to
permanently reduce the contract capacity (and, correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the power purchase agreement. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period, and may incur significant liabilities in respect of past amounts required to be refunded. Accordingly, our business, financial condition, future results and cash flows could be materially and adversely affected.
The existence of a force majeure event or a forced outage affecting the transmission system of the Imperial Irrigation District could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
If the transmission system of the Imperial Irrigation District experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber 1 and 2 projects or the Ormesa project to the relevant power purchaser, the relevant power purchaser would not be required to make energy payments for such non-delivered electricity and may not be required to make any capacity payments with respect to the affected project so long as such force majeure event or forced outage continues. Our revenues for the year ended December 31, 2006, from the projects utilizing the Imperial Irrigation District transmission system, were approximately $80.7 million. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater revenue loss.
Some of our leases will terminate if we do not extract geothermal resources in ‘‘commercial quantities’’, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.
Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in ‘‘commercial quantities’’ or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in ‘‘commercial quantities’’. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable project is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection, all of which may not be possible or could result in increased cost to us, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our Bureau of Land Management leases may be terminated if we fail to comply with any of the provisions of the Geothermal Steam Act of 1970 or if we fail to comply with the terms or stipulations of such leases, which may materially and adversely affect our business and operations.
Pursuant to the terms of our Bureau of Land Management (which we refer to as BLM) leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally, certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act of 1970 or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.
Some of our leases (or subleases) could terminate if the lessor (or sublessor) under any such lease (or sublease) defaults on any debt secured by the relevant property, thus terminating our rights to access the underlying geothermal resources at that location.
The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the project located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.
In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.
Current and future urbanizing activities and related residential, commercial and industrial developments may encroach on or limit geothermal activities in the areas of our projects, thereby affecting our ability to utilize, access, inject and/or transport geothermal resources on or underneath the affected surface areas.
Current and future urbanizing activities and related residential, commercial and industrial development may encroach on or limit geothermal activities in the areas of our projects, thereby affecting our ability to utilize, access, inject and/or transport geothermal resources on or underneath the affected surface areas. In particular, the Heber projects and the Gould project rely on an area, which we refer to as the Heber Known Geothermal Resource Area or Heber KGRA, for the geothermal resource necessary to generate electricity at the Heber projects and Gould project. Imperial County has adopted a ‘‘specific plan area’’ that covers the Heber KGRA, which we refer to as the ‘‘Heber Specific Plan Area’’. The Heber Specific Plan Area allows commercial, residential, industrial and other employment oriented development in a mixed-use orientation, which currently includes geothermal uses. Several of the landowners from whom we hold geothermal leases have expressed an interest in developing their land for residential, commercial, industrial or other surface uses in accordance with the parameters of the Heber Specific Plan Area. Currently, Imperial County’s Heber Specific Plan Area is coordinated with the cities of El Centro and Calexio. There has been ongoing underlying interest since the early 1990s to incorporate the community of Heber. While any incorporation process would likely take several years, if Heber were to be incorporated, the City of Heber could replace Imperial County as the governing land use authority, which, depending on its policies, could have a significant effect on land use and availability of geothermal resources.
Current and future development proposals within Imperial County and the City of Calexico, applications for annexations to the City of Calexico, and plans to expand public infrastructure may affect surface areas within the Heber KGRA, thereby limiting our ability to utilize, access, inject and/or transport the geothermal resource on or underneath the affected surface area that is necessary for the operation of our Heber projects and Gould project, which could adversely affect our operations and reduce our revenues.
Current transportation construction works and urban developments in the vicinity of our Steamboat complex of projects in Nevada may also affect future permitting for geothermal operations relating to those projects. Such works and developments include the extension of an interstate highway (to be named U.S. 580) by the Nevada Department of Transportation, the construction of a new casino hotel and other commercial or industrial developments on land in the vicinity of our Steamboat projects.
We depend on key personnel for the success of our business.
Our success is largely dependent on the skills, experience and efforts of our senior management team and other key personnel. In particular, our success depends on the continued efforts of Lucien
Bronicki, Dita Bronicki, Hezy Ram, Nadav Amir, Yoram Bronicki and other key employees. The loss of the services of any key employee could materially harm our business, financial condition, future results and cash flow. Although to date we have been successful in retaining the services of senior management and have entered into employment agreements with Lucien Bronicki, Dita Bronicki, Hezy Ram and Yoram Bronicki, such members of our senior management may terminate their employment agreements without cause and with notice periods ranging from 90 to 180 days. We may also not be able to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available.
Our projects have generally been financed through a combination of parent company loans and limited− or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited−or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our projects.
Our projects have generally been financed using a combination of parent company loans and limited or non-recourse project finance debt or lease financing. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the project’s revenues and are secured by the project’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited−recourse project finance debt refers to our additional agreement, as part of the financing of a project, to provide limited financial support for the project subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other projects, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other projects) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the project would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.
Changes in costs and technology may significantly impact our business by making our power plants and products less competitive.
A basic premise of our business model is that generating baseload power at geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems, fuel cells, microturbines, windmills and photovoltaic (solar) cells. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants; however, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our projects may be significantly impaired.
Our expectations regarding the market potential for the development of recovered energy-based power generation may not materialize, and as a result we may not derive any significant revenues from this line of business.
We have identified recovered energy-based power generation as a significant market opportunity for us. Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future.
If this market does not materialize at the levels that we expect, such failure may materially and adversely affect our business, financial condition, future results and cash flow.
Our intellectual property rights may not be adequate to protect our business.
Our intellectual property rights may not be adequate to protect our business. While we occasionally file patent applications, patents may not be issued on the basis of such applications or, if patents are issued, they may not be sufficiently broad to protect our technology. In addition, any patents issued to us or for which we have use rights may be challenged, invalidated or circumvented.
In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.
Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties’ patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management’s attention from our core business.
We are subject to risks associated with a changing economic and political environment, which may adversely affect our financial stability or the financial stability of our counterparties.
The risk of terrorist attacks in the United States or elsewhere continues to remain a potential source of disruption to the nation’s economy and financial markets in general. The availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corp. and events related to the California electric market crisis. Additionally, the recent rise in fuel costs may make it more expensive for our customers to operate their businesses. These events could constrain the capital available to our industry and could adversely affect our financial stability and the financial stability of our transaction counterparties.
Possible fluctuations in the cost of construction, raw materials and drilling may materially and adversely affect our business, financial condition, future results and cash flow.
Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, and on the supply of various industrial equipment components that we use. We currently obtain all such materials and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. We have recently experienced increases in the cost of raw materials and in transportation costs. We have also experienced an increase in construction costs and an increase in drilling costs. To the extent not otherwise passed along to our customers, these and future cost increases of such raw materials and equipment could adversely affect our profit margins.
Conditions in Israel, where the majority of our senior management and all of our production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our projects.
Operations in Israel accounted for approximately 24.1%, 25.2% and 25.6% of our operating expenses in the year ended December 31, 2006, 2005 and 2004, respectively. Political, economic and security conditions in Israel directly affect our operations. Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel. Since October 2000, there has been a significant increase in violence, primarily in the West Bank and Gaza Strip. As a result, negotiations between Israel and representatives of the
Palestinian Authority have been sporadic and have failed to result in peace. We could be adversely affected by hostilities involving Israel, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results and cash flow.
Failure to comply with certain conditions and restrictions associated with tax benefits provided to Ormat Systems Ltd. by the Government of Israel as an ‘‘approved enterprise’’ may require us to refund such tax benefits and pay future taxes in Israel at higher rates.
Our subsidiary, Ormat Systems Ltd., which we refer to as Ormat Systems, has received ‘‘approved enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. As an approved enterprise, our subsidiary is exempt from Israeli income taxes with respect to revenues derived from the approved investment program for a period of two years commencing on the year it first generates profits from the approved investment program, and thereafter such revenues are subject to a reduced Israeli income tax rate of 25% for an additional five years. These benefits are subject to certain conditions set forth in the certificate of approval from Israel’s Investment Center, which include, among other things, a requirement that Ormat Systems comply with Israeli intellectual property law, that all transactions between Ormat Systems and our affiliates be at arms length, and that there will be no change in control of, on a cumulative basis, more than 49% of Ormat Systems’ capital stock (including by way of a public or private offering) without the prior written approval of the Investment Center. If Ormat Systems does not comply with these conditions, in whole or in part, it would be required to refund the amount of tax benefits (as adjusted by the Israeli consumer price index and for accrued interest) and would no longer benefit from the reduced Israeli tax rate, which could have an adverse effect on our financial condition, future results and cash flow. If Ormat Systems distributes dividends out of revenues derived during the tax exemption period from the approved investment program, it will be subject, in the year in which such dividend is paid, to Israeli income tax on the distributed dividend.
If our parent defaults on its lease agreement with the Israel Land Administration, or is involved in a bankruptcy or similar proceeding, our rights and remedies under certain agreements pursuant to which we acquired our products business and pursuant to which we sublease our land and manufacturing facilities from our parent may be adversely affected.
We acquired our business relating to the manufacture and sale of products for electricity generation and related services from our parent, Ormat Industries. In connection with that acquisition, we entered into a sublease with Ormat Industries for the lease of the land and facilities in Yavne, Israel where our manufacturing and production operations are conducted and where our Israeli offices are located. Under the terms of our parent’s lease agreement with the Israel Land Administration, any sublease for a period of more than five years may require the prior approval of the Israel Land Administration. As a result, the initial term of our sublease with Ormat Industries is for a period of four years and eleven months beginning on July 1, 2004, extendable to twenty-five years less one day (which includes the initial term). The consent of the Israel Land Administration was obtained for a period of the shorter of (i) 25 years or (ii) the remaining period of the underlying lease agreement with the Israel Land Administration, which terminates between 2018 and 2047. If our parent were to breach its obligations to the Israel Land Administration under its lease agreement, the Israel Land Administration could terminate the lease agreement and, consequently, our sublease would terminate as well.
As part of the acquisition described in the preceding paragraph, we also entered into a patent license agreement with Ormat Industries, pursuant to which we were granted an exclusive license for certain patents and trademarks relating to certain technologies that are used in our business. If a bankruptcy case were commenced by or against our parent, it is possible that performance of all or part of the agreements entered into in connection with such acquisition (including the lease of land and facilities described above) could be stayed by the bankruptcy court in Israel or rejected by a liquidator appointed pursuant to the Bankruptcy Ordinance in Israel and thus not be enforceable. Any of these events could have a material and adverse effect on our business, financial condition, future results and cash flow.
We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the projects they operate, most of which are subject to restrictions and taxation on dividends and distributions.
We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.
The agreements pursuant to which most of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our projects, such as the Mammoth project, there may be certain additional restrictions on dividend distributions pursuant to our agreements with our partners. Further, if we elect to receive distributions of earnings from our foreign operations, we may incur United States taxes on account of such distributions, net of any available foreign tax credits. In all of the foreign countries where our existing projects are located, dividend payments to us are also subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of revenues we can receive from our subsidiaries.
Some of our directors and executive officers who also hold positions with our parent may have conflicts of interest with respect to matters involving both companies.
Three of our seven directors are directors and/or officers of Ormat Industries, namely Lucien Bronicki, Dita Bronicki and Yoram Bronicki. In addition, four of our executive officers are also executive officers of Ormat Industries. Specifically, our Chairman, Director and Chief Technology Officer, Lucien Bronicki, is the Chairman of our parent; our Chief Executive Officer, President and Director, Dita Bronicki, is the Chief Executive Officer of our parent; our Chief Financial Officer, Joseph Tenne, is the Chief Financial Officer of our parent; and Etty Rosner our Vice President — Contract Administrator and Corporate Secretary is the Corporate Secretary of our parent. These directors and officers owe fiduciary duties to both companies and may have conflicts of interest on matters affecting both us and our parent, and in some circumstances may have interests adverse to our interests.
Our controlling stockholders may take actions that conflict with your interests.
Ormat Industries Ltd. holds approximately 64.0% of our common stock. Bronicki Investments Ltd. holds approximately 28.12% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 28, 2007 (27.50% on a fully diluted basis). Bronicki Investments Ltd. is a privately held Israeli company and is controlled by Lucien and Dita Bronicki. Because of these holdings, our parent company will be able to exercise control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions, and they will have significant control over our management and policies. The directors elected by these stockholders will be able to significantly influence decisions affecting our capital structure. This control may have the effect of delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in their best interest. For example, our controlling stockholders will be able to control the sale or other disposition of our products business to another entity or the transfer of such business outside of the State of Israel; as such action requires the affirmative vote of at least 75% of our outstanding shares.
The price of our common stock may fluctuate substantially and your investment may decline in value.
The market price of our common stock is likely to be highly volatile and may fluctuate substantially due to many factors, including:
|•||actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-based revenues;|
|•||variance in our financial performance from the expectations of market analysts;|
|•||conditions and trends in the end markets we serve and changes in the estimation of the size and growth rate of these markets;|
|•||announcements of significant contracts by us or our competitors;|
|•||changes in our pricing policies or the pricing policies of our competitors;|
|•||loss of one or more of our significant customers;|
|•||changes in market valuation or earnings of our competitors;|
|•||the trading volume of our common stock; and|
|•||general economic conditions.|
In addition, the stock market in general, and the New York Stock Exchange and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow.
Future sales of common stock by some of our existing stockholders could cause our stock price to decline.
As of the date of this report, our parent, Ormat Industries Ltd., holds approximately 64% of our outstanding common stock and some of our directors, officers and employees also hold shares of our outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline. On November 10, 2004, we entered into a registration rights agreement with Ormat Industries whereby Ormat Industries may require us to register our common stock held by it or its directors, officers and employees with the Securities and Exchange Commission or to include our common stock held by it or its directors, officers and employees in an offering and sale by us.
Provisions in our charter documents and Delaware law may delay or prevent acquisition of us, which could adversely affect the value of our common stock.
Our restated certificate of incorporation and our bylaws contain provisions that could make it harder for a third party to acquire us without the consent of our Board of Directors. These provisions do not permit actions by our stockholders by written consent. In addition, these provisions include procedural requirements relating to stockholder meetings and stockholder proposals that could make stockholder actions more difficult. Our Board of Directors is classified into three classes of directors serving staggered, three-year terms and may be removed only for cause. Any vacancy on the Board of Directors may be filled only by the vote of the majority of directors then in office. Our Board of Directors has the right to issue preferred stock without stockholder approval, which could be used to institute a ‘‘poison pill’’ that would work to dilute the stock ownership of a potential hostile acquirer,
effectively preventing acquisitions that have not been approved by our Board of Directors. Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders.
The Sarbanes-Oxley Act of 2002 imposes significant regulatory, corporate and operational requirements on the Company. Failure to comply with such provisions may have significant adverse consequences to the Company
As a public company, we are subject to the Sarbanes-Oxley Act of 2002 (the SOX Act). The SOX Act contains a variety of provisions affecting public companies, including but not limited to, corporate governance requirements, our relationship with our auditors, evaluation of our internal disclosure controls and procedures and evaluation of our internal control over financial reporting. See Management’s Report on Internal Control over Financial Reporting and Item 9A. — ‘‘Controls and Procedures’’.
ITEM 1B. UNRESOLVED STAFF COMMENTS
On December 29, 2006, we received a comment letter from the staff of the Division of Corporation Finance of the SEC, with respect to our annual report on Form 10-K for the year ended December 31, 2005. We responded to the staff’s comments in a letter dated January 29, 2007. We believe that we have resolved all of the staff’s comments, with the exception of one staff comment relating to the accounting treatment in the statement of cash flows and in the statement of operations of the lease and lease back transaction of the Puna project. . Our response to the staff included a detailed discussion of relevant accounting authority and our analysis undertaken in reaching a decision to so present and account for the Head Lease. On March 9, 2007, we received a follow up letter from the staff, asking us for an explanation of our lease out, lease in transactions and our analysis and the accounting authority for our conclusion regarding the accounting treatment of such transactions. As such, this comment remains unresolved. The Company believes that it has properly accounted for the Puna lease transaction in accordance with the provisions of SFAS No. 13, Accounting for Leases.
ITEM 2. PROPERTIES
We currently lease corporate offices at 6225 Neil Road, Reno, Nevada 89511-1136. We also occupy an approximately 66,000 square meter office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we sublease from Ormat Industries. See ‘‘Certain Relationships and Related Transactions’’. We also lease small offices in each of the countries in which we operate.
We believe that our current facilities are adequate for our operations as currently conducted. If additional facilities are required, we believe that we could obtain additional facilities at commercially reasonable prices.
Each of our projects is located on property leased or owned by us or one of our subsidiaries, or is a property that is subject to a concession agreement.
Information and descriptions of our plants and properties are included in Item 1, ‘‘Business’’, of this annual report.
ITEM 3. LEGAL PROCEEDINGS
There were no material developments in any legal proceedings to which the Company is a party during the fiscal year 2006, other than as described below.
As a result of our acquisition of the Steamboat 1 and 1A plants, our subsidiary Steamboat Geothermal LLC has become a party to litigation pending in the Second Judicial District Court in Washoe County, Nevada with Geothermal Development Associates and Delphi Securities, Inc. In April 2002, these plaintiffs initiated a lawsuit against the former owner and operator of the Steamboat
1/1A project. The plaintiffs dispute amounts owed to them pursuant to an agreement, dated July 14, 1985, pursuant to which Geothermal Development Associates assigned all of its right, title, and interest in the subject geothermal leasehold property in exchange for a net operating royalty interest in the revenues of the Steamboat 1 plant. The plaintiffs claim entitlement to damages based upon the following three allegations, which we deny: (i) that the actions of the former owner in developing the Steamboat 1A plant have decreased the output of the Steamboat 1 plant; (ii) that general, administrative, and corporate expenses included by the former owner in the calculation of the net royalty amount were overstated for the years 2000 and 2001; and (iii) that, in addition to its royalty interest in the revenues from the Steamboat 1 plant, plaintiffs are entitled to a net revenue royalty interest from the Steamboat 1A plant. The matter was originally set for a trial in September 2003, but the trial date was adjourned in order to allow the plaintiffs to obtain substitute counsel. Initial evidentiary disclosures and discovery requests had been made before the trial was adjourned. No dispositive motions are pending before the Court and the trial date has not been rescheduled. As of December 31, 2005 and January 9, 2006, Steamboat Geothermal LLC entered into a sales, settlement and release agreement and an assignment agreement, respectively, with Woodside Properties LLC, the assignee of 37% of Geothermal Development Associates’ right to net operating revenues, whereby Steamboat Geothermal LLC was assigned 37% of the net operating revenues of Steamboat 1 in partial settlement of the above mentioned dispute with Geothermal Development Associates and Delphi Securities, Inc. The plaintiffs also assert that, in addition to the amounts they claim are owed to them, they are entitled to interest on those amounts, as well as a reasonable net operating royalty payment from our Burdette project. We believe that such assertion is without merit, and that any outcome of such litigation or any settlement discussions will not have a material impact on our results of operations. On November 14, 2006, the parties agreed to dismiss plaintiff Delphi Securities, Inc. from the case with prejudice. The case is scheduled for mediation on April 10-11, 2007.
In connection with the power purchase agreements for the Ormesa project, Southern California Edison has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contends that California ISO real-time prices should apply, while management believes that SP-15 prices quoted by NYMEX should apply. According to Southern California Edison’s estimation, the amount under dispute is approximately $2.5 million. The parties have signed an interim agreement; whereby Southern California Edison will continue to procure the GEM 2 and GEM 3 power at the current energy rate of 5.37 cents/kWh until May 1, 2007. In addition, a long-term power purchase agreement is expected to be entered into for the GEM 2 and GEM 3 power. The negotiations in connection with the long-term power purchase agreement are still under way and there is no guarantee that such negotiations will be successfully completed. Management believes that such settlement agreement will not have a material financial impact on us.
One of our subsidiaries, Ormat Inc., is a party in a third-party complaint originally filed on November 15, 2005 by Lacy M. Henry and Judy B. Henry (the Henrys) in a bankruptcy proceeding in the United States Bankruptcy Court for the Eastern District of North Carolina. The Henrys are debtors in a Chapter 11 bankruptcy filed in the Bankruptcy Court. The Henrys were the sole shareholders of MPS Generation, Inc. (MPSG). We entered into a supply contract with MPSG dated as of December 29, 2003, under which we were retained as a subcontractor to produce four waste heat energy converters for a project for which MPSG had entered into a contract with Basin Electric Power Cooperative (Basin). Basin filed a lawsuit on February 24, 2005 against, among others, MPSG and the Henrys in the United States District Court for the District of North Dakota, alleging various causes of action including breach of contract, actual and constructive fraud, and conversion, and demanding the piercing of MPSG’s corporate veil to establish the personal liability of the Henrys for MPSG’s debts. On September 15, 2005, Basin filed a complaint commencing the bankruptcy adversary proceeding, seeking a determination that the claims which Basin alleged against the Henrys in the North Dakota lawsuit were not dischargeable. On November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against us, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against us for breach of contract/breach of warranty, tortious interference with contract, unfair
or deceptive trade practices and fraud. The Henrys alleged damages in excess of $100 million. On December 15, 2005, we filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. Our subsidiary filed a motion to dismiss the Henrys’ claims on January 31, 2006. On March 21, 2006, Basin filed an Amended Complaint in the bankruptcy proceeding, consolidating the causes of action it brought in the North Dakota lawsuit. In their answer to Basin’s Amended Complaint, the Henrys raised the same third party claims against our subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying our subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against our subsidiary pending the resolution of Basin’s alter ego claims against the Henrys. In its answer to Basin’s Amended Complaint, MPSG asserted third party claims against our subsidiary similar to those claims raised by the Henrys. We believe that we have no liability to the Henrys or to MPSG and intend to defend vigorously against the Henrys’ and MPSG’s claims in the bankruptcy proceeding. A trial on all issues raised in the bankruptcy proceeding is scheduled to begin in September 2007 in the Bankruptcy Court.
From time to time, we (including our subsidiaries) are a party to various other lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our (and their) business. These actions typically seek, among other things, compensation for alleged personal injury, breach of contract, property damage, punitive damages, civil penalties or other losses, or injunctive or declaratory relief. With respect to such lawsuits, claims and proceedings, we accrue reserves in accordance with U.S. generally accepted accounting principles. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results or cash flows.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the quarter ended December 31, 2006.
|ITEM 5.||MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES|
Our common stock is traded on the New York Stock Exchange under the symbol ‘‘ORA’’. Public trading of our stock commenced on November 11, 2004. Prior to that, there was no public market for our stock. The approximate number of holders of record of our common stock was 8 on February 28, 2007. On February 28, 2007, our stock’s closing price as reported on the New York Stock Exchange was $38.82 per share.
We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board of Directors will take into account our business plan and current and expected obligations, and no distribution will be made that in the judgment of our Board of Directors would prevent us from meeting such business plan or obligations.
Notwithstanding this policy, dividends will be paid only when, as and if approved by our Board of Directors out of funds legally available therefore. The actual amount and timing of dividend payments will depend upon our financial condition, results of operations, business prospects and such other matters as the board may deem relevant from time to time. Even if profits are available for the payment of dividends, the Board of Directors could determine that such profits should be retained for an extended period of time, used for working capital purposes, expansion or acquisition of businesses or any other appropriate purpose. As a holding company, we are dependent upon the earnings and cash flow of our subsidiaries in order to fund any dividend distributions and, as a result, we may not be able to pay dividends in accordance with our policy. Our Board of Directors may, from time to time, examine our dividend policy and may, in its absolute discretion, change such policy.
We have declared the following dividends over the past two years:
High/Low Stock Prices:
Ormat Technologies, Inc. (ORA) — High and Low Prices for the years 2005 and 2006, and from January 1 until February 28, 2007:
Stock Performance Graph:
The following performance graph represents the cumulative total shareholder return for the period November 11, 2004 (the date upon which trading of the Company’s common stock commenced) through December 31, 2006 for our common stock, as compared to the Standard and Poor’s Composite 500 Index, and a peer group.
|*||Independent Power Producer (IPP) Peers are The AES Corporation, NRG Energy Inc. and International Power PLC Renewable energy (Renewable) Peers are Acciona S.A., Evergreen Solar Inc. and Energy Conversion Devices Inc.|
The above Stock Performance Graph shall not be deemed to be soliciting material or to be filed with the SEC under the Securities Act and the Exchange Act except to the extent that the Company specifically requests that such information be treated as soliciting material or specifically incorporates it by reference into a filing under the Securities Act or the Exchange Act.
Equity Compensation Plan Information
For information on our equity compensation plan, refer to Item 12 ‘‘Security Ownership of Certain Beneficial Owners and Management’’.
Unregistered Sales of Equity Securities and Use of Proceeds from Registered Securities
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth our selected consolidated financial data for the years ended and at the dates indicated. We have derived the selected consolidated financial data for the years ended December 31, 2006, 2005 and 2004 and as of December 31, 2006 and 2005 from our audited consolidated financial statements set forth in Part II Item 8 of this annual report. We have derived the selected consolidated financial data for the years ended December 31, 2003 and 2002, and as of December 31, 2004, 2003 and 2002 from our audited consolidated financial statements not included herein.
The information set forth below should be read in conjunction with Item 7 — ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and our consolidated financial statements set forth in Part II Item 8 of this annual report.