ITEM 1. BUSINESS
Certain Definitions
Unless the context otherwise requires, all references in this annual report to "Ormat," "the Company," "we," "us," "our company", "Ormat Technologies" or "our" refer to Ormat Technologies, Inc. and its consolidated subsidiaries. The "Senior Secured Notes" refers to Ormat Funding Corp, one of our subsidiaries' 8¼% Senior Secured Notes due 2020 that were issued in February 2004.
Overview
We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal power plants, and we also design, develop and build, and plan to own and operate, recovered energy-based power plants, in each case using equipment that we design and manufacture. We conduct our business activities in two business segments: (i) Power Generation. We develop, build, own and operate geothermal power plants in the United States and other countries around the world and sell the electricity they generate. (ii) Products. In addition, 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.
All of the projects that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Therefore, electricity produced from geothermal energy sources contributes significantly less to local and regional incidences of acid rain, and global warming than energy produced by burning fossil fuels. Geothermal energy is also an attractive alternative to other sources of energy as part of a national diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.
In addition to our geothermal energy power generation business, we have developed and continue to develop products that produce electricity from recovered energy or so-called "waste heat." Recovered energy or waste heat represents residual heat that is generated as a by-product of gas turbine-driven compressor stations and in a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Such residual heat, that would otherwise be wasted, is captured in the recovery process and is used by recovered energy power plants to generate electricity without burning additional fuel and without emissions.
Company Contact and Sources of Information
We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the SEC's Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the Internet at that website.
Our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports 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, Insider Trading Policy, and amendments thereof 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 report or by calling us at (775) 356-9029.
Our Power Generation Business
We increased our net ownership interest in generating capacity by 162 MW between December 31, 2002 and December 31, 2004, of which 150 MW was attributable to our acquisition of geothermal power plants from third parties and 12 MW was attributable to increased generating capacity of our existing geothermal power plants resulting from plant technology upgrades and improvements to our geothermal reservoir operations. We own and operate or control and operate geothermal projects in the United States, Guatemala, Kenya, Nicaragua, and the Philippines and 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.
In 2004, revenues from our electricity segment were $158.8 million constituting approximately 72.4% of our total revenues in 2004. Revenues from the sale of electricity by our domestic projects were $134.6 million, constituting approximately 84.7% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign projects were $24.3 million, constituting approximately 15.3% of our total revenues from the sale of electricity.
The table below summarizes key information relating to our projects that are currently in operation, under construction and/or subject to enhancement.
(1) References to generating capacity refer to the net amount of electrical energy available for sale to the power purchaser, in the case of all of our existing domestic projects and the Momotombo and Olkaria III projects (two of our foreign projects), and to the generating capacity that is subject to the "take or pay" power purchase agreements in the case of the Leyte and Zunil projects (another two of our foreign projects). In the case of projects under construction and enhancement, references to generating capacity refer to the net amount of electrical energy that we expect will be available for sale to the relevant power purchasers. This column represents the net generating capacity of the project, not our net ownership in such generating capacity. Such net generating capacity is based on operational data for the 12-month period beginning January 1, 2004 through and including December 31, 2004.
(2) Includes the Steamboat 1/1A project and the Steamboat 2/3 project.
(3) We own and operate all of our projects, except the Momotombo project in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government, and the Mammoth project, Leyte project and Zunil project, in which we have a 50%, 80% and 21% ownership, respectively.
(4) The power purchase agreement for the Olkaria III project will expire in 2020 or, if Phase II of the project is constructed and completed, 20 years from the completion of such Phase II. Phase II of this project involves a proposed construction of additional facilities that we expect would add approximately 35 MW of generating capacity to this project.
(5) Projected fourth quarter of 2005.
(6) Incremental megawatts to the Steamboat complex.
(7) Projected.
(8) The power purchase agreement will expire 20 years from the January 1 immediately following the commercial operation date.
(9) The power purchase agreement will expire at the later of 20 years from the commencement of commercial operations or 23 years from the commencement of construction works.
(10) These projects are in their early engineering stage.
(11) We expect to sell an additional 8 MW under the existing power purchase agreement and another 10 MW under a new long-term power purchase agreement with a third party, currently under negotiation.
(12) We expect to sell an additional 5 MW under the existing power purchase agreement.
(13) We expect to sell an additional 10 MW. We are currently negotiating with a third party for the sale of this additional output pursuant to a new long-term power purchase agreement.
(14) The power purchase agreement will expire 25 years after its effective date.
(15) 2MW was completed in the first quarter of 2005, and we expect completion of an additional 16 MW in the last quarter of 2005.
(16)
This is a recovered energy project.
All of the revenues that we derive from the sale of electricity are pursuant to long-term power purchase agreements. In the United States, the power purchasers under such agreements are all investor-owned electric utilities. Approximately 79% of our total revenues in 2004 from the sale of electricity by our domestic projects were derived from power purchasers that currently have investment grade credit rating. The purchasers of electricity from our foreign projects are either state-owned entities or recently privatized state-owned entities. We have obtained political risk insurance from the Multilateral Investment Guarantee Agency of the World Bank Group ("MIGA") for all of our foreign projects (other than the Leyte project) in order to cover a portion of any loss that we may suffer upon the occurrence of certain political events covered by such insurance.
Development, Construction and Acquisition. We have experienced significant growth in recent years, principally through the acquisition of geothermal power plants from third parties and the expansion and enhancement of our existing projects. In February 2004, we acquired the Steamboat 2/3 project; in May 2004, we acquired the Steamboat Hills project and in June 2004, we acquired the Puna project. In total, we have increased our net ownership interest in generating capacity from 94 MW as of December 31, 2001 to 302 MW as of December 31, 2004. We currently expect to continue growing our power generation business through:
• the development and construction of new geothermal and recovered energy-based power plants;
• the expansion and enhancement of our existing projects; and
• the acquisition of additional geothermal and other renewable assets from third parties.
As part of these efforts, we regularly monitor requests for proposals from, and submit bids to, investor-owned and others electric utilities in the United States to provide additional generating capacity, primarily in the western United States where geothermal resources are generally concentrated. We also respond to international tenders issued by foreign state-owned electric utilities for the development, construction and operation of new geothermal power plants. In addition, we apply our technological expertise to upgrade the facilities of our existing geothermal power plants and to continuously monitor and manage our existing geothermal resources in order to increase the efficiency and generating capacity of such facilities.
We are currently in varying stages of development of new projects and construction and enhancement of new and existing projects. Based on our current development and construction schedule, which is subject to change at any time and which we may not achieve, we expect to have approximately 97-102 additional MW in generating capacity in the United States by the end of 2006 and approximately 20 additional MW in Guatemala by June 2006. In addition, we have obtained exclusive rights to develop the geothermal resources of a project in China, which, if implemented, is expected to produce approximately 50 MW in generating capacity. Agreements are in place with the Kenya Power & Lighting Co. Ltd. regarding, among other things, (i) the construction of Phase II of the Olkaria III project in Kenya, (ii) Kenya Power & Lighting Co. Ltd.'s provision of certain collateral, and (iii) its efforts to strengthen government support for Olkaria III project. The request for strengthened government support has not been accepted to date by the Kenyan government. Upon implementation, we expect Phase II to add approximately 35 MW in generating capacity to the current Olkaria III project. In preparation for the release of Phase II, we have recently asked Kenya Power & Lighting Co. Ltd. to provide the necessary collateral. We must notify Kenya Power & Lighting Co. Ltd., by April 17, 2005, whether we will proceed to construct Phase II of the Olkaria III project and, if we notify Kenya Power & Lighting Co. Ltd. that we will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to provide such notification we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement.
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 OECs. Our customers include contractors and geothermal plant owners and operators. We recently sold two of our OEC units, with a total gross output of approximately 18 MW, to the Instituto Costarricense de Electricidad in Costa Rica, which is developing the Miravalles V geothermal power project in that country, and we sold one of our OEC units with total gross output of approximately 2 MW for installation at Oserian Farm in Kenya, where farmers grow flowers for export.
Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy or so-called "waste heat" that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We have installed one of our recovered energy-based generation units at Enterprise Product's Neptune gas processing plant in Louisiana.
Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme climate conditions, whether hot or cold. Our customers include contractors installing gas pipelines in remote areas. In addition, we design, manufacture and sell generators for various other uses, including heavy duty direct current generators. Our remote power units were recently installed on a Pemex pipeline in Mexico.
Engineering, Procurement and Construction ("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 Mokai and Wairakei geothermal power plants in New Zealand.
Operation and Maintenance of Power Plants. We provide operation and maintenance services for geothermal power plants.
In 2004, our revenues from our products business were $60.4 million, constituting approximately 27.6% of our total revenues.
History
We were formed by Ormat Industries Ltd. (also referred to in this annual report as the "Parent", "Ormat Industries", "the parent company" or "our parent") in 1994 in the state of Delaware for the purpose of investing and holding ownership interests in power projects, as well as constructing and operating power plants owned by us and by third parties. Ormat Industries, which is based in Israel, is an international power systems company whose predecessor, Ormat Turbines Ltd., was founded in 1965 by Lucien and Yehudit Bronicki for the principal purpose of developing equipment for the production of clean, renewable 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, and had, as of July 1, 2004, 677 employees. Ormat Industries owns 77.2% of our outstanding common stock.
Industry Background
Geothermal Energy
All of our projects produce 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 wellfield is properly operated. Geothermal energy projects typically have higher capital costs (primarily as a result of the costs attributable to wellfield development) but tend to have significantly lower variable operating costs, principally consisting of maintenance expenditures, than fossil fuel-fired power plants that require ongoing fuel expenses.
Geothermal Power Plant Technologies
Geothermal power plants generally employ either binary systems or conventional flash systems. In our projects, we also employ our proprietary technology of combined geothermal cycle systems. See "Our Technology."
Binary System
In a plant using a binary system, geothermal fluid, either hot water (also called brine) or steam or both, is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to a heat exchanger, which heats a secondary working fluid which has a low boiling point. This is typically an organic fluid, such as isopentane or isobutene, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser which may be cooled by air or by water from a cooling tower. The condensed fluid is then recycled back to the heat exchanger, closing the cycle within the sealed system. The cooled geothermal fluid is then reinjected back into the reservoir. The binary technology is depicted in the graphic below.
Flash Design System
In a plant using flash design, geothermal fluid is extracted from the underground reservoir and flows from the wellhead through a gathering system of insulated steel pipelines to flash tanks and/or separators. There, the steam is separated from the brine and is sent to a demister in the plant, where any remaining water droplets are removed. This produces a stream of dry steam, which drives a turbine generator to produce electricity. In some cases, the brine at the outlet of the separator is flashed a second time (dual flash), providing additional steam at lower pressure used in the low pressure section steam turbine to produce additional electricity. Steam exhausted from the steam turbine is condensed in a surface or direct contact condenser cooled by cold water from a cooling tower. The non-condensable gases (such as carbon dioxide) are removed through the removal system in order to optimize the performance of the steam turbines. The condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected back into the geothermal resource through a series of injection wells. The flash technology is depicted in the graphic below.
In some instances, the wells directly produce dry steam (the flashing occurring under ground). In such cases, the steam is fed directly to the steam turbine and the rest of the system is similar to the flash power plant described above.
Market Opportunity
The geothermal energy industry in the United States experienced significant growth in the 1970s and 1980s, followed by a period of consolidation of owners and operators of geothermal assets in the 1990s. The industry, once dominated by large oil companies and investor-owned electric utilities, now includes several independent power producers. During the 1990s, growth and development in the geothermal energy industry occurred primarily in foreign markets, and only minimal growth and development occurred in the United States. Since 2001, there has been renewed interest in geothermal energy in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation, due to the increasing cost of natural gas, and as legislative and regulatory incentives, such as state renewable portfolio standards, have become more prevalent.
Electricity generation from geothermal resources in the United States currently constitutes a $1.5 billion-a-year industry (in terms of revenues) and accounts for 19% of all non-hydropower renewable energy-based electricity generation in the United States. Although electricity generation from geothermal resources is currently concentrated in California, Nevada, Hawaii and Utah, there are opportunities for development in other states such as Alaska, Arizona, Idaho, New Mexico and Oregon due to the availability of geothermal resources and, in some cases, a favorable regulatory environment in such states.
A 2004 forecast of the U.S. Department of Energy projects the addition of geothermal installations with generating capacity totaling 6,840 MW by 2025, based on the assumption that natural gas prices will remain relatively stable at current levels. This forecast is based on existing, known geothermal resources and does not take into account any positive effects on generating capacity resulting from new technology, such as enhanced utilization of existing geothermal bases and engineered geothermal systems (according to the Energy Information Administration, Annual Energy Outlook 2004).
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, Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, Minnesota, Nevada, New Jersey, New Mexico, New York, Pennsylvania, Rhode Island,
Texas, 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. Eleven of these eighteen states (including California, Nevada and Hawaii, where we have been the most active in our geothermal energy development and in which all of our U.S. projects are located) define geothermal resources as "renewables". Illinois, Kansas and Vermont are debating whether to adopt a renewable portfolio standard.
We believe that these legislative measures and initiatives present a significant market opportunity for us. For example, California generally requires that each investor-owned electric utility company operating within the state increase the amount of renewable generation in its resource mix by 1% per year so that 20% of its retail sales are procured from eligible renewable energy sources by 2017. Presently, approximately 10% of the electricity generated in California is derived from renewable resources (not counting hydroelectricity as renewable power). Nevada's renewable portfolio standard requires each Nevada electric utility to obtain 5% of its annual energy requirements from renewable energy sources in 2004, which requirement increases to 7% in 2005 and thereafter increases by 2% every two years until 2013, when 15% of such annual energy requirements must be provided from renewable energy sources. Hawaii's renewable portfolio standard requires each Hawaiian electric utility to obtain 8% of its net electricity sales from renewable energy sources by December 31, 2005, 10% by December 31, 2010 and 20% by December 31, 2020.
In addition, in some states an entity generating electricity from renewable resources, such as geothermal energy, is awarded Renewable Energy Credits (which we refer to as RECs) that can be sold for cash. RECs have been sold for a wide range of prices during the past year, but because the markets for these RECs still remain limited, the prices have been volatile, and vary greatly from state to state. On October 14, 2004, we entered into agreements with Sierra Pacific Power Company, a utility company in the state of Nevada, to sell RECs resulting from electricity we generate for station use at our Desert Peak, Brady, Steamboat Hills and Steamboat 2/3 projects. The price for such RECs under such agreements is $0.005 per kWh, subject to a reduction to $0.0045 per kWh if we generate less than 80% or more than 120% of a baseline amount. On February 23, 2005 these agreements were approved by the Public Utility Commission ("PUC").
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. We are also permitted to deduct up to 95% of the cost of the power plant over five years on an accelerated basis, which results in more of the cost being deducted in the first few years than during the remainder of the depreciation period. These two tax benefits collectively offset approximately one-third of the capital cost of each new project. Any unused investment tax credit has a 3-year carry back and a 15-year carry forward.
Under Section 710 of the American Jobs Creation Act of 2004 that was signed into law on October 22, 2004, geothermal power companies are allowed to claim a "production tax credit" of 1.8 cents per kWh on electricity produced from geothermal resources. According to this law, credit can be claimed on such electricity sold during the first five years after a project achieves commercial operation. Projects put into service from October 22, 2004 through December 31, 2005 qualify for such production tax credit. The owner of the project must choose between this production tax credit and the 10% investment tax credit described above. Any unused production tax credit has a 1-year carry back and a 20-year carry forward.
The Kyoto Protocol entered into force on February 16, 2005, making the emission targets undertaken for the 2008-2012 period by more than 30 developed countries, including the EU members, Russia, Japan, Canada, New Zealand, Norway and Switzerland, legally binding. We expect that the effect of the Kyoto treaty will be to encourage renewable energy installation outside of the United States, as the United States has not ratified the Kyoto treaty.
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 developing a project, has in place a five-year Plan for New and Renewable Energy Commercialization Development. The plan's goals include increasing production of geothermal energy as well as providing electricity in remote areas. Several Latin American countries have rural electrification programs and renewable energy programs. For example, Nicaragua, where we operate the Momotombo project, is currently developing a national rural electrification plan with the support of the World Bank. One of the plan's primary goals is the reduction of market barriers to renewable energy technologies useful for remote areas not connected to the main electricity grid. Nicaragua also has a national master plan for geothermal energy, which is intended to facilitate the awarding of concessions for geothermal exploration and development in the country. Guatemala, another country in which we have ongoing operations (the Zunil project) and development activities (the Amatitlan project), recently approved a law which creates incentives for power generation from renewable energy sources by, among other things, providing economic and fiscal incentives such as exemptions from taxes on the importation of relevant equipment and various tax exemptions for companies implementing renewable energy projects. We believe that these developments and governmental plans will create opportunities for us to acquire and develop geothermal power generation facilities internationally as well as create additional opportunities for us to sell our remote power units and other products.
In addition to our geothermal power generation activities, we have also identified recovered energy power generation as a significant market opportunity for us in the United States and internationally. We are initially targeting the North American market, where we expect that recovered energy-based power generation will be derived principally from compressor stations along interstate pipelines, from midstream gas processing facilities, and from processing industries in general. Several states, as well as the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Nevada and Hawaii allow electric utilities to include recovered energy-based power generation in calculating their compliance with the state's renewable portfolio standards. In addition, North Dakota, South Dakota and the Department of Agriculture (through the Rural Utilities Service) have approved recovered energy-based power generation units as renewable energy resources, which qualifies recovered energy-based power generators (whether in those two states or elsewhere in the United States) for federally funded, low interest loans. We believe that the European market has similar potential and we expect to leverage our early success in North America in order to expand into Europe and other markets worldwide. In North America alone, we estimate the potential total market for recovered energy-based generation to be approximately 1,000 MW.
Competitive Strengths
Competitive Assets. Our assets are competitive for the following reasons:
• Contracted Generation. All of the electricity generated by our geothermal power plants is currently sold pursuant to long-term power purchase agreements, providing generally predictable cash flows.
• Baseload Generation. All of our geothermal power plants supply a part of the baseload capacity of the electric system in their respective markets, meaning that they operate to serve all or a part of the minimum power requirements of the electric system in such market on an around-the-clock basis. Because our projects supply a part of the baseload needs of the respective electric system and are only marginally weather dependent, we have a competitive advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent dependent on 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. All of our existing projects produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable energy source. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Such clean and renewable characteristics of geothermal energy give us a competitive advantage over fossil fuel-based electricity generation as countries increasingly seek to balance environmental concerns with demands for reliable sources of electricity.
High Efficiency from Vertical Integration. Unlike any of our competitors in the geothermal industry, we are a fully-integrated geothermal equipment, services and power provider. We design, develop and manufacture most of the equipment we use in our geothermal power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our projects efficiently and to respond to operational issues in a timely and cost-efficient manner. Moreover, given the efficient communications among our subsidiary that designs and manufactures the products we use in our operations and our subsidiaries that own and operate our projects, we are able to quickly and cost effectively identify and repair mechanical issues and to have technical assistance and replacement parts available to us as and when needed.
Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector. Key members of our senior management team have worked in the power industry for most of their careers and average over 20 years of industry experience.
Technological Innovation. We own or have rights to use more than 70 patents relating to various processes and renewable resource technologies. All of our patents are internally developed and therefore costs related thereto are expensed as incurred. Our ability to draw upon internal resources from various disciplines related to the geothermal power sector, such as geological expertise relating to reservoir management, and equipment engineering relating to power units, allows us to be innovative in creating new technologies and technological solutions.
No Exposure to Fuel Price Risk. A geothermal power plant does not need to purchase fuel (such as coal, natural gas, or fuel oil) in order to generate electricity. Thus, once the geothermal reservoir has been identified and estimated to be sufficient for use in a geothermal power plant and the drilling of wells is complete, the plant is not exposed to fuel price or fuel delivery risk.
Business Strategy
Our strategy is to continue building a geographically balanced portfolio of geothermal and recovered energy assets, and to continue to be a leading manufacturer and provider of products and services related to renewable energy. We intend to implement this strategy through:
• Development and Construction of New Projects - continuously seeking out commercially exploitable geothermal resources and developing and constructing new geothermal and recovered energy-based power projects in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development and which meet our investment criteria;
• Increasing Output from Our Existing Projects - increasing output from our existing geothermal power projects by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery;
• Acquisition of New Assets - acquiring from third parties additional geothermal and other renewable assets that meet our investment criteria;
• Technological Expertise - investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities;
• Developing Recovered Energy Projects - establishing a first-to-market leadership position in recovered energy projects in North America and building on that experience to expand into other markets worldwide; and
• Long-term Contracts - entering into long-term contracts with energy purchasers that will provide stable cash flows.
Operations of our Power Generation Segment
How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the acquisition) of the relevant plant. If we do not own all of the interest in a power plant, we enter into a shareholders agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with our project. Our ability to transfer or sell our interest in certain projects may be restricted by certain purchase options or rights of first refusal in favor of our project partners or the project's power purchasers and/or certain change of control and assignment restrictions in the underlying project and financing documents. All of our domestic projects, with the exception of the Puna project, which is an Exempt Wholesale Generator ("EWG"), are Qualifying Facilities under the Public Utility Regulatory Policy Act of 1978 ("PURPA") and are eligible for regulatory exemptions from most provisions of the Federal Power Act ("FPA"), certain state laws and regulations, and the Public Utility Holding Company Act ("PUHCA") as set forth in 18 C.F.R. Section 292, Subpart F. As an EWG, the Puna project is exempt from regulation under PUHCA, and does not cause us to be regulated as a holding company under PUHCA. The Puna project is not subject to the FPA.
How We Obtain Development Sites and Geothermal Resources. For domestic projects, we either lease or own the sites on which our power plants are located. In our foreign projects, our lease rights for the plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases) or a concession or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land. A geothermal resource lease (or sublease) or a concession or other agreement will usually give us the right to explore, develop, operate and maintain the geothermal field including, among other things, the right to drill wells (and if there are existing wells in the area, to alter them) and build pipelines for transmitting geothermal fluid. At times, the holder of rights in the geothermal resource is a governmental entity and at times a private entity. Usually, the terms of the lease (or sublease) and concession agreement correspond to the terms of the relevant power purchase agreement. In certain other cases, we own the land where the geothermal resource is located, in which case there are no restrictions on its utilization.
How We Sell Electricity. In the United States, the purchasers of power from our projects are investor-owned electric utility companies. Outside of the United States, the purchaser is typically a
state-owned utility or distribution company or a recently privatized state-owned entity and we typically operate our facilities pursuant to rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically called power purchase agreements) for the sale of electricity or the conversion of geothermal resources into electricity. A project's revenues under a power purchase agreement usually consist of two payments, energy payments and capacity payments. Energy payments are normally based on a project's electrical output actually delivered to the purchaser measured in kilowatt hours, with payment rates either fixed or indexed to the power purchaser's "avoided" costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties, such as us). Capacity payments are normally calculated based on the generating capacity or the declared capacity of a project available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of our domestic projects located in California are eligible for capacity bonus payments under the respective power purchase agreements upon reaching certain levels of generation.
How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective projects; however, each project draws upon our available collective resources and experience and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup and other operational functions are pooled within each project complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our project availability goals.
We currently operate and maintain approximately 343 MW of generating capacity. Since our recent acquisitions in California and Nevada, as a result of our vertical integration, our proprietary technology and our operational and maintenance expertise, we have been successful in increasing the efficiency and performance of most of our acquired facilities and have been able to use the staff required to operate these facilities more efficiently. For example, we have been able to increase the output of the Brady project by approximately 50% since the date of its acquisition.
Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our projects can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents at our projects.
How We Finance Our Power Plants. Historically, we have funded our projects with a combination of non-recourse or limited recourse debt, parent company loans and internally generated cash. Such leveraged financing permits the development of projects with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular project's ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the financing documents.
Non-recourse debt refers to debt that is repaid solely from the project's revenues (rather than our revenues or revenues of any other project) and generally is secured by the project's physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in that project affiliate. This type of financing is referred to as "project financing." Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other
conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service.
In the event of a foreclosure after a default, our project affiliate owning the project would only retain an interest in the assets, if any, remaining after all debts and obligations were paid in full. In addition, incurrence of debt by a project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge in favor of the project's lenders securing the project's debt and to transfer and change of control restrictions set forth in the relevant financing agreements.
Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for the project affiliate in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular project, distributions received by us from other projects and other sources of cash available to us may be required to be used to satisfy these obligations. To the extent of these limited recourse obligations, creditors of a project financing of a particular project may have direct recourse to us.
How We Mitigate International Political Risk. We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. The policies are issued by entities which specialize in such policies, such as 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%-90% of our revenue loss derived from a specified governmental act such as confiscation, expropriation, riots, the inability to convert local currency into hard currency and, in certain cases, the breach of agreements. We have obtained such insurance for all of our foreign projects in operation except for the Leyte project.
Recent Developments
On December 9, 2004 we received a purchase order in the amount of approximately $16.9 million to supply 102 remote power units for Communications and Cathodic Protection along a pipeline on the Sakhalin Island in the Russian Federation. Delivery of the units is expected to take place between August 2005 and March 2006, with revenue expected to be realized during this time.
On January 4, 2005, through a newly established project subsidiary, we entered into a 25-year Power Purchase Agreement (PPA) with Basin Electric Power Corporation according to which we will supply approximately 22 MW from recovered energy generation power plants. The power plants are to be constructed between 15 and 18 months from the effectiveness of the PPA. The power plants will be constructed on gas compressor stations along a Natural Gas pipeline in North and South Dakota. The PPA has not yet become effective and is subject to certain conditions.
On February 13, 2004, $190 million in aggregate principal amount of the Senior Secured Notes was issued in a capital markets offering subject to Rule 144A and Regulations of the Securities Act, as amended. On March 16, 2005, our subsidiary, Ormat Funding Corp. ("Ormat Funding"), completed an offering to exchange $1,000 principal amount of its Senior Secured Notes that were registered under the Securities Act of 1933, as amended, for each $1,000 principal amount of its outstanding Senior Secured Notes. Currently, the aggregate principal amount of the Senior Secured Notes outstanding is $189,488,618.
On February 14, 2005 two of our subsidiaries entered into Supply and Engineering Procurement contracts for a new geothermal power plant to be constructed on Sao Miguel Island in the Azores. The contracts are for a total of approximately €19.2 million (approximately US$25 million). Construction on the power plant is expected to be completed within 19 months from the contract date.
As a result of our recent acquisitions, our results of operations for the various periods covered by our consolidated financial statements attached hereto may not be comparable with each other or indicative of future results.
Description of Our Projects
In 2004, revenues from the sale of electricity by our domestic projects were $134.6 million, constituting 84.7% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign projects were $24.3 million, constituting 15.3% of our total revenues from the sale of electricity.
The financing of certain of our projects and the terms of our power purchase agreements and certain other agreements related to our operations are further described in the "Description of Certain Material Agreements" section.
Domestic Projects
Our projects in operation in the United States have a generating capacity of approximately 229 MW. All of our current domestic projects are located in California, Nevada and Hawaii. We also have projects under construction or enhancement in California, Nevada and Hawaii.
The Ormesa Project
The Ormesa project is located in East Mesa, Imperial County, California. The Ormesa project consists of six plants, OG I, OG IE, OG IH (collectively, the OG I plants), OG II, GEM 2 and GEM 3. The various OG I plants commenced commercial operations between 1987 and 1989, and the OG II plant commenced commercial operations in 1988. The GEM 2 and GEM 3 plants commenced commercial operations in April 1989. The OG plants utilize a binary system, and the GEM plants utilize a flash system. The OG I plants have a gross generating capacity of 41 MW; the OG II plant has a gross generating capacity of 19 MW; and the GEM 2 and GEM 3 plants have a gross generating capacity of 34 MW. However, electricity generated by the GEM 2 and GEM 3 plants is not sold under a power purchase agreement because their power is used to provide auxiliary power for wellfield operations at the Ormesa project. The Ormesa project sells its electrical output to Southern California Edison Company under two separate power purchase agreements. In certain circumstances, Southern California Edison Company or its designee has a right of first refusal to acquire the OG I and OG II plants. The Ormesa project was acquired by us in April 2002, was initially re-financed with project finance debt from United Capital and was re-financed again with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The 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 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 Senior Secured Notes.
In connection with the power purchase agreements for the Ormesa project, Southern California Edison Company has expressed its intent not to pay the contract rate for the power supplied under the Ormesa power purchase agreement as a result of the supply by the GEM 2 and GEM 3 plants to the Ormesa project of auxiliary power. We expect to resolve the issue through the sale of the GEM 2 and 3 power that was used to supply auxiliary power to Ormesa to a different offtaker; and we are currently negotiating with a third party the sale of some of the power (10 MW) pursuant to a long-term power purchase agreement.
The Heber Projects
The Heber 1 Project. The Heber 1 project is located in Heber, Imperial County, California. The Heber 1 project includes one power plant, which commenced commercial operations in 1985, and a
geothermal resources field. The plant utilizes a dual flash system and has a generating capacity of 38 MW. The Heber 1 project sells its electrical output to Southern California Edison Company under a power purchase agreement. In certain circumstances, Southern California Edison Company and its affiliated entities have a right of first refusal to acquire the power plant. Upon satisfaction of certain conditions specified in the power purchase agreement and subject to receipt of requisite approvals and negotiations between the parties, our project subsidiary will have the right to demand that Southern California Edison Company purchase the power plant. The Heber 1 project was acquired, and was financed with equity and non-recourse debt from Beal Bank, in December 2003.
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 34 MW. The Heber 2 project sells its electrical output to Southern California Edison Company under a power purchase agreement. The Heber 2 project was acquired in, and was financed with equity and non-recourse debt from Beal Bank, in December 2003.
We are currently negotiating with a third party the sale of an additional 10 MW from the Heber complex under a long-term power purchase agreement.
The Steamboat Projects
The Steamboat 1/1A Project. The Steamboat 1/1A project is located in Steamboat Hills, Washoe County, Nevada. The Steamboat 1/1A project includes two power plants which commenced commercial operations in 1986 and 1988, respectively. The Steamboat 1/1A project utilizes a binary system and has a gross generating capacity of 10 MW. The Steamboat 1/1A project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 1/1A project was acquired in June 2003 using internally generated cash, and was re-financed with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The 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 Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.
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 gross generating capacity of 29 MW. The Steamboat 2/3 project sells its electrical output to Sierra Pacific Power Company under two separate power purchase agreements. The Steamboat 2/3 project was acquired in February 2004 using internally generated cash and proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The 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 Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes. A dispute over the purchase price adjustment for an immaterial amount is currently the subject of litigation.
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 additional drilling and certain other capital expenditures to take full advantage of the power purchase agreement. The Steamboat Hills project was acquired in May 2004 using internally generated cash.
The Mammoth Project
The Mammoth project is located in Mammoth Lakes, California. The Mammoth project is comprised of three plants, G-1, G-2 and G-3. The G-1 plant commenced commercial operations in 1985 and the G-2 and G-3 plants commenced commercial operations in 1990. The Mammoth project utilizes a binary system and has a gross generating capacity of 35 MW. Our project subsidiary, OrMammoth, Inc., owns a 50% partnership interest in Mammoth-Pacific, L.P., which owns 100% of the Mammoth project. The other 50% partnership interest is owned by an unrelated third party. The Mammoth project sells its electrical output to Southern California Edison Company under three separate power purchase agreements. Under the G-1 power purchase agreement, in certain circumstances, Southern California Edison Company or its affiliates has a right of first refusal to acquire the plant. Our 50% ownership interest in the Mammoth project was acquired in December 2003 using internally generated cash and project finance debt from Beal Bank, and was re-financed with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The 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 Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.
The Brady Project
The Brady project is located in Churchill County, Nevada and includes the Brady plant and the Desert Peak 1 plant. The Desert Peak 1 plant is approximately 4.5 miles southeast of the Brady plant. The Brady plant commenced commercial operations in 1992 and the Desert Peak 1 plant commenced commercial operations in 1985. The Brady project has a gross generating capacity of 32 MW and has in the past utilized a dual flash design. In August 2002, an additional 6 MW binary unit was added to the Brady plant to generate additional power from the brine before its reinjection. The Desert Peak 1 plant utilizes a dual flash design. The Brady project sells its electrical output from the Brady plant and Desert Peak 1 plant to Sierra Pacific Power Company under a power purchase agreement. Our project subsidiary is currently evaluating the replacement of the Desert Peak 1 plant with a new plant that would be more efficient. The new plant may be constructed on the same site as the existing Desert Peak 1 plant. Construction is anticipated to be completed in 2007, at an estimated total project cost of approximately $8 million. The Brady project was acquired in June 2001 using internally generated cash and was re-financed with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The 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 Senior Secured Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for further description of collateralization of the Senior Secured Notes.
The Puna Project
The Puna project is located in the Puna district, Hawaii. The Puna plant commenced commercial operations in 1993. The Puna plant utilizes an ORMAT geothermal combined cycle system, and has a designed generating capacity of 25 MW, although the power purchase agreement is for 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. We intend to increase the output of the Puna project by upgrading the technology of the plant through the addition of Ormat Energy Converters, drilling another production well, and negotiating a new power purchase agreement for the additional generating capacity that will be available as a result of such activities. The Puna project was acquired in June 2004 with the proceeds of parent company loans and short-term bank loans. We currently intend to refinance the acquisition cost of the Puna project by the first half of 2005. In connection with such refinancing we signed a term sheet with an equity investor and we are currently holding negotiations with two financial institutions which we expect to provide debt financing as part of the contemplated a leverage lease financing transaction.
Foreign Projects
Our projects in operation outside of the United States have a generating capacity of approximately 114 MW. We also have projects under construction in Guatemala and projects under development in China 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 4 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 subsidiary has an 80% partnership interest in Ormat-Leyte Co. Ltd., which owns 100% of the Leyte project. The remaining 20% partnership interest in Ormat-Leyte Co. Ltd. is held by two unrelated third parties. In August 1995, following a build-operate-transfer 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. 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 $14.0 million as of December 31, 2004. 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.
In July, 2004, a transformer for one of the plants at the Leyte project ceased operating for a period of three months. In addition, in August 2004, one of the generators at the Leyte project also ceased operating. We have replaced the transformer and sent the generator for repair, which was completed by the second week of January, 2005. As a result of these events, for the year ended December 31, 2004, Ormat-Leyte Co. Ltd experienced a $1.9 million reduction in revenues compared to our expected revenues for that period. Our commercial and business interruption insurance policies have already partially covered, and we expect them to fully cover, subject to deductibles and applicable waiting periods, the costs associated with such replacement and repair as well as to cover the reduction in revenues we experienced as a result of the reduced electricity generation. We are currently in the process of obtaining approval by our insurance carrier for the transformer claim.
The Momotombo Project (Nicaragua)
The Momotombo project is located in Momotombo, Nicaragua. The Momotombo project is comprised of one plant and a geothermal field. The plant was already in existence when we signed the concession agreement for the project in March 1999, and had commenced commercial operations in the mid-1980s utilizing a dual flash system. In 2003, an additional 6 MW binary unit was added, bringing the generating capacity to approximately 28 MW. The Momotombo project has a power purchase agreement with Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), two corporations which own the power distribution rights in Nicaragua. Our project subsidiary, which operates the Momotombo project, has an outstanding loan from Bank Hapoalim B.M., the outstanding balance of which was $17.0 million as of December 31, 2004.
The Olkaria III Project - Phase I (Kenya)
The Olkaria III project is located in Naivasha, Kenya. The Olkaria III project is comprised of one plant, which commenced commercial operations in August 2000, and a geothermal field. The plant currently has a generating capacity of approximately 13 MW (Phase I). The parties have been working on the construction of Phase II of this project which we expect, upon completion, would increase the generating capacity of the Olkaria III project to approximately 48 MW. A description of Phase II of this project is set forth below in "Projects under Development." Phase I of the Olkaria III project utilizes a binary system. In November 1998, following an international tender, our project subsidiary entered into a power purchase agreement with the Kenya Power & Lighting Co. Ltd., which was further amended in July 2000 and April 2003. Our project subsidiary leases the site on which the geothermal resources and the plant facilities are located from the Kenyan government, pursuant to an agreement which will expire in 2040. The Kenyan government granted our project subsidiary a license giving it exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended 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 the Kenya Power & Lighting Co. Ltd.
The Zunil Project (Guatemala)
The Zunil project is located in Zunil, Guatemala. The Zunil project is comprised of one plant which commenced commercial operations in 1999. The plant utilizes a binary system consisting of Ormat Energy Converters and has a generating capacity of 24 MW. The project is owned by Orzunil I de Electricidad, Limitada, which owns 100% of the Zunil project. Our project subsidiary owns 21% of the outstanding partnership interests of Orzunil I de Electricidad, Limitada. Another of our subsidiaries provides operation and maintenance services to the project. The Zunil project sells its generating capacity to Instituto Nacional de Electrification pursuant to a power supply agreement. As of the date of this 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, 2004, $28.9 million. The loans are due and payable in quarterly installments through November 2011. Each of the IFC and the CDC owns 14% of the issued and outstanding partnership interests of Orzunil I de Electricidad, Limitada. The remaining 51% is owned by an unrelated party.
Projects under Construction or Enhancement
We are in varying stages of construction or enhancement of projects, both domestic and foreign. Based on our current construction and enhancement schedule, we expect to have an additional generating capacity of approximately 97 MW to 102 MW in the United States by the end of 2006 and an additional generating capacity of approximately 20 additional MW in Guatemala by the third quarter of 2006.
The Desert Peak 2 Project
Our project subsidiary is currently constructing the Desert Peak 2 project in Churchill County, Nevada (near the Brady project). The Desert Peak 2 project is expected to have a generating capacity of up to 15 MW and will utilize our Ormat Energy Converters. The electrical output from the project will be sold, and renewable energy and environmental credits will be transferred, to Nevada Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of such power plant. The Desert Peak 2 project is expected to be completed in the fourth quarter of 2005.
The Galena Project
Our project subsidiary is in the process of replacing the equipment currently used in the Steamboat 1 project with new, upgraded equipment. Our project subsidiary will also augment the operation of the Steamboat 1/1A project with additional geothermal resources extracted from the Steamboat 2/3 project's leases that will be diverted for use by the Steamboat 1/1A project.
After such improvements, we will rename the Steamboat 1/1A project as the Galena project. We believe that this upgrade will allow the Galena project to obtain a generating capacity of 20 MW (adding an incremental 13 MW to the existing Steamboat complex). We anticipate that the Galena project will achieve commercial operations in the fourth quarter of 2005 and that the project will sell its electrical output and transfer its renewable energy credits to Sierra Pacific Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of such power plant. Our project subsidiary is coordinating the transition from the Steamboat 1/1A project to the Galena project with Sierra Pacific Power Company.
The Desert Peak 3 Project
The Desert Peak 3 project in Churchill County, Nevada is currently in the engineering stage and is expected to have a generating capacity of 10 MW to 15 MW. Our project subsidiary will sell electrical output from the plant, and transfer the renewable energy and environmental credits, to Nevada Power Company under a power purchase agreement that has a 20-year term commencing on the January 1 following the commercial operation date of the plant and which was signed as part of Nevada Power Company's efforts to comply with Nevada's renewable portfolio standards.
The OREG 1 Project
The OREG 1 project is currently in the engineering stage and is expected to have a generating capacity of 22 MW. Our project subsidiary has entered into a 25-year power purchase agreement with Basin Electric Power Corporation according to which the project will sell electrical output from recovered energy generation power plants. The power plants will be constructed on gas compressor stations along a natural gas pipeline in North and South Dakota.
The power purchase agreement has not yet become effective and is subject to certain conditions, including agreement for the purchase of the recovered energy and a variety of other agreements necessary for the start of construction.
The Amatitlan Project (Guatemala)
Our project subsidiary is currently constructing a geothermal power plant in Amatitlan, Guatemala on a "build, own and operate" or "BOO" basis. The project is comprised of one power plant which we expect will have a generating capacity of 20 MW, and has obtained the rights to various geothermal production and reinjection wells. The Amatitlan plant will use our Ormat Energy Converters.
The term of the power purchase agreement for the Amatitlan project is 20 years from the date of the commencement of operations at the power plant or 23 years from the date of commencement of the construction works, whichever is later. During a period of two years after the completion of the
construction of the power plant, and subject to the signing of an additional agreement with 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 to up to an aggregate of 50 MW by drilling additional wells. We anticipate that the Amatitlan project will be completed in 2006.
Other Projects
We are currently pursuing the addition of Ormat Energy Converters for the Heber complex and Ormesa project, the drilling of additional wells for the Heber complex and the Ormesa and Puna projects, and other activities for the Heber complex. We believe that these activities could increase the generating capacity of the Heber complex and the Puna and Ormesa projects collectively by 33 MW, and we are currently in discussions with Southern California Edison Company and another potential purchaser for this additional electrical power. We are also in the early engineering stages of an enhancement program for the Mammoth and Steamboat Hills projects, which we believe could increase the generating capacity of these facilities by 4 MW and 7 MW, respectively.
Projects under Development
We also have projects under development in the United States, China and Kenya. In certain cases, we have obtained concession agreements and/or financing commitments, and in other cases, the projects are in early development stages. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria.
The Yunnan Project (China)
OrYunnan Geothermal Co., Ltd., which is a joint venture established between our project subsidiary and Yuan Province Geothermal Development Co., Ltd., owns exclusive rights to develop all of the geothermal resources in Teng Chong County, Baoshan City, in Yunnan Province, southwest China. Our project subsidiary owns 85% of the interests in OrYunnan Geothermal Co. Ltd., which owns all of the ownership interests in the Yunnan project. The area of the geothermal concession is approximately 65 square miles and is located approximately 200 miles southwest of Kunming, the provincial capital of Yunnan, and approximately 40 miles from the border with Myanmar. We estimate the potential of the geothermal resources in the concession area to be between 150 to 200 MW. Initially, our project subsidiary and its partner intend to develop a geothermal field and construct a power plant with a generating capacity of approximately 48 MW, which we estimate will require a capital investment of approximately CNY 940.0 million (approximately $113.4 million calculated at the prevailing exchange rate as at December 31, 2004). As of the date hereof, our project subsidiary is awaiting completion of the Chinese central government approval procedures, following which negotiations with the provincial utility company towards the signing of a power purchase agreement can conclude. On May 29, 2002, our project subsidiary entered into a memorandum of understanding, which we refer to as an MOU, regarding the main terms of the power purchase agreement and other major project agreements with Yunan Electric Power Co., Ltd., a state-owned utility company, concerning the purchase of electric power by the utility company from our project subsidiary on a 30-year basis and the related interconnection arrangements. The MOU estimates that the commercial operation date of the plant is to be January 1, 2006. However, we have been in the development stage of the OrYunnan Project for several years and this date will have to be extended for an appropriate period following the completion of the Chinese central government's approval.
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 hereof, our project subsidiary has drilled wells and commenced preliminary construction activities but has not begun any material construction activities with respect to Phase II. We halted our construction activities due to uncertainty relating to the form of government support (if any) that would be provided for the project and the related
collateral package, both of which we requested as pre-conditions for the financing of Phase II. We currently have until April 17, 2005 to notify Kenya Power & Lighting Co. Ltd. whether we will proceed to construct Phase II of the Olkaria III project, in which case the current power purchase agreement with respect to Phase I will remain valid until 2020. In the past, when the Kenya Power & Lighting Co. Ltd. was in a depressed financial state, exacerbated by a prolonged local drought, the enhanced letter of support from the Kenyan Government was considered a necessary prerequisite for the release of Phase II. Since that time, a combination of the resumption of hydro power sourced revenues, a debt to equity conversion which also effectively increased the Kenyan government's stake, a lowering of tariffs by specified suppliers and outside donor funding have improved that entity's financial position. In preparation for the release of Phase II, we have recently requested Kenya Power & Lighting Co. Ltd to post the collateral. At the same time and for the same reasons, we are exploring the possibility of financing and completing Phase II without the additional government support is being positively explored. As previously stated, we currently have until April 17, 2005 to notify Kenya Power & Lighting Co. Ltd. whether we will proceed with the constructing of Phase II of the Olkaria III project. In the event we decide not to proceed with Phase II, and notify Kenya Power & Lighting Co. Ltd about this decision, the current power purchase agreement with respect to Phase I will remain valid until 2020. If we notify Kenya Power & Lighting Co. Ltd. that we will not proceed then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to make such notification that we will not proceed, we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. . In addition, if we do not proceed with the construction of Phase II, we may lose some or all of our investment relating to Phase II, which is approximately $20.9 million as of December 31, 2004.
Geothermal Assets for Future Development in the United States
We have various geothermal leases for future development in the United States. These geothermal leases include the Meyberg lease near Steamboat, Nevada, the Newberry lease in Oregon, the Rhyolite Plateau lease near Mammoth, California, various leases for future development in Puna, Hawaii and various other leases for development in Nevada.
Operations of our Products Segment
Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or OECs. Our customers include contractors and geothermal plant owners and operators. Recently, one of our 1.8 MW power units was installed at Oserian Farm in Kenya, where farmers grow flowers for export.
The consideration for the power units is usually paid in installments, in accordance with milestones set in the supply agreement. Sometimes we agree to provide the purchaser with spare parts (or alternatively, with a non-exclusive license to manufacture such parts). We provide the purchaser with at least a 12-month warranty for such products. We usually also provide the purchaser (often, upon receipt of advances made by the purchaser) with a guarantee, which expires in part upon delivery of the equipment to the site and fully expires at the termination of the warranty period.
Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy or so-called "waste heat" that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We view recovered energy generation as a significant market opportunity for us, and 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 offtakers to sell the electricity generated by the recovered energy generation unit that utilizes such industrial waste heat. We expect that the power purchasers in such cases will be investor-owned electric utilities or local electrical cooperatives. The first agreement was signed in 2004 and we expect it will become effective in the second quarter of 2005.
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).
Our recovered energy generation units qualify as Qualifying Facilities under PURPA for regulatory purposes and, if structured properly, may also be eligible for favorable tax treatment, such as the seven year modified accelerated cost recovery under relevant U.S. federal tax rules.
Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme climate conditions, whether hot or cold. The remote power units supply energy for remote and unmanned installations and along communications lines and cathodic protection along gas and oil pipelines. Our customers include contractors installing gas pipelines in remote areas. In addition, we manufacture and sell generators for various other uses, including heavy duty direct current generators. Our remote power units were recently installed on a Pemex pipeline in Mexico. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.
Engineering, Procurement and Construction ("EPC") of Power Plants. We engineer, procure and construct (EPC), as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. Recent examples of our construction activities include the design and construction of the Mokai and Wairakei geothermal power plants in New Zealand.
The consideration for such services is usually paid in installments, in accordance with milestones set in the EPC contract and related documents. We usually provide performance guarantees or letters of credit securing our obligations under the contract. Upon delivery of the plant to its owner, such guarantees are replaced with a warranty guarantee, usually for a period ranging from 12 months to 36 months. The EPC contract usually places a cap on our liabilities for failure to meet our obligations thereunder. For example, our subsidiary, Ormat Pacific, Inc., is currently acting as EPC contractor for two geothermal projects in New Zealand owned by Contact Energy Limited and Tuaropaki Power Company Limited, respectively. Ormat Industries has guaranteed Ormat Pacific, Inc.'s obligations under both agreements. Ormat Systems, our Israeli subsidiary, will supply the equipment and products necessary for the construction and operation of these power plants.
We also design and construct the recovered energy generation units on a turnkey basis, and may provide a long-term agreement to supply non-routine maintenance for such units. Our customers 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.
Operation and Maintenance of Power Plants. We provide operation and maintenance services for geothermal power plants owned by us and by third parties. For example, we provide operations and management services to the Orzunil project in Guatemala, in which we have a minority ownership interest.
In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation and remote power units and other generators, we, from time to time, enter into sales agreements for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory covered by such agreements by such representatives or, in some cases, by other representatives in such territory.
Our manufacturing operations and products are certified ISO 9001, ISO 14001, ASME and TÜV, and we are an approved supplier to many electric utilities around the world.
Backlog
The Company and our wholly owned subsidiaries have a products backlog of $86.4 million as of March 15, 2005 including revenues for the period between January 1, 2005 and March 14, 2005, compared to $107.6 million for delivery as of January 1, 2004. The following is a breakdown of the products segment backlog:
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Related party
We expect that our revenues from electricity for 2005 from our wholly owned projects will be $170 million and $18 million of revenues from electricity, which is our share in the revenues generated by our subsidiaries accounted for by the equity method.
Our Technology
Our proprietary technology covers power plants operating according to the Organic Rankine Cycle only or in combination with the Steam Rankine Cycle and Brayton Cycle, as well as integration of power plants with energy sources such as geothermal, recovered energy, biomass, solar energy and fossil fuels. Specifically, our technology involves original designs of turbines, pumps, and heat exchangers, as well as formulation of organic motive fluids. All of our motive fluids are non-ozone-depleting substances. Using advanced computerized fluid dynamics and other computer aided design, or CAD, software as well as our test facilities, we continuously seek to improve power
plant components, reduce operations and maintenance costs, and increase the range of our equipment and applications. In particular, we are examining ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, performance simulation programs, and topping turbines. In the geothermal as well as the recovered energy (waste heat) area, we are examining two-level recovered energy systems and new motive fluids.
We also construct combined cycle geothermal plants in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power.
In the conversion of geothermal energy into electricity, our technology has a number of advantages compared with conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer, and also requires cooling water treatment with chemicals and thus a need for the disposition of such chemicals. A conventional geothermal steam turbine plant also creates a significant visual impact in the form of an emitted plume from the cooling tower during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimum visual impact and do not emit a 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 18 years. No single patent on its own is material to our business.
The products-related patents cover components such as turbines, heat exchanges, seals and controls. The system patents cover subjects such as disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources and use of two-phase fluids. A number of patents cover the combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power.
We are also involved in developing new technology to extract heat from the earth by circulating fluid through an enhanced or man-made reservoir created in naturally low permeable or water-poor rocks. We are undertaking this development in cooperation with GeothermEx Inc., the University of Utah, Energy & Geoscience Institute, the University of Nevada-Reno and the Great Basin Center for Geothermal Energy, with funding support from the United States Department of Energy.
Competition
The power generation industry is characterized by intense competition from electric utilities, other power producers, and marketers. In recent years, the United States in particular has seen increasing competition in power sales, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term markets. Such competition has contributed to a reduction in electricity prices.
In the geothermal power generation sector, our main competitors in the United States are CalEnergy, Calpine and Caithness. Some of these companies are also active outside of the United States. Outside of the United States, aside from these companies, we have not recently encountered competition from any private sector geothermal power developer, but may face competition from national electric utilities or state-owned oil companies.
In the products business, our main competitors are Mitsubishi, Fuji and Toshiba of Japan, GE/Nuevo Pignone and Ansaldo of Italy, Siemens of Germany, Alstom of France and Kaluga of Russia. 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.
Siemens of Germany as well as other manufacturers of conventional steam turbines are potential competitors in the recovered energy generation business, although we believe that our recovered energy generation unit has technological and economical advantages over the Siemens/Kalina technology and conventional steam technology. Recently, United Technologies announced the introduction of a small 200 kW Organic Rankine Cycle for recovered energy.
We also compete with companies engaged in the power generation business from renewable energy sources other than geothermal energy, such as wind power, solar power and hydro-electric power.
None of our competitors competes with us both in the sale of electricity and in the products business.
Customers
All of our revenues from the sale of electricity were derived from fully-contracted energy and/or capacity payments under long-term power purchase agreements with governmental and private utility companies. Southern California Edison Company, Sierra Pacific Power Company and Hawaii Electric Light Company have accounted for 41.4%, 12.9%, and 7.1% of revenues, respectively, for the fiscal year ended December 31, 2004. Based on publicly available information, as of December 31, 2004, the issuer ratings of Southern California Edison Company, Sierra Pacific Power Company and Nevada Power Company (a potential power purchaser for the Desert Peak 2 and Desert Peak 3 projects) were Baa1 (stable outlook), B1 (stable outlook) and B1 (stable outlook), respectively, from Moody's Investors Services and BBB+ (stable outlook), B+ (negative outlook), and B+ (negative outlook), respectively, from Standard & Poor's Ratings Services and the issuer rating of Hawaii Electric Light Company was BBB+ (stable outlook) from Standard & Poor's Ratings Services. The credit ratings of any power purchaser may decrease from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the power purchase agreements for our foreign power projects.
Our revenues from the products business were derived from contractors or owners or operators of power plants, process companies and pipelines, including Mokai and Wairakei which accounted for 51.4% and 30.5%, respectively, of our revenues from the sale of products in 2004.
Raw Materials
In connection with our manufacturing activities, we use raw materials such as steel and aluminium. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of such raw materials are readily available from various suppliers.
Employees
As of December 31, 2004, we had 677 employees, of which 228 were in the United States, 295 were in Israel and 154 were located in other countries. We expect that future growth in the number of our employees will be mainly attributable to the purchase and/or development of new power plants.
None of our employees (other than the Momotombo project employees) are represented by a labor union, and we have never experienced any labor dispute, strike or work stoppage. We consider our relations with our employees to be satisfactory. We believe our future success will depend on our continuing ability to hire, integrate and retain qualified personnel.
We have no collective bargaining agreements with respect to our Israeli employees. However, by order of the Israeli Ministry of Industry, Trade and Labor the provisions of a collective bargaining agreement between the Histadrut (the General Federation of Labor in Israel) and the Coordination Bureau of Economic Organizations (which includes the Industrialists Association) may apply to some of our non-managerial, finance and administrative, and sales and marketing personnel. This collective bargaining agreement principally concerns cost of living increases, length of the workday, minimum wages, insurance for work-related accidents, procedures for dismissing employees, annual and other vacation, sick pay, determination of severance pay, pension contributions and other conditions of employment. We currently provide such employees with benefits and working conditions which are at least as favorable as the conditions specified in the collective bargaining agreement.
Insurance
We maintain business interruption insurance, casualty insurance, including flood and earthquake coverage, and primary and excess liability insurance, as well as customary worker's compensation and automobile insurance and such other insurance, if any, as is generally carried by companies engaged in similar businesses and owning similar properties in the same general areas and financed in a similar manner. To the extent any such casualty insurance covers both us and/or our projects, on the one hand, and any other person and/or plants, on the other hand, we generally have specifically designated as applicable solely to us and our projects "all risk" property insurance coverage in an amount based upon the estimated full replacement value of our projects (provided that earthquake and flood coverage may be subject to annual aggregate limits depending on the type and location of the project) and business interruption insurance in an amount that also varies from project to project.
We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries. The policies are 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%-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 regulations in the United States and should not be considered a full statement of the law or all issues pertaining thereto.
PURPA
PURPA, in relevant part, exempts renewable electric generating projects that are "Qualifying Facilities" from various regulations under the FPA. There are two types of Qualifying Facilities: "Qualifying Small Power Production Facilities" and "Qualifying Cogeneration Facilities." Under the FPA as amended by PURPA and the regulations promulgated thereunder, a power production facility
is a "Qualifying Small Power Production Facility" if (i) the facility produces no more than 80 MW (on a net capacity basis) or satisfies certain Federal Energy Regulatory Commission ("FERC") certification and construction dates, (ii) the primary energy source of the facility is biomass, waste, renewable resources, geothermal resources or any combination thereof, and at least 75% of the total energy input is from these sources, and (iii) the facility is owned by a person not primarily engaged in the generation or sale of electric power (other than electric power solely from cogeneration facilities or small power production facilities) (i.e., the project company cannot be controlled by, more than 50% of the equity interests of the facility may not be owned by, and more than 50% of the equity benefits cannot be received by an electric utility, an electric utility holding company or a combination thereof or their subsidiaries).
PURPA Qualifying Facilities receive two primary benefits. First, PURPA exempts Qualifying Facilities, such as our domestic projects (other than the Puna project), from the definition of "electric utility company" under PUHCA, most provisions of the FPA and state laws and regulations relating to financial, organization and rate regulation of electric utilities. Second, the regulations promulgated by FERC under PURPA require, in relevant part, that electric utilities (i) purchase energy and capacity made available by Qualifying Facilities, construction of which commenced on or after November 9, 1978, at a rate based on the purchasing utility's full "avoided costs" and (ii) sell supplementary, back-up, maintenance and interruptible power to Qualifying Facilities on a just and reasonable and nondiscriminatory basis. FERC's regulations define "avoided costs" as the "incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the Qualifying Facility or Qualifying Facilities, such utility would generate itself or purchase from another source. Utilities may also purchase power at prices other than avoided cost pursuant to negotiations as provided by FERC's regulations. Under an amendment to PURPA and PURPA regulations, FERC has also provided that utility of geothermal small power production facilities (that is, geothermal small power production facilities that would be Qualifying Facilities except that they are owned by a person primarily engaged in the generation or sale of electric energy) are exempt from PUHCA but not state regulation or, if applicable, the FPA.
We expect that our domestic projects will continue to meet all of the criteria required for Qualifying Facilities under PURPA. If any of our domestic projects in which we have an interest loses its Qualifying Facility status or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our operations could be adversely affected. Loss of Qualifying Facility status for one of our domestic projects for having more than 50% utility ownership would make that facility a utility geothermal small power production facility. Such facilities are exempt from PUHCA but are subject to state regulation and, if applicable, the FPA. Loss of Qualifying Facility status for any other reason would also make the facility subject to state regulation and, if applicable, the FPA. In addition, loss of Qualifying Facility status for any reason other than utility ownership would make the facility subject to PUHCA unless it has EWG status or falls within another exemption. If a facility lost Qualifying Facility status for any reason other than utility ownership and was ineligible for EWG status because it made retail sales, we would face the choice between discontinuing the retail sales and filing for EWG status or becoming subject to PUHCA. At present, none of our domestic projects makes retail sales of electricity (other than to affiliates). In the unlikely event that we become a public utility holding company, which could be deemed to occur prospectively or retroactively to the date that any of our plants lost its Qualifying Facility status (assuming that that plant was neither an EWG nor a utility geothermal small power production facility), our other domestic projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the Qualifying Facility ownership requirements. This could cause all of our projects to become subject to federal and state energy regulations. In addition, a loss of Qualifying Facility status could allow the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all contract revenues, result in significant liability for refunds of past amounts paid, or otherwise impair the value of a project. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past
amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such refund payment. In addition, such a loss of status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.
In 2003, Congress proposed legislation that, among other provisions, would have had the practical effect of repealing PUHCA and shifting regulatory oversight of holding companies to FERC, and of repealing the mandatory purchase requirements of PURPA. Although the 2003 legislation would not affect existing power purchase agreements for Qualifying Facilities, such legislation or other legislation could (i) repeal or amend PURPA in a manner that substantially reduces the benefits currently afforded Qualifying Facilities, or (ii) otherwise make more burdensome the requirements for the projects to maintain their status as Qualifying Facilities. In such event, operations at the projects or compliance with the terms of the power purchase agreements could be adversely affected, which in turn could reduce our net income and materially and adversely affect our business, financial condition and future results of operation and cash flow.
PUHCA
PUHCA, in relevant part, provides that any corporation, partnership or other entity or organized group that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a "public utility company" (which is defined to include an "electric utility company" or a "gas utility company"), or of a company that is a "holding company" of a public utility company or public utility holding company, is subject to registration with the Securities and Exchange Commission and to regulation under PUHCA, unless exempted by a Securities and Exchange Commission ("SEC") rule, regulation or order. An entity may also be deemed to be a holding company if the Securities and Exchange Commission determines, after providing notice and an opportunity for a hearing, that such entity exercises a controlling influence over the management or policies of any public utility or holding company as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that such entity be regulated as a holding company. Unless an exemption is obtained, PUHCA requires registration for a holding company of a public utility company and requires a public utility holding company to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of the utility system. In addition, a public utility company that is a subsidiary of a registered holding company under PUHCA is subject to financial and organizational regulation, including approval by the SEC of its financing transactions.
Under current federal law, we are not subject to regulation as a holding company under PUHCA and will not be subject to such regulation as long as the plants in which we have an interest are (i) Qualifying Facilities, (ii) "Exempt Wholesale Generators" (as defined in PUHCA) or (iii) subject to another exemption or waiver, such as status as an electric utility geothermal small power production facility.
FPA
Under the FPA, FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined through competitive bidding or negotiation. If a project were to lose its Qualifying Facility status, the rates set forth in its power purchase agreement would have to be filed with FERC and would be subject to review by FERC under the FPA, unless the project is located in Hawaii, Alaska or the parts of Texas that are not deemed to be interstate commerce, in which case state regulations would apply. Under FERC policy, the rates under those circumstances could be no higher than the rate or price the relevant power purchaser would have paid for energy had it not been required to purchase from such project under PURPA's mandatory purchase requirements, i.e., such power purchaser's economy energy (incremental) cost during the period of non-compliance with Qualifying Facility requirements, unless the applicable power purchase agreement otherwise provides for alternative rates to apply in the event of such loss of Qualifying Facility status and FERC accepts such alternative rates.
State Regulation
Our projects in California and Nevada, by virtue of being Qualifying Facilities and because they engage in wholesale sales of electricity to public electric utilities in California and Nevada, are not subject to rate, financial and organizational regulations applicable to public electric utilities in those states. The projects each sell or will sell their electrical output to public electric utilities (either Sierra Pacific Power Company, Nevada Power Company or Southern California Edison Company) which are regulated by their respective state public utility commission. Sierra Pacific Power Company and Nevada Power Company are regulated by the Public Utility Commission of Nevada, which we refer to as NPUC. Southern California Edison Company and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission, which we refer to as CPUC. Since the NPUC and the CPUC regulate the retail rates through which the purchasing utilities recover their payments to our facilities from the retail electric customers of the public electric utilities under their jurisdiction, it is important for the purchasing electric utilities to obtain approval by their respective public utility commissions of their agreements with our projects. It is also important for the public electric utilities to be allowed continued recovery in their retail electric rates of the cost paid to our projects for electricity.
The NPUC has previously approved the agreements for each of our existing projects located in Nevada and has continuously allowed recovery of the costs of the electricity from those projects in the retail electric rates charged by Sierra Pacific Power Company. The NPUC, pursuant to a delegation of authority from FERC, also sets the avoided cost basis for updating the rates in several of our contracts. While we have no reason to believe that the NPUC will not continue to allow such recovery and continue to set the appropriate avoided cost rate, we cannot guarantee a specific avoided cost rate level or recovery in rates by the regulated public utility. The inability to recover the full cost of the electricity from our project by a public utility could adversely impact the ability of the public utility to pay for the electricity from a project, but such adverse treatment is unlikely given the pre-approval of the agreements. Further, we believe that federal law requires the state commissions to permit full recovery of PURPA-based wholesale rates by the purchasing utility, but we are aware of no judicial decisions in California, Nevada, or Hawaii upholding this principle.
Under Hawaii law, non-fossil generators are not public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the Hawaii Public Utility Commission will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at full avoided cost.
Foreign Regulation of the Electric Utility Industry
The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power project and should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.
Nicaragua. 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, that is responsible for setting policies, strategies and objectives for such sector and approving indicative plans therefor. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the Nicaraguan Institute of Energy, which we refer to as INE. The Nicaraguan government currently owns all of the commercial activities in the energy sector through Empresa Nacional de Electricidad ("ENEL").. The Nicaraguan energy sector has recently been restructured and partially privatized. Following such restructuring and privatization, the government has retained title and control of the transmission assets and has created the Empresa Estatal de Transmision ("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. On October 2002, Law No.443 was enacted by the National Congress related specifically to Geothermal resources for energy production. This law regulates the granting of exploration and exploitation concessions for geothermal fields. The INE adopted this law.
Guatemala. The General Electricity Law of 1996 created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the National Electric Energy Commission ("CNEE") and a new wholesale power market administrator, the Administrator of the Wholesale Market ("AMM"), for the regulation and administration of such sector. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating the electricity law, overseeing the market and setting rates for transmission services and for electricity service to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with 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 exemption and a 10-year business tax exemption.
Kenya. Kenya's Electric Power Act of 1997 restructured the electricity sector in such country. Among other things, the Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. The Kenya Power & Lighting Co. Ltd. is the only licensed public electricity supplier and has a monopoly in the transmission and distribution of electricity in the country. The Act permitted Independent Power Producers ("IPPs") to install power generators and sell electricity to Kenya Power & Lighting Co. Ltd., which is owned by various private and government entities and which 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. Kenya Power & Lighting Co. Ltd.'s retail electricity rates are subject to approval by the Electricity Regulation Board.
Philippines. The Philippine's Electric Power Industry Reform Act of 2001 created the Energy Regulatory Commission, which is an independent quasi-judicial regulatory body mandated to promote competition, encourage market development, ensure customer choice and penalize abuse of market power in the restructured electricity industry. The Energy Regulatory Commission is responsible for the enforcement of the rules and regulations governing the operations of the electricity spot market and the activities of the spot market operator and other participants to ensure a greater supply and rational pricing of electricity. In addition, the Energy Regulatory Commission determines, fixes, and approves transmission and distribution wheeling charges and retail electricity rates for the captive market of a distribution utility through a methodology that it establishes and enforces. The Energy Regulatory Commission also monitors and takes measures to penalize abuse of market power and anti-competitive or discriminatory behavior by any electric power industry participant.
Permit Status
While our power generation operations produce electricity without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide, some of our projects do emit air pollutants in quantities that are subject to regulation under applicable environmental air pollution laws. Such operations typically require air permits. Especially critical to our geothermal operations are those permits and standards applicable to the construction and operation of geothermal wells and brine reinjection wells. In the United States, injection wells are
regulated under the federal Safe Drinking Water Act Underground Injection Control, which we refer to as UIC, program. Our injection wells typically fall into UIC Class V, one of the least regulated categories, because fluids are reinjected to enhance utilization of the geothermal resource. Our projects are required to comply with numerous domestic and foreign federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for their operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms.
Our operations are designed and conducted to comply with applicable permit requirements. Non-compliance with any such requirements could result in fines or other penalties. We are not aware of any non-compliance with such requirements that would be likely to result in fines or penalties; however, the Heber 1 and 2 projects received a notice from the California Division of Oil, Gas and Geothermal Resources that the pressure levels at some of the geothermal fluid injection wells were too high, and the California Regional Water Quality Control Board and the Colorado River Basin Region has notified the Heber 1 and 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 inject the cooling tower blowdown water into the geothermal injection reservoir, as do other geothermal projects in the Imperial Valley.
As of the date of this annual report, all of the material permits and approvals 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 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. Typically, permit transfers or the reissuance of permits in connection with a change of ownership are routine administrative matters.
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 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 2.
ITEM 2. PROPERTIES
We lease our corporate offices at 980 Greg Street, Sparks, Nevada 89431. We also occupy an approximately 66,000 square meter office and manufacturing facility located in the industrial park of Yavne, Israel, which we sublease from Ormat Industries. See "Certain Relationships and Related Transactions." We also lease small offices in each of the countries in which we operate.
We believe that our current facilities are adequate for our operations as currently conducted. If additional facilities are required, we believe that we could obtain additional facilities at commercially reasonable prices.
Each of our 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.
ITEM 3. LEGAL PROCEEDINGS
There were no material developments in any legal proceedings to which the Company is a party during the fiscal year 2004, other than the settlement with IID as described below.
In August 2003, Ormesa LLC agreed to enter into binding arbitration with the Imperial Irrigation District, which we refer to as the IID, in connection with the IID's claim that Ormesa LLC was obligated to pay scheduling and transmission charges (including those applicable to the GEM 2 and GEM 3 plants) through the effective date of relinquishment of nominated capacity for the GEM 2 and GEM 3 plants. The amount in dispute was $529,000. Ormesa LLC contended that it was not obligated to pay the subject charges for the GEM 2 and GEM 3 plants after the January 1, 2003 effective date of the Energy Services Agreement that Ormesa LLC entered into with the IID. In December, 2004, a Settlement Agreement and Mutual Release between IID and Ormesa LLC was reached, under which Ormesa LLC paid the sum of US$330,630 in full settlement of the claim.
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 allege damages based upon three separate theories: (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 as well as some initial 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. We have initiated settlement discussions with the plaintiffs. As part of such discussions, we have received a letter from the plaintiffs in which they assert that, in addition to the amounts they claim are owed to them, they are also entitled to a reasonable net operating royalty payment from our Galena project. We believe that such assertion is without merit, and that any outcome of such litigation or settlement discussions will not
have a material impact on our results of operations. We estimate that the aggregate amount of all liabilities resulting from such litigation will not exceed $1 million, and we have recorded a provision in that amount in our financial records.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote by our sole stockholder, Ormat Industries, during the fourth quarter of 2004. On October 21, 2004, prior to the initial public offering of the Company's common stock, Ormat Industries acted on several matters by unanimous written consent. The following matters were acted upon:
1) Second Amended and Restated Certificate of Incorporation - The sole stockholder approved the Second Amended and Restated Certificate of Incorporation.
2) Second Amended and Restated By-laws - The sole stockholder approved the Second Amended and Restated By-laws.
3) Rights Agreement - The sole stockholder approved the Rights Agreement.
4) Ormat Technologies, Inc. 2004 Incentive Compensation Plan - The sole stockholder approved the Ormat Technologies, Inc. 2004 Incentive Compensation Plan.
PART II
ITEM 5.
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 two at March 15, 2005. On March 15, 2005, our stock's closing price as reported on the New York Stock Exchange was $15.31 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 therefor. The actual amount and timing of dividend payments will depend upon our financial condition, results of operations, business prospects and such other matters as the board may deem relevant from time to time. Even if profits are available for the payment of dividends, the Board of Directors could determine that such profits should be retained for an extended period of time, used for working capital purposes, expansion or acquisition of businesses or any other appropriate purpose. As a holding company, we are dependent upon the earnings and cash flow of our subsidiaries in order to fund any dividend distributions and, as a result, we may not be able to pay dividends in accordance with our policy. Our Board of Directors may, from time to time, examine our dividend policy and may, in its absolute discretion, change such policy.
We did not declare any cash dividends on the common stock for fiscal year 2003. In fiscal year 2004, we declared, approved and authorized the payment of a dividend to our stockholders of record on October 21, 2004, related to the year 2004 profits in the aggregate amount of $2.5 million ($0.1025 per share). The dividend was paid on March 2, 2005. On March 22, 2005, by a unanimous written consent of our Board of Directors we declared, approved and authorized the payment of an additional dividend of $0.03 per share, based on the number of shares issued and outstanding at March 22, 2005, which should not change until the date of payment, on account of fourth quarter profits, to all issued and outstanding shares of common stock on April 4, 2005, payable on April 18, 2005.
Ormat Technologies, Inc. (ORA) - High and Low Prices for the Fourth Quarter Period, Ending December 31, 2004, and until March 15, 2005:
Fourth Quarter 2004:
High: $ 18.70
Low: $ 15.20
January 1- March 15, 2005:
High: $ 16.5
Low: $ 15.01
Equity Compensation Plan Information
For information on our equity compensation plans, refer to Item 12 "Security Ownership of Certain Beneficial Owners and Managments."
Unregistered Sales of Equity Securities and Use of Proceeds
On June 30, 2004, we issued 1,160,714 shares of our common stock to Ormat Industries in connection with the conversion of a $20.0 million loan to equity. We have relied on the private placement exemption pursuant to Section 4(2) of the Securities Act of 1933, as amended, with respect to the issuance of such shares.
On November 10, 2004, the SEC declared effective our registration statement on Form S-1 (File No. 333-117527) ("Registration Statement") for our Initial Public Offering. Under the Registration Statement, we registered and sold 7,187,500 shares of our common stock. All of the 7,187,500 shares sold in that offering were sold at $15.00 per share. The offering closed on November 16, 2004. The underwriting syndicate was managed by Lehman Brothers Inc., Deutsche Bank Securities Inc., RBC Capital Markets Corporation, and Wells Fargo Securities LLC.
The aggregate gross proceeds from the sale of 7,187,500 shares of common stock were $107.8 million. The aggregate net proceeds to us after the offering were $97.0 million, after deducting an aggregate of $7.5 million in underwriting discounts and commissions paid to the underwriters and $3.3 million in other expenses incurred in connection with the offering.
As of the date of this filing, we invested our net proceeds in interest-bearing investment-grade instruments and bank deposits.
ITEM 6.
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, 2004, 2003 and 2002 and as of December 31, 2004 and 2003 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, 2001 and 2000, and as of December 31, 2002, 2001 and 2000 from our audited consolidated financial statements not included herein.
The information set forth below should be read in conjunction with Item 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis of our results of operations, financial condition and liquidity in conjunction with our consolidated financial statements and the related notes. Some of the information contained in this discussion and analysis or set forth elsewhere in this annual report including information with respect to our plans and strategies for our business, statements regarding the industry outlook, our expectations regarding the future performance of our business, and the other non-historical statements contained herein are forward-looking statements. See "Cautionary Note Regarding Forward-Looking Statements". You should also review the "Risk Factors" section under this Item for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.
General
Overview
We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal power plants, and we also design, develop and build, and plan to own and operate, recovered energy-based power plants, in each case, using equipment that we design and manufacture. In addition, we sell the equipment we design and manufacture for geothermal electricity generation, recovered energy-based electricity generation, and other equipment for electricity generation to third parties. Our operations consist of two principal business segments. The first consists of the sale of electricity from our power plants, which we refer to as the Electricity Segment, while the second consists of the design, manufacturing and sale of equipment for electricity generation, the installation thereof and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants, which we refer to as the Products Segment.
Our Electricity Segment currently consists of our investment in power plants producing electricity from geothermal resources. It will also include our planned investment in power plants producing electricity from recovered energy resources. Our geothermal power plants include both power plants that we have built and power plants that we have acquired. Our Products Segment consists of the design, manufacture and sale of equipment that generates electricity, principally from geothermal and recovered energy resources, but also using other fuel sources as well. Our Products Segment also includes, to the extent requested by our customers, the installation of our equipment and other related power plant installations and the provision of services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. For the year ended December 31, 2004, our Electricity Segment represented approximately 72.4% of our total revenues, while our Products Segment represented approximately 27.6% of our total revenues during such period.
Our Electricity Segment operations are conducted in the United States and throughout the world. We have increased our net ownership interest in generating capacity by 162 MW between December 31, 2002 and December 31, 2004, of which 150 MW was attributable to our acquisition of geothermal power plants from third parties and 12 MW was attributable to increased generating capacity of our existing geothermal power plants resulting from plant technology upgrades and improvements to our geothermal reservoir operations. Since January 1, 2001, we have completed various acquisitions of geothermal power plants in the United States with an aggregate acquisition cost, net of cash received, of $503.9 million. We also own or control as well as operate geothermal projects in Guatemala, Kenya, Nicaragua and the Philippines. Our net ownership in our generating capacity has increased from 94 MW, as of December 31, 2001, to 302 MW, as of December 31, 2004.
In the year ended December 31, 2004, total Electricity Segment revenues from the sale of electricity by our wholly owned power plants (including revenues of our 80% owned Leyte Project for the three month ended March 31, 2004, as described below) were $158.8 million.
In addition, revenues from our 50% ownership of the Mammoth Project for the year ended December 31, 2004 and revenues from our 80% ownership of the Leyte Project for the period from April 1, 2004 to December 31, 2004 (due to the deconsolidation of the Leyte Project on April 1, 2004, as a result of adoption of FIN No. 46R), were $14.5 million. The investments of such projects are accounted for in our consolidated financial statements under the equity method.
Our Products Segment operations are also conducted in the United States and throughout the world. For the year ended December 31, 2004, revenues attributable to our Products Segment were $60.4 million. We have identified recovered energy-based power generation as a significant market opportunity for us in the United States and throughout the world. We expect that an important element of our growth in the Products Segment will be the design, manufacturing and sale of recovered energy products that will allow us (in our Electricity Segment) and potential customers (in our Product Segment) to utilize waste heat for the purpose of producing electricity.
Our Electricity Segment is characterized by relatively predictable revenues generated by our power plants pursuant to long-term power purchase agreements, with terms which are generally up to 20 years. By contrast, revenues attributable to our Products Segment, which are based on the sale of equipment and the provision of various services to our customers are far less predictable and may vary significantly from period to period. Our management assesses the performance of our two segments of operation differently. In the case of our Electricity Segment, when making decisions about potential acquisitions or the development of new projects, our management typically focuses on the internal rate of return of the relevant investment, relevant technical and geological matters and other relevant business considerations. Additionally, as part of our Electricity Segment, our management evaluates our operating projects based on the performance of such projects in terms of revenues and expenses in contrast to projects that are under development, which our management evaluates based on costs attributable to each such project. Our management evaluates the performance of our Products Segment based on the timely delivery of our products, performance quality of our products and costs actually incurred to complete customer orders as compared to the costs originally budgeted for such orders.
During the year ended December 31, 2004, our total revenues increased by 83.5% (from $119.4 to $219.2 million) over the previous year. It is important to note, however, that the year ended December 31, 2004 is the first year in which our total revenues included revenues generated by power plants that we acquired during the twelve months preceding December 31, 2004. Accordingly, our results of operations for the various years covered by our consolidated financial statements set forth in Part II Item 8 of this annual report may not be comparable with each other or indicative of future results.
The profitability of our acquisition and expansion strategy is reflected by the growth in our operating income, which increased to $62.4 million for the year ended December 31, 2004 compared with $25.5 million for the year ended December 31, 2003. There can be no assurance, however, that our operations will continue to achieve this level of profitability. Please review the section "Risk Factors -Factors that could affect future results" set forth in this item for a description of the risks that may affect our business.
Recent Development
On November 16, 2004, we completed an initial public offering of 7,187,500 shares (including the underwriters' over-allotment option) of our common stock pursuant to a prospectus dated November 10, 2004 at $15 per share. Net proceeds to us after commissions and offering related expenses were approximately $97.0 million. As of March 15, 2005, there were 31,562,495 shares of our common stock outstanding.
Trends and Uncertainties
The geothermal industry in the United States has historically experienced significant growth followed by a consolidation of owners and operators of geothermal power plants. During the 1990s, growth and development in the geothermal industry occurred primarily in foreign markets and only
minimal growth and development occurred in the United States. Since 2001, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation due to increasing gas prices and as a result of newly enacted legislative and regulatory incentives, such as state renewable portfolio standards. We see the increasing demand for energy generated from geothermal and other renewable resources in the United States and the further introduction of renewable portfolio standards as the most significant trends affecting our industry today and in the immediate future. Our operations and the trends that from time to time impact our operations are subject to market cycles.
Although other trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following trends, factors and uncertainties:
• We have experienced significant growth through the acquisition and enhancement of geothermal power plants and expect to experience additional growth due to the construction of additional projects. As a result of such acquisitions, we expect an increase in our consolidated revenues as well as in our operating income attributable to our Electricity Segment in 2005, as compared to our consolidated revenues and in our operating income attributable to our Electricity Segment for the year ended December 31, 2004.
• In the United States, we expect to continue to benefit from the increasing demand for renewable energy as a result of favorable legislation adopted by 18 states and the district of Colombia, including California, Nevada and Hawaii (where we have been the most active in our geothermal development and in which all of our U.S. projects are located). In each of these states, relevant legislation currently requires that an increasing percentage of the electricity supplied by electric utility companies operating in such states be derived from renewable energy resources until certain pre-established goals are met. We expect that the additional demand for renewable energy from utilities in such states will create additional opportunities for us to expand existing projects and build new power plants.
• Outside of the United States, we expect that a variety of governmental initiatives, including the award of long-term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage "clean" renewable and sustainable energy sources, will create new opportunities for the development of new projects as well as create additional markets for our remote power units and other products.
• We have identified recovered energy-based power generation as a significant market opportunity for us in the United States and throughout the world. We are initially targeting the North American market and, thereafter, we intend to leverage our success in that market in order to expand such operations throughout the world. If our expectations regarding the growth in demand for our recovered energy units are not met, we may not be able to generate the revenues we expect from such operations.
• We expect the revenues from our Products Segment in 2005 to be similar to the revenue level we achieved in 2004. In pursuing new orders, we participate in tenders for projects and proposals for installations and identify and monitor markets, which utilize or plan to utilize geothermal energy, and in which geothermal resources are available. Over the long-term, we intend to continue to pursue growth in our recovered energy business, and we expect that the portion of revenues from our recovered energy business as a percentage of the total revenues from our Product Segment will increase.
• We expect to continue to generate the majority of our revenues from the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from fully-contracted payments under long-term power purchase agreements.
• The viability of the geothermal resources utilized by our power plants depends on various factors such as the heat content of the geothermal reservoir, useful life of the reservoir (the term during which such geothermal reservoir has sufficient extractable fluids for our operations) and operational factors relating to the extraction of the geothermal fluids. Our geothermal power plants may experience an unexpected decline in the capacity of their respective geothermal wells. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties we face in connection with our operations.
• Our foreign operations are subject to significant political, economic and financial risks, which vary by country. Such risks include the ongoing privatization of the electricity industry in the Philippines, the partial privatization of the electricity sector in Guatemala, labor unrest and strengthening of unions in Nicaragua and the political uncertainty currently prevailing in Kenya. Although we maintain political risk insurance as an attempt to mitigate such risks, such insurance does not provide complete coverage with respect to all such risks.
• We expect current interest rates to gradually increase in the short-term. Any increases in interest rates that impact our existing financings or future financings could increase the aggregate amount of our interest expenses and thus could have an adverse effect on our results of operations.
• We have experienced recent increases in the cost of raw materials required for our equipment manufacturing activities, which we believe have resulted primarily from increased demand in the Chinese market for such raw materials, and increases in the cost of transportation of our products. An increase in such costs may have an adverse effect on our financial condition and results of operations.
• Under Section 710 of the American Jobs Creation Act of 2004 that was signed into law on October 22, 2004, owners of geothermal power companies are allowed to claim a "production tax credit" of 1.8 cents per kWh on electricity produced from geothermal resources. Under the Act, we may claim these credits on electricity generated as a result of the planned enhancement or construction of projects that will be put in service before December 31, 2005. We, as the owner of the project must choose between this production tax credit and a 10% investment tax credit. The production tax credit that could be claimed on electricity sold during the first five (5) years after the project achieves commercial operation may significantly improve our financial results. Some of our power purchase agreements allow the power purchaser to benefit from part of such production tax credits, if and when they become available to us.
Revenues
We generate our revenues primarily from the sale of electricity from our geothermal power plants, the design, manufacture and sale of equipment for electricity generation and the construction, installation and engineering of power plant equipment.
Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants pursuant to long-term power purchase agreements; however, such revenues are subject to seasonal variations, as more fully described below in the section entitled "Seasonality". Our power purchase agreements generally provide for the payment of capacity payments, energy payments, or both. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our power purchase agreements provide for bonus payments in the event that we are able to exceed certain target levels and the potential forfeiture of payments if we fail to meet minimum target levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser's short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others).
As required by Emerging Issues Task Force No. 01-8, Determining Whether an Arrangement Contains a Lease, we assessed all of our power purchase agreements acquired since July 1, 2003, and concluded that all such agreements related to our Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the agreements are presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy presented as "energy and capacity" revenue in our consolidated financial statements. As the lease revenue and the energy and capacity revenues are derived from the same arrangement and both fall within our Electricity Segment, we analyze such revenues, and related costs, on a combined basis for management purposes.
Revenues attributable to our Products Segment are generally unpredictable because larger customer orders for our products are typically a result of our participating in, and winning, tenders issued by potential customers in connection with projects they are developing. Such projects often take a long time to design and develop and are often subject to various contingencies such as the customer's ability to raise the necessary financing for a project. As a result, we are generally unable to predict the timing of such orders for our products and may not be able to replace existing orders that we have completed with new ones. As a result, our revenues from our Products Segment fluctuate (and at times, extensively) from period to period.
The following table sets forth a breakdown of our revenues for the years indicated:
Geographical breakdown of revenues
84.7%, 56.4% and 48.0% of the revenues attributable to our Electricity Segment were generated in the United States in the year ended December 31, 2004, 2003, and 2002, respectively. During the past three fiscal years, the percentage of our total revenues attributable to the sale of electricity in the United States has increased significantly, as compared to the percentage of our total revenues that is attributable to the sale of electricity by our foreign projects that has declined commensurately. The revenues of our foreign projects for the year ended December 31, 2004 also decreased due to the deconsolidation of the Leyte Project from our consolidated financial statements as of April 1, 2004. The increase in our Electricity Segment is largely attributable to our recent acquisition of various projects in the United States. The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment for the years indicated:
Historically, revenues attributable to our Products Segment, after giving effect to the elimination of intercompany transactions, have been derived primarily from outside of the United States, which is reflective of the historical demand in the United States described elsewhere in this annual report. Since 2003, we have begun to generate revenues attributable to our Products Segment in the United States as well. However, as a result of the fluctuation and unpredictability of the revenues attributable to our Products Segment and the impact that a few sales or EPC contracts can have on the geographic distribution of such revenues, the geographical distribution of such revenues may not be indicative of any developing trends or of our future results.
Seasonality
The demand for the electricity generated by our domestic projects and the prices paid for such electricity pursuant to some of our power purchase agreements are subject to seasonal variations. The demand for electricity from the Heber 1 and 2 projects, the Mammoth project and the Ormesa project is the highest in the summer months of June through September, because the power purchaser for those projects, Southern California Edison Company, delivers more electricity to its California markets during such period in order to meet demand for air conditioning and other energy-intensive cooling systems utilized during such summer months. The demand for electricity from the Steamboat complex and the Brady project is more balanced, consisting of both summer and winter peaks that reflect the greater temperature variations in Nevada. The demand for electricity from the Puna project is balanced due to the equatorial temperature in Hawaii (with less pronounced temperature variations during the year). In California, the capacity rates payable pursuant to the applicable power purchase agreement are higher in the summer months and as a result we receive higher revenues during such months. In contrast, there are no significant changes in prices during the year payable pursuant to our power purchase agreement for the Puna project and the Nevada projects. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by the power purchaser in California in the summer months as a result of the increase in demand and in prices have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency, and as a result our revenues are generally higher in the summer than in the winter.
Breakdown of Expenses
Electricity Segment
The principal expenses attributable to our operating projects include operation and maintenance expenses such as salaries, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes and insurance and, for the California projects, transmission charges, scheduling charges and purchases of sweet water for use in our plant cooling towers. Some of these expenses, such as parts and third-party services are not incurred on a regular basis, which results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter.
Payments made to government agencies and private entities as compensation for the use of the relevant geothermal resources and site leases where plants are located are included in cost of revenues.
Royalty payments are payments made as compensation for the right to use certain geothermal resources and are included as a component of cost of revenues, and are paid as a percentage of the revenues derived from the associated geothermal rights. For the year ended December 31, 2004, royalties were approximately 3.0% of the electricity revenues.
Products Segment
The principal expenses attributable to our Products Segment include materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses, sales commissions to sales representatives and royalties pertaining to government participation in our research and development programs at a rate of 3.5% to 5.0% of the proceeds recovered from the sale of products which were developed pursuant to such research and development programs.
Some of the principal expenses attributable to our Products Segment, such as a portion of the costs related to labor, utilities and other support services are fixed and, in order to maintain our current production and construction capability must be incurred, notwithstanding the revenues attributable to our Products Segment. As a result, the cost of revenues attributable to our Products Segment, expressed as a percentage of total revenues, is often very fluctuant. To date, our management has made the strategic decision to maintain our production and construction capacity and, therefore, maintain the fixed cost component of the total costs attributable to our Products
Segment at the current level. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.
Cash, Cash Equivalents and Marketable Securities
Our cash, cash equivalents and marketable securities as of December 31, 2004 increased to $125.9 million from $8.9 million as of December 31, 2003, principally due to the additional cash received from: (i) proceeds from the IPO of shares of our common stock on the New York Stock Exchange that was completed on November 16, 2004., (ii) proceeds from the issuance of the Senior Secured Notes, and (iii) the operating activities of the acquired projects.
Critical Accounting Policies
Our significant accounting policies are more fully described in Note 1 to our audited consolidated financial statements set forth in Part II Item 8 of this annual report. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Such estimates are based on management's historical experience, the terms of existing contracts, management's observance of trends in the geothermal industry, information provided by our customers and information available to management from other outside sources, as appropriate. Such estimates are subject to an inherent degree of uncertainty. Our critical accounting policies include:
• Revenues and Cost of Revenues. Revenues related to the sale of electricity from our geothermal power plants, and capacity payments paid in connection with such sales, are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant power purchase agreements. Revenues generated from engineering and operating services and sales of products and parts are recorded once the service is provided or product delivery is made, as applicable. Revenues generated from the construction of geothermal and recovered energy power plant equipment on behalf of third parties is recognized on the percentage completion method, which is the relationship between costs actually incurred and total estimated costs to completion. Such cost estimate is made by management in part based on prior operations and in part based on specific project characteristics and designs. If management's estimates utilized with respect to our Products Segment of total estimated costs to completion are inaccurate, then the percentage of completion will also be inaccurate and thus lead management to over or under-estimate the gross margins for our Products Segment. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined.
• Determining whether a Arrangement Contains a Lease. In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combinations on or after July 1, 2003. The adoption of EITF Issue No. 01-8 effective July 1, 2003 did not have a material effect on our financial position or results of operations. The power purchase agreements acquired in connection with the acquisition of the Heber 1 and 2, Steamboat 2/3, Steamboat Hills and Puna projects contain a lease element within the scope of SFAS No. 13. Accordingly, for the
year ended December 31, 2004, revenues and costs associated with the lease element of the Steamboat 2/3 power purchase agreements have been presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in our statements of operation.
• Impairment of Long-lived Assets and Long-lived Assets to Be Disposed of. Long-lived assets including unconsolidated investments and power purchase agreements are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated future net undiscounted cash flows expected to be generated by the relevant asset. The significant assumptions that we use in estimating our undiscounted future cash flows include: (i) projected generating capacity of the project and rates to be received under the respective power purchase agreements, and (ii) projected operating expenses of the relevant project. If assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors relating to our business. Our review of existing factors and the resulting appropriate carrying value of our long-lived assets are subject to judgment and estimates that management is required to make. We believe that no impairment exists for our long-lived assets; however future estimates as to the recoverability of such assets may change based on revised circumstances.
• Obligations Associated with the Retirement of Long-Lived Assets. Effective January 1, 2003, we adopted Statement of Financial Accounting Standards ("SFAS") No. 143 of the Financial Accounting Standards Board ("FASB"), Accounting for Obligations Associated with the Retirement of Long-Lived Assets. Pursuant to SFAS No. 143, entities are required to record the fair market value of any legal liability related to the retirement of any of its assets in the period in which such liability is incurred. Our liabilities related to the retirement of our assets include our obligation to cap wells upon termination of our operating activities, the dismantling of our geothermal power plants upon cessation of our operations and the performance of certain remedial measures related to the land on which such operations were conducted. When a new liability for an asset retirement obligation is recorded, we capitalize the costs of such liability by increasing the carrying amount of the related long-lived asset. Such liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, an entity either settles the obligation for its recorded amount or incurs a gain or a loss with respect thereto, as applicable. We estimate the costs related to such liabilities and if such estimates are incorrect, then the capitalized costs and carrying amount of the related long-lived asset will change and as a result may affect our consolidated financial condition and results of operations.
• Derivative Instruments. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless such instruments are exempted from derivative treatment as a normal purchase and normal sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
We maintain a risk management strategy that incorporates the use of interest rate swaps and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by interest rate volatility. Gain or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and are subsequently reclassified into earnings when interest on the related
debt is paid. Gain or losses on contracts that are not designated to qualify as a cash flow hedge are included as a component of interest expense.
We adopted and have become subject to the provisions of SFAS No. 133 Derivative Implementation Group (DIG") Issue No. C15, Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also, pursuant to DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. We have power sales agreements that qualify as derivative instruments under DIG Issue No. C15 and do not meet the exception as they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. Our adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on our consolidated financial position and results of operations.
In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, or October 1, 2003 for us. DIG Issue No. C20 requires contracts that did not previously qualify for the normal purchases and normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortize such fair value over the remaining contract period. Upon our adoption of DIG Issue No. C20, we elected the normal purchase and normal sales scope exception under FAS No. 133 related to our power purchase agreements. Such adoption did not have a material impact on our consolidated financial position and results of operations.
• Accounting for Income Taxes. As part of the process of preparing our consolidated financial statements, we are required to estimate our income tax in each of the jurisdictions in which we operate. This process requires us to estimate our actual current tax exposure and make an assessment of temporary differences resulting from differing treatment of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheet. We must then assess the likelihood that our net deferred tax assets will be recovered from future taxable income and, to the extent we believe that such recovery is not likely, we must establish a valuation allowance. To the extent we establish a valuation allowance or increase such allowance in a period, we must include an expense within the tax provision in our consolidated statement of operations. Management uses significant judgment in determining our deferred tax assets and liabilities and any valuation allowance recorded against our net deferred tax assets. In the event that we generate taxable income in a particular jurisdiction in which we operate and in which we have net operating loss carryforwards for which a deferred tax valuation allowance has been established, we may be required to adjust our valuation allowance. We account for investment tax credits and we will account in the future, if applicable, for production tax credits as a reduction to income tax in the year in which the credits arise.
• Stock-Based Compensation. We account for stock-based compensation based on the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees and related interpretations, which we refer to as APB Opinion No. 25, which states that no compensation expense is required to be recorded for stock options or other stock-based awards to employees that are granted with an exercise price equal to or above the estimated fair value per share of common stock on the relevant grant date. In the event that stock options are granted at a price that is lower than the fair market value on the relevant grant date, the difference between the fair market value of the common stock and the
exercise price of the stock options is recorded as unearned compensation. Unearned compensation is amortized to compensation expense over the vesting period applicable to the stock option. We have adopted the disclosure requirements of SFAS No. 123, Accounting for Stock-Based Compensation, as it relates to stock options granted to employees, which requires pro forma net income to be disclosed based on the fair value of the options granted at the date of the relevant grant.
• New Accounting Pronouncements
Consolidation of Variable Interest Entities
In January 2003, the FASB, issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB 51, which we refer to as FIN No. 46, as amended by FIN No. 46R in December 2003. Among other things, FIN No. 46R generally deferred the effective date of FIN No. 46 to the quarter ended March 31, 2004. The objectives of FIN No. 46R are to provide guidance on the identification of Variable Interest Entities, which we refer to as VIEs, for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which company (if any), as the primary beneficiary, should consolidate such VIE. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity's economic variability.
Effective as of March 31, 2004, we adopted FIN No. 46R. In connection with the adoption of FIN No. 46R, we concluded that Ormat Leyte Co., Ltd., in which we have an 80% ownership interest, should be deconsolidated. Ormat Leyte Co., Ltd.'s operating results were accounted for using the consolidated method of accounting for the three-month period ended March 31, 2004 and, effective April 1, 2004, our ownership interest in Ormat Leyte Co., Ltd. is accounted for using the equity method of accounting.
Share-Based Payments
In December 2004, the FASB issued the revised SFAS No. 123, Share-Based Payment, which we refer to as SFAS No.123R and which addresses the accounting for share-based payment transactions in which a company obtains employee services in exchange for: (i) equity instruments of the company, or (ii) liabilities that are based on the fair value of the company's equity instruments or that may be settled by the issuance of such equity instruments. SFAS No.123R eliminates the ability to account for employee share-based payment transactions using APB Opinion No. 25, Accounting for Stock Issued to Employees, and requires instead that such transactions be accounted for using the grant date fair value based method. SFAS No. 123R will be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005 (July 1, 2005 for us). Early adoption of FAS No.123R is encouraged. SFAS No.123R applies to all awards granted or modified after the Statement's effective date. In addition, compensation cost for the unvested portion of previously granted awards that remain outstanding on the Statement's effective date shall be recognized on or after the effective date, as the related services are rendered, based on the awards' grant date fair value as previously calculated for the pro forma disclosure under SFAS No.123.
We estimate that the cumulative effect of adopting SFAS No.123R as of its adoption date by us (July 1, 2005), based on the awards outstanding as of December 31, 2004, will be immaterial. This estimate does not include the impact of additional awards, which may be granted, or forfeitures, which may occur subsequent to December 31, 2004 and prior to our adoption of SFAS No.123R. We expect that upon the adoption of SFAS No.123R, we will apply the modified prospective application transition method, as permitted by the Statement. Under such transition method, upon the adoption of SFAS No.123R, our consolidated financial statements for periods prior to the effective date of the Statement will not be restated. We do not expect SFAS No. 123R to have a material impact on our results of operations and financial position in future periods.
Inventory Costs
In November 2004, the FASB issued SFAS No. 151, Inventory Costs - an amendment of ARB 43, Chapter 4. SFAS No.151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. This Statement requires that those items be recognized as current period charges. In addition, this Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No.151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005 (January 1, 2006 for us). Earlier application of SFAS No.151 is permitted. The provisions of SFAS No.151 shall be applied prospectively. We do not expect SFAS No.151 to have a material impact on our results of operations and financial position in future periods.
Exchange of Non-monetary Assets
In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets - An Amendment of APB Opinion No. 29. SFAS No. 153 amends APB Opinion No. 29, Accounting for Non-monetary Transactions. The amendments made by SFAS No. 153 are based on the principle that exchanges of non-monetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the exception for non-monetary exchanges of similar productive assets and replace it with a general exception for exchanges of non-monetary assets that do not have commercial substance. The provisions in SFAS No.153 are effective for non-monetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 (July 1, 2005 for us). Early application of SFAS No. 153 is permitted. The provisions of SFAS No.153 shall be applied prospectively. We do not expect SFAS No.153 to have a material impact on our results of operations and financial position in future periods.
Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock
In July 2004, the FASB issued EITF Issue No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock. EITF Issue No. 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF Issue No. 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of the investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The provisions in EITF Issue No. 02-14 are effective for reporting periods beginning after September 15, 2004 (October 1, 2004 for us). The adoption of EITF Issue No. 02-14 by us did not have any our impact on our results of operations and financial position.
Results of Operations
Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different periods described below may be of limited value, as a result of the effects on our historical operating results of each of the following: (i) our recent acquisitions and enhancements of acquired projects, (ii) the sale of our investment in Karaganda Holding Company, which we refer to as KHC, in the third quarter of 2002, which owned and operated two coal fired power plants in Kazakhstan, and (iii) fluctuation in revenues of our Products Segment.
Comparison of the Year Ended December 31, 2004 and the Year Ended December 31,
Total Revenues
Total revenues for the year ended December 31, 2004 were $219.2 million, as compared with $119.4 million for the year ended December 31, 2003, which represented an 83.5% increase in total revenues. This increase is primarily attributable to additional revenues being generated from the Heber 1 and 2 projects, which we acquired in December of 2003, the Steamboat 2/3 project, which we acquired on February 13, 2004, the Steamboat Hills project, which we acquired on May 20, 2004 and
the Puna project, which we acquired on June 3, 2004. Such increase in revenues was also due to an additional $18.7 million generated by our Products Segment during 2004.
Electricity Segment
Revenues attributable to our Electricity Segment for the year ended December 31, 2004 were $158.8 million, as compared with $77.8 million for the year ended December 31, 2003, which represented a 104.3% increase in such revenues. As noted above, such increase is principally due to our acquisition activities. The decrease in revenues from other projects is due to the deconsolidation of the Leyte project as of April 1, 2004, which represented $12.6 million of our revenues for the year ended December 31, 2003, versus only $3.1 million of our revenues for the year ended December 31, 2004.
Products Segment
Revenues attributable to our Products Segment for the year ended December 31, 2004 were $60.4 million, as compared with $41.7 million for the year ended December 31, 2003, which represented a 44.9% increase in such revenues. This increase resulted from added revenues of $18.7 million, principally attributable to two large geothermal projects (Mokai and Wairakei) during the year ended December 31, 2004. Such increase reflects the fluctuation of the revenues generated from our Products Segment.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2004 was $136.1 million, as compared with $76.2 million for the year ended December 31, 2003, which represented a 78.5% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2004 and the year ended December 31, 2003 were 62.1% and 63.8%, respectively.
Electricity Segment
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2004 was $89.7 million, as compared with $46.7 million for the year ended December 31, 2003, which represented a 92.1% increase in cost of revenues for such segment. The year ended December 31, 2004 included $35.2 million, $7.8 million, $2.0 million and $6.5 million, respectively, of cost of revenues attributable to the Heber 1 and 2 projects, the Steamboat 1/1A and Steamboat 2/3 projects, the Steamboat Hills project and the Puna project, as compared to the year ended December 31, 2003, during which such projects were not included in our results of operations (other than a minimal amount in connection with the cost of revenues for Heber 1 and 2 projects in December 2003). As a percentage of total electricity revenues, total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2004 (56.5%) was slightly lower than the percentage for the year ended December 31, 2003 (60.1%) because as a percentage of revenues, total cost of revenues for our newly acquired projects were slightly lower than the projects in our portfolio prior to such acquisitions. This was offset slightly by the deconsolidation of the Leyte project as of April 1, 2004, for which the cost of revenues as a percentage of total Electricity Segment revenues for the year ended December 31, 2003, was 45.7%, which is lower than the average cost of revenues.
Products Segment
Total cost of revenues attributable to our Products Segment for the year ended December 31, 2004 was $46.3 million, as compared with $29.5 million for the year ended December 31, 2003, which represented a 57.1% increase in cost of revenues related to such segment. Such $16.8 million increase in cost of revenues during the year ended December 31, 2004 was due to an increase in the volume of sales, as compared to the year ended December 31, 2003. As a percentage of total products revenues, our total cost of revenues attributable to our Products Segment for the year ended December 31, 2004 was 76.7% and for the year ended December 31, 2003 was 70.7%. The lower percentage of cost of revenues in 2003 resulted from the cancellation of a provision recorded in 2002 for the construction of a project following negotiations with a customer.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2004 were $2.2 million, as compared with $1.4 million for the year ended December 31, 2003, which represented a 56.4% increase in research and development expenses. Such increase was in the ordinary course of our operations and does not represent any significant change in our research and development program or our ability to maintain and continue to develop our technologies and operations, and reflects fluctuations in the period in which actual expenses were incurred.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2004 were $7.8 million, as compared with $7.1 million for the year ended December 31, 2003, which represented a 9.6% increase due to an increase in activities. Selling and marketing expenses for the year ended December 31, 2004 constituted 3.5% of total revenues for such year, as compared with 5.9% for the year ended December 31, 2003. Such 2.4% decrease is principally attributable to the fixed cost nature of certain of our selling and marketing expenses as compared to a larger revenue base. The larger revenue base was principally attributable to an increase in the revenues generated by our Electricity Segment. Once a project is in operation and generates electricity, selling and marketing expenses attributable to such project are relatively insignificant.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2004 were $11.6 million, as compared with $9.3 million for the year ended December 31, 2003, which represented a 25.5% increase in general and administrative expenses. Such increase was principally attributable to an increase in professional services fees related to our business development activities in the United States. General and administrative expenses for the year ended December 31, 2004 constituted 5.3% of total revenues for such year, as compared with 7.7% for the year ended December 31, 2003. Such 2.4% decrease is attributable to the fixed cost nature of certain of our general and administrative expenses as compared to a larger revenue base. We expect our general and administrative expenses to further increase in 2005 as a result of additional professional services fees, additional personnel expenses and other administrative expenses, as a result of being a public company whose shares are traded on the New York Stock Exchange.
Gain on Sale of Geothermal Resource Rights
On December 17, 2004, we sold a subsidiary that had a concession over the geothermal field relating to the San Vicente project and the Chanameca project in El Salvador to a local company for $2.4 million net of transaction costs. As a result of the sale we recognized a gain of $0.8 million.
Interest Expense
Interest expense for the year ended December 31, 2004 was $42.8 million, as compared with $8.1 million for the year ended December 31, 2003, which represented a 426.9% increase in such interest
expense. Approximately $13.3 million of such increase was attributable to the interest expenses incurred by certain of our subsidiaries in connection with the Beal Bank financing (including $1.6 million of marked to market expenses relating to an interest rate cap agreement through September 30, 2004) and approximately $14.8 million of such increase was attributable to the interest expenses incurred in connection with the issuance by Ormat Funding, on February 13, 2004, of $190.0 million of Senior Secured Notes, in addition, in the year ended December 31, 2004, we incurred $0.6 million of additional amortization of deferred financing costs as a result of our early repayment of the Ormesa loan on December 31, 2004. See "-Liquidity and Capital resources". The remaining $5.7 million increase was mainly attributable to an increase in parent company loans. We do not expect a significant increase in our interest expense in 2005, other than costs which may be incurred if Puna's refinancing is in a form other than an operating lease.
Income Taxes
Income taxes for the year ended December 31, 2004 were $6.6 million, as compared with $2.5 million for the year ended December 31, 2003, which represented a 163.7% increase in such income taxes. The effective tax rate for the years ended December 31, 2004 and 2003 was 31.6% and 13.8%, respectively. For the year ended December 31, 2004, our effective tax rate was reduced by approximately 2.4% as a result of lower tax rate in certain of our foreign operations (such as Nicaragua). For the year ended December 31, 2003, our effective tax rate was reduced by approximately 8.4% as a result of the application of investment tax credits. In addition, our foreign tax rates were substantially lower than our U.S. tax rates due primarily to the tax holiday in the Philippines that applied to us, and the reversal of a deferred tax valuation allowance related to the realization of net operating losses in Ormat Systems which decreased our effective tax rate by approximately 5.6 %.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2004 was $3.6 million (net of tax expense in the amount of $0.9 million), as compared with $0.6 million for the year ended December 31, 2003, which represented a 538.1% increase. Such increase was principally attributable to: (i) the income generated in connection with our 50% equity interest in the Mammoth project, which was acquired in December 2003 and which accounted for $1.5 million of such income for the year ended December 31, 2004, (ii) income generated in connection with our 80% equity interest in the Ormat Leyte project which was deconsolidated as of April 1, 2004 (as a result of the application of FIN No. 46R) and which accounted for $1.5 million and (iii) $0.1 million from the increase in the profits of the Zunil project.
Net Income
Net income for the year ended December 31, 2004 was $17.8 million, as compared with $15.5 million for the year ended December 31, 2003, which represented an increase of 15.1% in our net income. Net income as a percentage of our total revenues for the year ended December 31, 2004 was 8.1%, as compared with 12.9% for the year ended December 31, 2003. Such decrease in percentage was principally attributable to an increase in our interest expenses relating to the financing of the acquisition of the Heber 1 and 2 projects and the Steamboat 2/3 project, and the refinancing of existing projects, offset by the increase in gross margin due to these projects.
Comparison of the Year Ended December 31, 2003 and the Year Ended December 31, 2002
Total Revenues
Total revenues for the year ended December 31, 2003 were $119.4 million, as compared with $85.6 million for the year ended December 31, 2002, which represented a 39.5% increase in our total revenues. Such increase was principally attributable to the receipt of additional revenues generated by the Ormesa project that was acquired on April 15, 2002 and the increase in revenues generated from the sale and installation of equipment to power plants worldwide.
Electricity Segment
Revenues from the sale of electricity for the year ended December 31, 2003 were $77.8 million, as compared with $65.5 million for the year ended December 31, 2002, which represented an 18.8% increase in such revenues. Such increase was a result of: (i) the acquisition of the Ormesa project in April of 2002, which for the full fiscal year ended December 31, 2003 generated $30.5 million of revenues, as compared to $21.8 million for the eight months of operation in 2002 following its acquisition; (ii) $2.0 million of revenues generated by the Heber 1 and 2 projects for the 13-day period ended December 31, 2003, as compared with no revenues attributable to such projects in 2002; and (iii) $1.0 million of revenues generated by the Steamboat 1/1A project as compared with no revenues attributable to such project in 2002. The increase in our revenues for the year ended December 31, 2003, as compared to the year ended December 31, 2002, would have been higher but for the one-time addition to the revenues received in 2002 in the amount of $2.7 million, as a result of a disputed performance bonus that was resolved and recognized in 2002.
Products Segment
Revenues from our Products Segment for the year ended December 31, 2003 were $41.7 million, as compared with $20.1 million for the year ended December 31, 2002, which represented a 107.5% increase in such revenues. Such increase resulted primarily from $14.0 million of revenues primarily attributable to two large projects (Mokai and Miravalles) and the sale of products, services and parts for the year ended December 31, 2003. Such increase reflects the fluctuation of the revenues generated from our Products Segment.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2003 was $76.2 million, as compared with $50.8 million for the year ended December 31, 2002, which represented a 50.0% increase. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2003 was 63.8%, as compared to 59.3% for the year ended December 31, 2002. This increase is explained below.
Electricity Segment
Cost of revenues attributable to our Electricity Segment for the year ended December 31, 2003 was $46.7 million, as compared with $33.5 million for the year ended December 31, 2002, which represented a 39.4% increase for such cost of revenues. Such increase was principally attributable to the acquisition of the Ormesa project, as cost of revenues for the year ended December 31, 2003 included expenses of the Ormesa project in the amount of $23.3 million, as compared to $15.7 million for the year ended December 31, 2002. The Ormesa project had higher operating expenses than the other projects we operated at such time due to additional transmission costs relating to the transmission of electricity over the Imperial Irrigation District transmission system and the type of equipment used in the Ormesa project, which is more costly to operate and maintain than the equipment used in our other projects that existed at the time of such acquisition. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment was 60.1% for the year ended December 31, 2003 as compared to 51.1% for the year ended December 31, 2002.
Such increase, on a percentage basis, was partially attributable to $2.7 million of revenues received as a result of a one-time disputed performance bonus that was resolved and recognized in 2002.
Products Segment
Cost of revenues attributable to our Products Segment for the year ended December 31, 2003 was $29.5 million, as compared with $17.3 million for the year ended December 31, 2002, which represented a 70.5% increase in such cost of revenues. Such $12.2 million increase in cost of revenues was attributable to the generation of additional revenues from the sale of our equipment during the year ended December 31, 2003. As a percentage of our total Products Segment revenues, our cost of revenues attributable to our Products Segment for the year ended December 31, 2003 was 70.7% as compared to 85.9% for the year ended December 31, 2002. Such 15.2% decrease was primarily attributable to a 107.5% increase in our Products Segment revenues as compared to the fixed nature of much of our cost of revenues, such as salaries, depreciation, expenses related to maintaining operations, utilities and property expenses.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2003 were $1.4 million, as compared with $1.5 million for the year ended December 31, 2002, which represented a 6.7% decrease in such research and development expenses. Such decrease reflects a fluctuation in the ordinary course of our business and does not represent a significant change in our research and development program or our ability to maintain and continue to develop our technologies and operations.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2003 were $7.1 million, as compared with $6.1 million for the year ended December 31, 2002, which represented a 16.4% increase in such selling and marketing expenses. Selling and marketing expenses for the year ended December 31, 2003 represented 5.9% of our total revenues, as compared to 7.1% for the year ended December 31, 2002. Such 1.2% decrease is a result of the effect of the fixed cost component of our selling and marketing expenses over a larger revenue base. The larger revenue base was principally attributable to an increase in the revenues generated by our Electricity Segment. Once a project is in operation and generates electricity, selling and marketing expenses are relatively insignificant.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2003 were $9.3 million, as compared with $7.1 million for the year ended December 31, 2002, which represented a 31.0% increase in general and administrative expenses. Such increase was attributable to costs related to an increase in our personnel, wages and professional services and other costs related to our business development activities in the United States which were primarily related to the pursuit and consummation of the acquisition of the Heber 1 and 2 projects and our 50% ownership interest in the Mammoth project. As a percentage of our total revenues, general and administrative expenses were 7.7% of such revenues for the year ended December 31, 2003 and 8.3% of such revenues for the year ended December 31, 2002.
Interest Expense
Interest expense for the year ended December 31, 2003 was $8.1 million, as compared with $6.2 million for the year ended December 31, 2002, which represented an increase of 30.6% in our total interest expense. Such increase resulted from $1.9 million of interest expense incurred in connection with the United Capital project finance loan incurred on December 31, 2002 by our project subsidiary to refinance the Ormesa acquisition, $0.8 million of interest expense incurred in connection with outstanding parent company loans, and $0.4 million of interest expense incurred in connection with the Beal Bank loan incurred on December 18, 2003, in order to finance the acquisition of the Heber 1 and 2 projects and the Mammoth project. Interest expenses related to certain other bank loans decreased by $1.2 million for the year ended December 31, 2003 due to a decrease in outstanding corresponding balances.
Income Taxes
Income taxes for the year ended December 31, 2003 were $2.5 million, as compared with $6.1 million for the year ended December 31, 2002, which represented a decrease of 59.0% in such income taxes. The effective tax rate for the years ended December 31, 2003 and 2002 was 13.8% and 39.5%, respectively. For the year ended December 31, 2003, our effective tax rate was reduced by approximately 8.4% as a result of the application of investment tax credits. In addition, our foreign tax rates were substantially lower than our U.S. tax rates due primarily to the tax holiday in the Philippines that applied to us and a partial reversal of a deferred tax valuation allowance related to the realization of net operating losses in Ormat Systems which decreased our effective tax rate by approximately 5.6%. For the year ended December 31, 2002, our effective tax rate was reduced by approximately 2.5% as a result of the application of investment tax credits and increased by approximately 8.0% related to a deferred tax valuation allowance applied to the net operating losses in Ormat Systems.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2003 was $0.6 million, as compared with $0.3 million for the year ended December 31, 2002, which represented an increase of 100%. Such increase was principally attributable to an increase in our income derived from our 21.0% ownership of the Zunil project, which had lower debt service and therefore higher net income.
Discontinued Operations
Losses from operations of discontinued activities in Kazakhstan and losses from the sale of our Kazakhstan operations were $3.1 million and $6.4 million, respectively for the year ended December 31, 2002. The sale of our Kazakhstan operations (consisting of coal fired power plants and related assets), occurred on September 16, 2002. Such losses were recorded and reflected in our financial statements for the year ended December 31, 2002.
Net Income
Our income from continuing operations was $15.7 million in the year ended December 31, 2003, as compared to $8.5 million in year ended December 31, 2002, representing 13.1% of revenues in 2003 as compared to 9.9% of revenues in 2002. Such increase was attributable to increased revenues in both segments. Net income in 2002 was a loss of $1.0 million as a result of the loss from discontinued operations in Kazakhstan and the loss from the sale of our Kazakhstan assets. Net income in 2003 was $15.5 million.
Liquidity and Capital Resources
To date, our principal sources of liquidity have been derived from cash from operations, proceeds from parent company loans, third party debt in the form of borrowing under credit facilities, issuance of the Senior Secured Notes and project financing. We have utilized this cash to fund our acquisitions, develop and construct power generation plants and meet our other cash and liquidity needs. Most recently we have increased our liquidity position and raised capital through the issuance of shares of common stock on the public markets.
Loan Agreements with our Parent
In 2003, we entered into a loan agreement with Ormat Industries (the parent company), which was further amended on September 20, 2004. Pursuant to this loan agreement, Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150 million. The proceeds of the loan are to be used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to June 5, 2010. Interest on the loan is
calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a rate per annum equal to Ormat Industries' average effective cost of funds plus 0.3% percent in U.S. dollars, which represented a rate of 7.5% for the advances made during 2003. All computations of interest shall be made by Ormat Industries on the basis of a year consisting of 360 days. As of December 31, 2004, the outstanding balance of the loan was approximately $143.2 million.
In addition to the above loan, pursuant to the terms of a capital note, as further amended on September 20, 2004, Ormat Industries converted outstanding balances owed by us to Ormat Industries into a subordinated non-interest bearing loan in an amount equal to NIS 240.0 million. At any time after November 30, 2007 upon demand by Ormat Industries, we will be required to repay the loan in full. The final maturity of the loan is December 30, 2009. In accordance with the terms of such note, we will not be required to repay any amount in excess of $50.7 million (using the exchange rate existing on the date of such note).
Third Party Debt
Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes.
Limited and Non-Recourse Debt
OrCal Geothermal, one of our subsidiaries, entered into a non-recourse project finance loan from Beal Bank for the purpose of financing the acquisition of the Heber 1 and 2 projects and our 50% ownership interest in the Mammoth project, of which $150.6 million was outstanding as of December 31, 2004, bearing an interest rate of the greater of 7.125% or LIBOR plus 5.125% per annum. The Bank Hapoalim project finance debt, of which $17.0 million was outstanding as of December 31, 2004, bearing an interest rate of LIBOR plus 2.375% per annum on tranche one of the loan and LIBOR plus 3.0% per annum on tranche two of the loan, and the Export-Import Bank of the United States project finance debt, of which $14.0 million was outstanding as of December 31, 2004, bearing an interest rate of 6.54% per annum, were entered into by our relevant subsidiaries to finance the Momotombo project and the Leyte project (which was deconsolidated as of April 1, 2004), respectively. On December 31, 2004, Ormesa LLC, our subsidiary, repaid in its entirety a senior secured loan in the amount of $13.1 million under its credit facility with United Capital, a division of Hudson United Bank. The loan was secured by a first priority lien on the Ormesa project and this lien was released contemporaneously with the repayment of the loan. In accordance with the terms of our indenture governing the Senior Secured Notes (see below), immediately upon the repayment of the loan, Ormesa executed a guarantee of the Senior Secured Notes and granted a first priority lien on the Ormesa project and all other Ormesa assets in favor of the collateral agent for the benefit of the holders of the Senior Secured Notes. We repaid the loan with amounts set aside in a cash escrow that was funded from proceeds from the sale of the Senior Secured Notes.
Senior Secured Notes - Non-Recourse
On February 13, 2004, Ormat Funding, one of our subsidiaries, issued 8¼% Senior Secured Notes in a capital markets offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A projects, and the financing of the acquisition cost of the Steamboat 2/3 project, of which $189.5 million was outstanding as of December 31, 2004. The Senior Secured Notes are collateralized by substantially all of the assets of Ormat Funding and fully and unconditionally guaranteed by all of the wholly owned subsidiaries of Ormat Funding, and (with certain exceptions) by all real property, contractual rights, revenues and bank accounts, intercompany notes, certain insurance policies and guarantees of Ormat Funding and its subsidiaries.
There are various restrictive covenants under the Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. As of December 31, 2004, we were in compliance with the covenants under the Senior Secured Notes.
A registration statement on Form S-4 relating to the Senior Secured Notes was filed with and declared effective by the Securities and Exchange Commission on February 9, 2005. On March 16, 2005, we exchanged these unregistered notes for Senior Secured Notes with substantially identical terms that have been registered under the securities Act of 1933, as amended. Currently, there is $189,488,618 of Senior Secured Notes outstanding.
Refinancing of the Puna Project
We currently intend to refinance the acquisition cost of the Puna project by the first half of 2005. In connection with such refinancing, we signed a term sheet with an equity investor and we are currently holding negotiations with two financial institutions which we expect to provide debt financing as part of the contemplated a leverage lease financing transaction.
In anticipation of such financing, we have entered into a rate lock agreement with Lehman Brothers Special Financing, Inc. to provide interest rate protection. Such forward rate agreement and its implications are further described under "Exposure to Market Risks" below. The proceeds from the refinancing will be used for general corporate purposes and for future capital expenditures.
Full-Recourse Debt
Our full-recourse third party debt includes the following loans: (i) a $20.0 million credit facility from United Mizrahi Bank, of which $20.0 million was outstanding as of December 31, 2004, bearing an interest rate of LIBOR plus 1.2% per annum; the loan was repaid in the first quarter of 2005; (ii) a $20 million credit facility from Bank Leumi, which was repaid during the last quarter of 2004, and which bore an interest rate of LIBOR plus 1.5% per annum; (iii) medium term loans from Bank Continental, which were repaid during the last quarter of 2004. These loans bore an interest rate of LIBOR plus 1% per annum in the first half of 2004 and an interest rate of LIBOR plus 2.5% per annum in the second half of 2004; and (iv) a medium term loan from Israel's Industrial Development Bank, of which $3.3 million was outstanding as of December 31, 2004, bearing an interest rate of LIBOR plus 2.6% per annum, which was fully repaid on March 2005. Our payment obligations under such credit facilities are all currently guaranteed by our parent. In addition, our third party debt includes a medium term loan from Bank Hapoalim, of which $4.0 million was outstanding as of December 31, 2004, bearing an interest rate of LIBOR plus 1.7% per annum
In connection with our acquisition of the power generation business by Ormat Systems Ltd. from our parent, we have entered into certain agreements with each of Bank Hapoalim, Bank Leumi, United Mizrahi Bank and Israel's Industry Development Bank. Under these agreements, in exchange for such banks' release of our parent's guarantee and a release of their security interest over the assets of our subsidiary, Ormat Systems, we and Ormat Systems have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over our assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and (iii) selling, assigning, transferring, conveying or disposing of all or substantially all of our assets. In some cases, we and Ormat Systems have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. We do not expect that these covenants or ratios, which apply to us on a consolidated basis, will materially limit our ability to execute our future business plans or our operations. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.
We do not expect that any third party debt that we, or any of our subsidiaries, will incur in the future will be guaranteed by our parent.
Most of the loan agreements to which we or our subsidiaries are a party contain cross-default provisions with respect to other material indebtedness owed by us to any third party.
In 2003, one of our lenders granted a waiver with respect to the failure of our parent company for its fiscal year 2001 and 2002 to meet certain financial ratios contained in its guarantee relating to our loan agreement with such lender. We provided no consideration for such waiver. As of December 31, 2004, the balance outstanding pursuant to such loan agreement was $4.0 million.
Our management believes that we are currently in compliance with our covenants with respect to our third-party debt.
Letters of Credit and Guarantees
We also have outstanding letters of credit issued by Bank Hapoalim in the total amount of $17.8 million as of December 31, 2004.
Our subsidiary, Ormat Nevada, has also entered into a letter of credit agreement with Hudson United Bank, which is described in further detail under "Off-Balance Sheet Arrangements" below.
From time to time, Bank Leumi has issued, as security for certain of our obligations, performance letters of credit in favor of our customers. Our parent is the counterparty with respect to such letters of credit. Pursuant to certain existing agreements with our parent described elsewhere in this annual report, we are required to pay to our parent a guarantee fee with respect to such letters of credit (and other guarantees) and are responsible to reimburse our parent for any draw or payment made under these letters of credit or guarantees. As of December 31, 2004, the outstanding aggregate amount available to be drawn under these letters of credit was $8.0 million.
Dividend
In accordance with our dividend policy, prior to our initial public offering we have declared an interim dividend of $2.5 ($0.1025 million per share) for 2004 to our parent company, Ormat Industries, which has been paid on March 2, 2005. On March 22, 2005, we declared, approved and authorized the payment of a quarterly dividend of $0.03 per share which should not change until the date of payment), to all issued and outstanding shares of common stock on April 4, 2005, payable on April 18, 2005. We expect to pay a similar dividend during the next three quarters.
Historical Cash Flows
The following table sets forth the components of our cash flows for the relevant periods indicated:
For the Year Ended December 31, 2004
Net cash provided by operating activities for the year ended December 31, 2004 was $63.5 million, as compared with net cash provided by operating activities of $46.0 million for the year ended December 31, 2003. Such increase was principally attributable to the addition of cash flows from the operating activities of the Heber 1 and 2 projects, Steamboat 2/3 project, Steamboat Hills project and Puna project whose revenues during the year ended December 31, 2004 amounted to $59.7 million, $15.4 million, $15.5million and $1.8 million, respectively.
Net cash used in investing activities for the year ended December 31, 2004 was $310.6 million, as compared with $285.2 million for the year ended December 31, 2003. The principal factors that affected the cash used in investing activities during the current year were the aggregate amount of cash paid for acquisitions, net of cash received, which, for the year ended December 31, 2004, as a result of the acquisitions of the Steamboat 2/3 project, the Puna project and the Steamboat Hills project, were equal to $82.8 million, $72.8 million and $20.3 million respectively, marketable securities of $90.9 million derived from the public offering issuance proceeds, in addition to the increase in our restricted cash and cash equivalents during such year, which was equal to $9.0 million resulting
primarily from the issuance by Ormat Funding Corp. of its 8¼% Senior Secured Notes in the amount of $190.0 million. A portion of the proceeds from the issuance of such Senior Secured Notes was escrowed and reserved for additional investments for the Galena project.
Net cash provided by financing activities for the year ended December 31, 2004 was $275.0 million, as compared with $211.4 million for the year ended December 31, 2003. The principal factors that affected the cash flow provided by financing activities during the year ended December 31, 2004 were the net proceeds from the IPO of $97.0 million, the proceeds of $190.0 million from the issuance of the Senior Secured Notes in order to finance the acquisition of the Steamboat 2/3 project and to refinance the acquisition of the Ormesa, Brady, Mammoth and Steamboat 1/A projects the proceeds from the United Mizrahi Bank loan of $20.0 million and net proceeds from parent company loans in the amount of $55.3 million.
For the Year Ended December 31, 2003
Net cash provided by operating activities for the year ended December 31, 2003 was $46.0 million, as compared with $11.6 million for the year ended December 31, 2002. Such change was principally attributable to an increase in revenues, in an amount equal to $8.7 million, as a result of the acquisition of the Ormesa project and an increase in revenues, in an amount equal to $21.5 million, generated from our Products Segment.
Net cash used in investing activities for the year ended December 31, 2003 was $285.2 million, as compared with $60.5 million for the year ended December 31, 2002. The principal factors that affected the increase in the use of our cash flow for investing activities during such period included:
• Cash paid for acquisitions (net of cash received) in the amount of $256.6 million, relating to the acquisition of the Heber 1 and 2 projects and our 50% ownership interest in the Mammoth project; and
• Capital expenditures spent in connection with the Ormesa project in an amount equal to $17.0 million for the installation of new power units and the modification of the geothermal fluid gathering and electrical systems, in order to increase the capacity, reliability and availability of the Ormesa project.
Net cash provided by financing activities for the year ended December 31, 2003 was $211.4 million, as compared with $72.4 million for the year ended December 31, 2002. The principal factors that impacted our cash flow provided by financing activities during the year ended December 31, 2003 were the incurrence of a loan by OrCal in an amount of $154.5 million from Beal Bank in December 2003, and the receipt of $126.3 million of proceeds from parent company loans, less a repayment of $55.0 million of short-term debt.
Capital Expenditures
Our capital expenditures primarily relate to two principal components: the enhancement of our existing power plants and the development of new power plants. In addition, we have budgeted approximately $5.0 million for the next two years for the acquisition of machinery and equipment and for an office building.
To the extent not otherwise described below, we expect that the following enhancements of our existing power plants will be funded from internally generated cash or other available corporate resources, which we expect to subsequently refinance with non or limited recourse debt at the project level. Initially, we intend to fund the construction projects described below from internally generated cash or other available corporate resources. We currently do not contemplate obtaining any new loans from our parent company.
Mammoth Project. Mammoth-Pacific, L.P. is planning a $5 million enhancement program ($2.5 million to be funded by us) of the Mammoth project, consisting primarily of drilling activities, which we believe will result in an increase in the output of the project by 4 MW and is expected to be completed in 2006. A substantial portion of the funds required for such enhancement have been earmarked from the project's funds by us and our partners for such enhancement program. Mammoth
is currently evaluating changes to this enhancement program that may result in an additional costs of approximately $2.5 million ($1.25 million to be funded by us).
Heber Complex. In connection with the Heber 1 and 2 projects and the new Heber 3 project, we are currently pursuing a program consisting of geothermal field optimization, the drilling of an additional well and the addition of Ormat Energy Converter ("OEC") units at the Heber projects in order to increase the generating capacity of the Heber 1 and 2 projects by an estimated 18 MW, for an estimated total budgeted investment of approximately $28.0 million. As of December 31, 2004, approximately $8.0 million in costs had been incurred related to the Heber project. We expect that the program will be completed by the end of 2005.
Puna Project In connection with the Puna project, an approximately $15.5 million enhancement program is currently planned and is intended to increase the output of the project by an estimated 5 MW and to improve its reliability. We expect that such enhancement program will be completed in the fourth quarter of 2005.
Ormesa Project. In connection with the Ormesa project, we plan to drill two additional wells, add additional OEC units and replace existing units in order to increase the output of the project by an estimated 10 MW. We estimate that the costs of such enhancements will be up to $27 million. We are currently negotiating with a third party for the sale of the additional output under a long-term power purchase agreement. We expect that such enhancement program will be completed in 2006.
Galena Project. We commenced construction of the Galena project during the third quarter of 2004 and expect to complete construction and commence commercial operations in the fourth quarter of 2005. Construction costs of $23.1 million are being funded from the proceeds of Ormat Funding Corp.'s offering of Senior Secured Notes, which are currently deposited in an escrow account, and will be released in accordance with the progress of the construction phase for such enhancement. Additional costs of construction in the amount of $2 million will be funded out of available cash flow. As of December 31, 2004, approximately $5.3 million in costs had been incurred related to the Galena project. Based on the final design of the project, we plan to increase the Steamboat complex output by a total increase of 13 MW.
Desert Peak 2 Project. In connection with the Desert Peak 2 project, we have already drilled the necessary production wells and expect to begin the manufacturing and construction of the associated power plant shortly, which manufacturing and construction is expected to be completed in the fourth quarter of 2005. The total construction cost for the construction of the 15 MW power plant is estimated to be $32.5 million. As of December 31, 2004, approximately $11.1 million in costs had been incurred related to the Desert Peak 2 project.
Desert Peak 3 Project. In connection with the Desert Peak 3 project, we plan to construct a power plant in the Steamboat complex, which will supply electricity under the Desert Peak 3 power purchase agreement and expect construction of the Desert Peak 3 project to be completed in 2007. The total construction cost for the 10-15 MW power plant is estimated to be $30 million. We estimate that the Desert Peak 3 project will be constructed during 2005 and 2006.
Amatitlan Project. The Amatitlan project is scheduled to be completed in 2006 at an aggregate construction cost for the 20 MW plant is estimated to be approximately $32.5 million. As of December 31, 2004, approximately $2.8 million in costs had been incurred related to the Amatitlan project.
OREG 1 Project. The recovered energy project is scheduled to be completed in 2006, at an aggregate construction cost for the 22 MW plant of approximately $35 million. As of December 31, 2004, approximately $4.0 million in costs had been incurred in relation to this project.
In addition to the above projects, we plan to start the construction and enhancement of additional projects for a total amount of approximately $10 million.
Other than the enhancements and new projects described above, and a possible further enhancement to the Ormesa project which is in the early stages of conceptual design, we do not anticipate any other material capital expenditures in the near term for any of our operating projects, other than ordinary maintenance requirements, which we typically fund with internally generated cash.
Exposure to Market Risks
One market risk to which power plants are typically exposed is the volatility of electricity prices. Our exposure to such market risk is principally due to the fact that our long-term power purchase agreements have fixed or escalating rate provisions, that limit our exposure to changes in electricity prices. However, beginning in May 2007, the energy payments under the power purchase agreements the Heber 1 and 2 projects, the Ormesa project and the Mammoth project will be determined by reference to the relevant power purchaser's short run avoided costs. In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierrra Pacific Power Company pays for energy and capacity is based upon its short run avoided costs. We estimate that energy payments will represent approximately two-thirds of those projects' revenues after 2007 and as a result, expect that there will be some volatility in the revenues received from such projects.
As of December 31, 2004, 49.3% of our consolidated long-term debt (excluding amounts owed to our parent) was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. However, as of such date, 50.7% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. In order to mitigate such risks, we have acquired an interest rate cap of 6.0% with respect to the LIBOR component of the interest rate applicable to the Beal Bank loan from 2007 to 2011. As of December 31, 2004, $343.3 million of our debt, including $143.2 million owed to our parent, remained subject to some floating rate risk. As such, we are exposed to changes in interest rates with respect to our long-term obligations. The detrimental effect on our pre-tax earnings of a hypothetical 50 basis point increase in interest rates would be approximately $0.8 million. See "Liquidity and Capital Resources" above for further discussion of our debt instruments.
In anticipation of our plans to refinance the acquisition cost of our Puna project, on December 30, 2004, we entered into a rate lock agreement with Lehman Brothers Special Financing, Inc. at a locked-in treasury rate of 4.2693%, with a notional amount of $52.0 million, terminating on February 28, 2005 (referred to as the determination date). The rate lock is based on a 10-year treasury security (referred to as the base treasury rate) that matures on August 15, 2014. Pursuant to such agreement, if the base treasury rate on the determination date is greater than 4.2693%, our counterparty will be required to pay us a floating amount; however, if the base treasury rate is less than 4.2693%, we will be required to pay to our counterparty the floating amount. If the base treasury rate equals 4.2693% on the determination date, no payment will be required to be made by either party. On February 25, 2005, we extended the rate lock agreement until March 31, 2005 at a new lock-in treasury rate of 4.31%. The extended Rate Lock is based on a 10-year treasury security that mature on February 15, 2015. There was no consideration paid by either party as a result of such extension. Based on treasury rates and the yield curve on December 31, 2004, each 1 basis point difference between the locked-in rate and the base treasury rate equalled approximately $42,000.
Another market risk to which we are exposed is primarily related to potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the new Israeli shekel. Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary's ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary's overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can arise when the currency-denomination of a particular contract is not the U.S. dollar. All of our power purchase agreements in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contacts from time to time contemplate costs which are incurred in local currencies. For example, in February 2005, we signed a large contract in the amount of approximately $25 million for a construction of a power plant which is denominated in Euros. A substantial portion of such contract will be matched by costs denominated in Euros. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. Currently, we have not used any material foreign currency exchange contracts or other derivative instruments to reduce our exposure to this risk. In the future, we may use such foreign currency exchange contracts and other derivative instruments to
reduce our foreign currency exposure, to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.
We currently maintain our surplus cash in short-term, interest-bearing bank deposits and Preferred Auctioned Rate Securities, which we refer to as PARS (deposits of entities with a minimum investment grade rating of AA (by Standard & Poor's Ratings Services)). We do not expect that a 300 basis point increase or decrease from current interest rates would have a material adverse effect on our financial position, but will have an effect on our results of operations and cash flows.
Effects of Inflation
We do not expect that the low inflation environment of recent years in most of the countries in which we operate will continue. To address rising inflation, some of our contracts include certain mitigating factors against any inflation risk. In connection with the Electricity Segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. The negative impact of inflation may be partially offset by price adjustments built into some of our power purchase agreements that could be triggered upon such occurrences. Energy payments pursuant to the power purchase agreements for the Mammoth project (after April 2007), Ormesa project (after April 2007), Heber1 and 2 projects (after April 2007) and Steamboat 1/1A project will change because of our power purchasers' underlying short run avoided costs. To the extent that inflation causes an increase in those short run avoided costs, higher energy payments could have an offsetting impact to any inflation-driven increase in our expenses. Similarly, the energy payments pursuant to the power purchase agreements for the Brady project, Steamboat 2/3 project, the Steamboat Hills project and the Galena project increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation.
The recent price increase in the cost of raw materials that we use in our Products Segment has not been due to inflation, but rather to a high demand for such raw materials which we believe mainly to result from demand generated by the Chinese market. This increase may cause a reduction in the profitability of our Products Segment, as well as an increase in the capital costs of our projects under construction and enhancement.
Overall, we believe that the impact of inflation on our business will not be significant.
Contractual Obligations and Commercial Commitments
The following table sets forth our material contractual obligations as of December 31, 2004, excluding interest (in thousands):
The following table sets forth our interest payments payable in connection with our contractual obligations as of December 31, 2004 (in thousands):
Interest on the Senior Secured Notes due in 2020 is fixed at a rate of 8.25%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates). Accordingly, for purposes of the above calculation of interest payments pertaining to variable rate debt, the methodology used to determine future LIBOR rates was the use of Constant Maturity Swaps.
Off-Balance Sheet Arrangements
On June 30, 2004, our subsidiary, Ormat Nevada, entered into a Letter of Credit Agreement with Hudson United Bank, pursuant to which Hudson United Bank agreed to issue one or more letters of credit in an aggregate face amount of up to $15.0 million. As of the date hereof, two letters of credit have been issued pursuant to this facility. The first was issued in favor of the trustee for the 8¼% Senior Secured Notes, for a face amount of $8.1 million, which was increased by an additional amount of $2.7 million on December 30, 2004. The second was issued in favor of Beal Bank, for a face amount of $3.6 million. Such letters of credit have been issued to substitute for current cash balances in respective reserve accounts. The unrestricted cash resulting from this exchange is being used for working capital and reductions of outstanding bank debt. In the event that the bank is required to pay on a letter of credit drawn by the beneficiary thereof, such letter of credit converts to a loan, bearing interest at LIBOR plus 4.0%, and matures on the next expiration date of the Letter of Credit Agreement. There are various restrictive covenants under the Letter of Credit Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, and minimum coverage ratio. Our management believes that we are currently in compliance with our covenants.
On July 15, 2004, we entered into a reimbursement agreement with Ormat Industries, pursuant to which we agreed to reimburse Ormat Industries for any draws made on any standby letter of credit issued by Ormat Industries that is subject to the guarantee fee agreement between us and Ormat Industries, and any payments made under any guarantee provided by Ormat Industries subject to such
agreement. Interest on any amounts owing pursuant to the reimbursement agreement is paid in U.S. dollars at a rate per annum equal to Ormat Industries' average effective cost of funds plus 0.3%, which currently amounts to 7.5%.
Some of our customers require our project subsidiaries to post letters of credit in order to guarantee their respective performance under relevant contracts. We are also required to post letters of credit to secure our obligations under various leases and licenses and may, from time to time, decide to post letters of credit in lieu of cash deposits in reserve accounts under certain financing arrangements. In addition, our subsidiary, Ormat Systems, is required from time to time to post performance letters of credit in favor of our customers with respect to orders of products.
Bank Hapoalim has issued such performance letters of credit in favor of our customers from time to time. Initially, our parent, Ormat Industries, was Bank Hapoalim's counterparty on such letters of credit and we paid our parent a guarantee fee and were responsible to reimburse our parent for any draw under these letters of credit. In connection with the acquisition transaction of the power generation business by Ormat Systems from our parent, we have assumed such letters of credit and are now the direct counterparty of Bank Hapoalim on such letters of credit. As of December 31, 2004, the aggregate amount available to be drawn under these letters of credit was $17.8 million. The amount that can be drawn under some of these letters of credit may be increased from time to time, subject to the satisfaction of certain conditions.
As of the date hereof, we have not had a draw presented against any letter of credit issued or provided on our behalf.
Concentration of Credit Risk
Our credit risk is currently concentrated with a limited number of major customers: Sierra Pacific Power Company, Southern California Edison Company, Hawaii Electric Light Company, PNOC-Energy Development Corporation, The Kenya Power and Lighting Company Limited and two electricity distribution companies which are assignees of Empresa Nicaraguense de Electricidad. If any of these electric utilities fails to make payments under its power purchase agreements with us, such failure would have a material adverse impact on our financial condition.
Historically, Southern California Edison Company accounted for 41.4%, 26.6% and 25.5% of our total revenues for the three years ended December 31, 2004, 2003 and 2002, respectively. Southern California Edison Company is also the power purchaser and revenue source for our Mammoth project, which we account for separately under the equity method of accounting.
Sierra Pacific Power Company accounted for 12.9%, 9.5% and 11.2% of our total revenues for the three years ended December 31, 2004, 2003 and 2002, respectively.
PNOC-Energy Development Corporation accounted for 1.4%, 10.6% and 18.2% of our total revenues for the three years ended December 31, 2004, 2003 and 2002, respectively.
The two electric distribution companies which are assignees of Empresa Nicaraguense de Electricidad accounted for 5.1%, 9.7% and 10.8% of our total revenues for the three years ended December 31, 2004, 2003 and 2002, respectively.
The Kenya Power & Lighting Co. Ltd. accounted for 4.5%, 8.1% and 10.8% of our total revenues for the years ended December 31, 2004, 2003 and 2002, respectively.
Following the acquisition of the Puna project, Hawaii Electric Light Company has become one of our key customers, accounting for approximately 7.1% of our total revenues for the year ended December 31, 2004.
Government Grants and Tax Benefits
Our subsidiary, Ormat Systems, has received "Approved Enterprise" status under Israel's Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. One such approval was received in 1996 and the other was received in May 2004. As an Approved
Enterprise, our subsidiary is exempt from Israeli income taxes with respect to income 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 income is subject to reduced Israeli income tax rates of 25.0% for an additional five years. These benefits are subject to certain conditions set forth in the certificate of approval from Israel's Investment Center including, among other things, a requirement that Ormat Systems comply with Israeli intellectual property law, that all transactions between Ormat Systems and our affiliates be at arms length, and that there will be no change in control of more than 49% of Ormat Systems' capital stock (including by way of a public offering) on a cumulative basis without the prior written approval of the Investment Center.
Prior to 2003, our research and development efforts were partially funded through grants from the Office of the Chief Scientist of the Israeli Ministry of Industry, Trade and Labor. We currently have no such grants available or outstanding. Under Israeli law, we are required to pay royalties to the Israeli government based on revenues derived from the sale of products developed with the assistance of such grants. The applicable royalty rate is between of 3.5% to 5.0%, and the amount of royalties required to be paid are capped at the amount of the grants received (in U.S. dollars). The outstanding balance of grants provided after January 1, 1999 accrue interest at a rate equal to the 12-month LIBOR, as published on the first day of the calendar year in which the particular grant was approved. Because the royalties are payable only from revenues, if any, derived from the relevant products, we only recognize a royalty expense to the government upon delivery of the product to our customers.
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 72.4% of our total revenues for the year ended December 31, 2004 from the sale of electricity. The cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:
• regular and unexpected maintenance and replacement expenditures;
• shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;
• labor disputes;
• the presence of hazardous materials on our project sites; and
• catastrophic events such as fires, explosions, earthquakes, 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.
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.
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. The temperature of the geothermal resource at our Heber 1 project has declined since the project commenced operations and, as a result, the project was operating at a level that is close to the minimum performance requirements set forth in the project's power purchase agreement. 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.
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 despite the expenditure of significant amounts of capital.
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, Guatemala and China, and we intend to pursue the expansion of some of our existing plants and the development of other new plants. Our completion of these facilities is subject to substantial risks, including:
• unanticipated cost increases;
• shortages and inconsistent qualities of equipment, material and labor;
• work stoppages;
• inability to obtain permits and other regulatory matters;
• failure by key contractors and vendors to timely and properly perform;
• adverse environmental and geological conditions (including inclement weather conditions); and
• our attention to other projects;
any one of which could give rise to delays, cost overruns, the termination of the plant expansion, construction or development or the loss (total or partial) of our interest in the project under development, construction or expansion.
We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations.
Our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. As of December 31, 2004, we had approximately $578.4 million of total consolidated indebtedness (including indebtedness to our parent company in the amount of $193.9 million), of which approximately 61.2% 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 $82.1 million for the year ended December 31, 2004, which represented 37.4% 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. 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 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, there is potential labor unrest and strengthening of labor unions, which may adversely affect our Momotombo project. In Kenya, the new government elected in 2002 is making an effort to deliver on campaign promises to reduce the price of electricity and is applying pressure on independent power producers, such as our Olkaria III project, to lower their tariffs. In addition, Kenya's new government is considering a further restructuring and privatization of the electricity industry and may divide Kenya Power & Lighting Co. Ltd., the power purchaser for our Olkaria III project, into separate entities and then privatize one or more of such resulting entities. A material tariff reduction or any break-up and potential privatization of Kenya Power & Lighting Co. Ltd. may adversely affect our Olkaria III project. We have recently held discussions with the Kenyan government and Kenya Power & Lighting Co. Ltd. regarding, among other things, the construction of Phase II of the Olkaria III project in Kenya and the provision of certain collateral and the strengthening of government support. The request for strengthened government support has not been accepted to date by the Kenyan government. Upon implementation, we expect Phase II to add approximately 35 MW in generating capacity to the current Olkaria III project. In preparation for the release of Phase II, we have recently asked Kenya Power & Lighting Co. Ltd. to provide the necessary collateral. We must notify Kenya Power & Lighting Co. Ltd., by April 17, 2005, whether we will proceed to construct Phase II of the Olkaria III project and, if we notify Kenya Power & Lighting Co. Ltd. that we will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If we fail to provide such notification we will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. In addition, if we do not proceed with the construction of Phase II, we may lose some or all of our investment relating to Phase II, which is approximately $20.9 million as of December 31, 2004.
Although we generally obtain political risk insurance in connection with our foreign projects, such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the 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 Company, Hawaii Electric Light Company, and Sierra Pacific Power Company have accounted for 41.4%, 7.1% and 12.9%, respectively, of our revenues for the year ended December 31, 2004. 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 Company withheld payments it owed under various of its power purchase agreements with a number of power generators (such as the Ormesa, Heber 1 and 2, and Mammoth projects) payable for certain energy delivered between November 2000 and March 2001 under such power purchase agreements until March 2002. In the case of our Ormesa project (which we acquired in April 2002), such payments were withheld by Southern California Edison Company for some period of time prior to our purchase. If any of the power purchasers fails to meet its payment obligations under its power purchase agreements, it could materially and adversely affect our business, financial condition, future results and cash flow.
In connection with the power purchase agreements for the Ormesa project, Southern California Edison Company has expressed its intent not to pay the contract rate for the power supplied by the GEM 2 and GEM 3 plants to the Ormesa project for auxiliary purposes. We have commenced discussions with Southern California Edison Company to resolve the dispute. In the interim period, Southern California Edison Company has tentatively agreed to pay a lower fixed price for such power. We cannot evaluate the potential long-term financial impact of a failure to reach a resolution with Southern California Edison Company, among other things because the current contract rates will fluctuate as of May 2007; however, financial loss at the reduced price paid by Southern California Edison Company for our fiscal year ended December 31, 2005 may be in the range of $1 million.
Seasonal variations may cause significant fluctuations in our cash flows, which may cause the market price of our common stock to fall in certain periods.
Our results of operations are subject to seasonal variations. This is primarily because some of our domestic projects receive higher capacity payments under the relevant power purchase agreements during the summer months, and due to the generally higher short run avoided costs in effect during the summer months. Some of our other projects may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, future results and cash flow. If our operating results fall below the public's or analysts' expectations in some future period or periods, the market price of our common stock will likely fall in such period or periods.
Pursuant to the terms of some of our power purchase agreements with investor-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity thereunder may result in the imposition of penalties.
Pursuant to the terms of the Galena, Desert Peak 2 and Desert Peak 3 power purchase agreements that we have entered into and under which we will sell electricity from the Galena, Desert Peak 2 and Desert Peak 3 projects that are currently under development and construction, we may be required to make payments to the relevant power purchaser in an amount equal to such purchaser's replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the power purchase agreement and which such power purchaser is forced to obtain from an alternate source. These three power purchase agreements are expected to phase-in and commence generating revenues starting in 2006. When all three are generating revenues, measured against our revenues from the sale of electricity for the year ended December 31, 2004 and assuming no other changes in our revenues, the revenues from such agreements would have constituted, collectively, less than 8% of our total revenues from the sale of electricity. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant power purchase agreement. We may also be required to pay liquidated damages if certain minimum performance requirements are not met under certain of our power purchase agreements, all of which could materially and adversely affect our business, financial condition, future results and cash flow. With respect to certain of our power purchase agreements, we may also be required to pay liquidated damages to our power purchaser if the relevant project does not maintain availability of at least 85% during applicable peak periods. The maximum aggregate amount of such liquidated damages for the Steamboat 2 and Steamboat 3 power purchase agreements would be approximately $1.5 million for each project. The Puna project was not in compliance with the minimum performance requirements of its power purchase agreement at the time we acquired such project, and is currently not in compliance with such requirements. Such non-compliance has resulted in the imposition of sanctions that have reduced, and as long as such non-compliance continues to exist, will continue to reduce, the aggregate amount of revenues payable to us from the power purchaser by approximately $6,000 per month. Further, the temperature of the geothermal resource at our Heber 1 project has declined from the date on which the project commenced operations and, as a result, the project had been operating at a level that is close to the minimum performance requirements set forth in the project's power purchase agreement.
The short run avoided costs for our power purchasers may decline, which would reduce our project revenues and could materially and adversely affect our business, financial condition, future results and cash flow.
Under the power purchase agreements for our projects in California, the price that Southern California Edison Company pays for energy is based upon its short run avoided costs, which are the incremental costs that it would have incurred had it generated the relevant electrical energy itself or purchased such energy from others. Under settlement agreements between Southern California Edison Company and a number of Qualifying Facility power generators in California, including our subsidiaries, the energy price component payable by Southern California Edison Company has been fixed through April 2007, and thereafter will be based on Southern California Edison Company's short run avoided costs, as determined by the California Public Utilities Commission, which we refer to as CPUC. These short run avoided costs are made available by Southern California Edison Company to the public and may vary substantially on a monthly basis, based primarily on natural gas prices and other factors. The levels of short run avoided cost prices paid by Southern California Edison Company may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison Company under our power purchase agreements with it and could materially and adversely affect our business, financial condition, future results and cash flow.
In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierra Pacific Power Company pays for energy and capacity is based upon its short run avoided costs. These short run avoided costs, and in turn the rates payable by Sierra Pacific Power Company,
may decline, which in turn would reduce the aggregate amount of project revenues recovered by our Nevada projects pursuant to the relevant power purchase agreements. Such a decrease in project revenues could adversely affect our business, financial condition, future results and cash flow.
In response to an order issued by a California State Court of Appeals, the CPUC has commenced an administrative proceeding in order to address short run avoided cost pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The court directed the CPUC to modify short run avoided cost pricing on a retroactive basis to the extent that the CPUC determined that short run avoided cost prices were not sufficiently "accurate" or "correct". On February 15, 2005 the CPUC issued a draft decision affirming that short run avoided cost prices during the disputed period were correct and in compliance with PURPA requirements and that no retroactive adjustments are warranted. Comments on the draft may be filed and a final decision from the CPUC could be issued in late March or early April 2005. If the short run avoided cost prices charged during the period in question were determined by the CPUC not to be "accurate" or "correct," retroactive price adjustments could be required for any of our Qualifying Facilities in California whose payments are tied to short run avoided cost pricing, including the Heber 1, Mammoth and Ormesa projects. Currently, it is not possible to predict the outcome of such proceedings; however, any retroactive price adjustment required to be made in relation to any of our projects may require such projects to make refund payments or charge less for future sales, which could materially and adversely affect our business, financial condition, future results and cash flow.
If any of our domestic projects loses its Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to our Qualifying Facilities, our domestic operations could be adversely affected.
The operations of most of our domestic projects are subject to, and benefit from, the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, are subject to limited provisions of the Federal Power Act, which we refer to as FPA, and are potentially subject to the provisions of various other energy laws and regulations, including the Public Utility Holding Company Act of 1935, as amended, which we refer to as PUHCA, other provisions of the FPA and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.
Qualifying Facility status under PURPA exempts our projects from PUHCA, most of the provisions of the FPA, and certain state laws concerning rates and the financial and organizational regulation of electric utilities. If any of our domestic projects in which we have an interest loses its Qualifying Facility status and no regulatory exemptions apply, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded Qualifying Facilities, our operations could be adversely affected.
In the event that one of our domestic projects loses its Qualifying Facility status, such project and we would become subject to PUHCA and such project would become subject to the full scope of the FPA and applicable state regulations unless an exemption or waiver applies, such as "exempt wholesale generator" ("EWG", as defined under PUHCA) status or "utility geothermal small power production facility" (as defined under PURPA regulations) status, for such project. EWG status would protect the project and us against PUHCA regulation, but would not exempt the project from FPA or state regulation. The application of PUHCA and such other regulations to our projects would require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. In the unlikely event that none of the PUHCA exemptions or waivers are available, we could become a public utility holding company under PUHCA, which could be deemed to occur prospectively or retroactively to the date that any of our projects lost its Qualifying Facility status. In addition, our other domestic projects could lose Qualifying Facility status because our interests in such projects could be considered to be electric utility holding company interests for purposes of the 50% limit on ownership of Qualifying Facilities by electric utilities or electric utility holding companies. As a result of such loss of Qualifying Facility status, and in the absence of an applicable exemption or waiver, the Federal Energy Regulatory Commission, which we refer to as FERC, or relevant state regulators, whichever has jurisdiction, may order partial refunds of
past amounts paid by the relevant power purchaser or order a reduction of the rate pursuant to the power purchase agreement prospectively, or both, and thus could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects.
A loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreement, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our project. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.
The United States Congress is considering proposed legislation that would amend PURPA by limiting the mandatory purchase obligations of power purchasers under new power purchase agreements. The enactment of such legislation could adversely affect our new projects or enhancements of existing projects that do not have a current power purchase agreement.
A decision by the U.S. Court of Appeals to overturn a FERC decision relating to the use by a project of power generated from another Qualifying Facility for auxiliary purposes may adversely affect our operations and financial results.
According to a recent FERC decision regarding our Ormesa project, a geothermal Qualifying Facility that obtains electricity for the operation of its reinjection pumps from an electric utility must reduce its net capacity available for sale by an equivalent amount. However, the FERC decision held that if the electricity for reinjection pumping is provided by Qualifying Facilities that are cogeneration or small power production facilities, no reduction in net capacity is required. Since electricity for reinjection pumping is provided to the Ormesa project by this type of Qualifying Facility, no change in operations at the Ormesa project is required by the FERC decision. However, a petition for review of this aspect of the FERC's decision has been filed before the U.S. Court of Appeals for the District of Columbia. If the Court of Appeals were to overturn the FERC's recent decision regarding the use of electricity for reinjection pumping provided by the Qualifying Facilities that are cogeneration or small power production facilities, there could be an adverse effect on revenues received from power sales on the Ormesa facility, and thus, an adverse effect on our operations and financial results.
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" of 1.8 cents a kilowatt hour on the first five years of electricity output. (Production tax credits can only be claimed on new plants put into service between October 23, 2004
and December 31, 2005.) 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 are expected to be considered 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, 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 a result of which the operation of the projects may be limited or suspended. Environmental laws, ordinances and regulations affecting us can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us.
We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our projects.
Our projects are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use isobutane, isopentane, industrial lubricants and other substances at our projects which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the projects, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, in the United States, we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.
We believe that at one time there may have been a gas station located on the Mammoth project site, but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. There may be soil or groundwater contamination and related 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 that we have acquired or which we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.
We recently acquired our Heber 1 and 2, Mammoth, Steamboat 2/3, Steamboat Hills and Puna projects. Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:
• failure of the acquired companies to achieve the results we expect;
• inability to retain key personnel of the acquired companies;
• risks associated with unanticipated events or liabilities; and
• the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.
If any of our acquired companies suffers customer dissatisfaction or performance problems, the same could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or "spot" markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements with a capacity price component will engage in "competitive bid" solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain power purchase agreements and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.
The existence of a prolonged force majeure event or a forced outage affecting a project could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
If a project experiences a force majeure event, our subsidiary owning that project would be excused from its obligations under the relevant power purchase agreement. However, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement. Additionally, to the extent that a forced outage has occurred, the relevant power purchaser may not be required to make any capacity and/or energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to permanently reduce the contract capacity (and, correspondingly, the amount of capacity payments due pursuant to such agreements in the future),
seek refunds of certain past capacity payments, and/or prematurely terminate the power purchase agreement. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period, and may incur significant liabilities in respect of past amounts required to be refunded. Accordingly, our business, financial condition, future results and cash flows could be materially and adversely affected.
The existence of a force majeure event or a forced outage affecting the transmission system of the Imperial Irrigation District could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
If the transmission system of the Imperial Irrigation District experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber 1 and 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, 2004, from the projects utilizing the Imperial Irrigation District transmission system, were approximately $90.8 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 each of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the project located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.
In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.
We depend on key personnel for the success of our business.
Our success is largely dependent on the skills, experience and efforts of our senior management team and other key personnel. In particular, our success depends on the continued efforts of Lucien Bronicki, Yehudit "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, Yehudit "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 120 to 180 days. We may also not be able to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available.
Our projects have generally been financed through a combination of parent company loans and limited- or non-recourse project finance debt. If our project subsidiaries default on their obligations under such limited- or non-recourse debt, we may be required to make certain payments to the relevant debt holders and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our projects.
Our projects have generally been financed using a combination of parent company loans and limited or non-recourse project finance debt. Non-recourse project finance debt refers to debt that is repaid solely from the project's revenues and is secured by the project's physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited- recourse project finance debt refers to our additional agreement, as part of the financing of a project, to provide limited financial support for the project subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other projects, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other projects) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the project would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.
Changes in costs and technology may significantly impact our business by making our power plants and products less competitive.
A basic premise of our business model is that generating baseload power at central geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems,
fuel cells, microturbines, windmills and photovoltaic (solar) cells. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants; however, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our projects may be significantly impaired.
Our expectations regarding the market potential for the development of recovered energy-based power generation may not materialize, and as a result we may not derive any significant revenues from this line of business.
We have identified recovered energy-based power generation as a significant market opportunity for us. Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future. If this market does not materialize at the levels that we expect, such failure may materially and adversely affect our business, financial condition, future results and cash flow.
Our intellectual property rights may not be adequate to protect our business.
Our intellectual property rights may not be adequate to protect our business. While we occasionally file patent applications, patents may not be issued on the basis of such applications or, if patents are issued, they may not be sufficiently broad to protect our technology. In addition, any patents issued to us or for which we have use rights may be challenged, invalidated or circumvented.
In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.
Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties' patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management's attention from our core business.
We are subject to risks associated with a changing economic and political environment, which may adversely affect our financial stability or the financial stability of our counterparties.
The risk of terrorist attacks in the United States or elsewhere continues to remain a potential source of disruption to the nation's economy and financial markets in general. The availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corp. and events related to the California electric market crisis. Additionally, the recent rise in fuel costs may make it more expensive for our customers to operate their businesses. These events could constrain the capital available to our industry and could adversely affect our financial stability and the financial stability of our transaction counterparties.
Possible fluctuations in the cost of raw materials may materially and adversely affect our business, financial condition, future results and cash flow.
Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminium, and on the supply of various industrial equipment components that we use. We currently obtain all such materials and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. Future cost increases of such raw materials and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.
Conditions in Israel, where the majority of our senior management and all of our production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our projects.
Operations in Israel accounted for approximately 25.6%, 51%, and 56.3% of our operating expenses in the year ended December 31, 2004, 2003 and 2002, respectively. Political, economic and security conditions in Israel directly affect our operations. Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel. Since October 2000, there has been a significant increase in violence, primarily in the West Bank and Gaza Strip, and more recently Israel has experienced a significant increase in terrorist incidents within its borders. As a result, negotiations between Israel and representatives of the Palestinian Authority have been sporadic and have failed to result in peace. We could be adversely affected by hostilities involving Israel, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results and cash flow.
Failure to comply with certain conditions and restrictions associated with tax benefits provided to Ormat Systems by the Government of Israel as an "approved enterprise" may require us to refund such tax benefits and pay future taxes in Israel at higher rates.
Our subsidiary, Ormat Systems, has received "approved enterprise" status under Israel's Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. As an approved enterprise, our subsidiary is exempt from Israeli income taxes with respect to revenues derived from the approved investment program for a period of two years commencing on the year it first generates profits from the approved investment program, and thereafter such revenues are subject to 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 where our manufacturing and production operations are conducted and where our Israeli offices are located. Under the terms of our parent's lease agreement with the Israel Land Administration, any sublease for a period of more than five years may require the prior approval of the Israel Land Administration. As a result, the initial term of our sublease with Ormat Industries is for a period of four years and eleven months, extendable to twenty-five years (which includes the initial term). 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 was 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.
Our controlling stockholders may take actions that conflict with your interests.
Ormat Industries, which is controlled by Bronicki Investments Ltd. holds 77.2% of our common tock. Bronicki Investments Ltd. is a privately held Israeli company and is controlled by Lucien and Yehudit Bronicki. Because of these holdings, our parent company and its controlling stockholders will be able to exercise control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions, and they will have significant control over our management and policies. The directors elected by these stockholders will be able to significantly influence decisions affecting our capital structure. This control may have the effect of delaying or preventing changes in control or changes in
management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in their best interest. For example, our controlling stockholders will be able to control the sale or other disposition of our products business to another entity or the transfer of such business outside of the State of Israel, as such action requires the affirmative vote of at least 75% of our outstanding shares.
Some of our directors that also hold positions with our parent may have conflicts of interest with respect to matters involving both companies.
Three of our six directors are directors and/or officers of Ormat Industries. These directors will have fiduciary duties to both companies and may have conflicts of interest on matters affecting both us and our parent, and in some circumstances may have interests adverse to our interests. Our Chairman, Director and Chief Technology Officer, Mr. Bronicki, is the Chairman of our parent and our Chief Executive Officer and Director; Mrs. Bronicki is the Chief Executive Officer of our parent.
We will incur increased costs as a result of being a public company.
As a public company, we have incurred and will continue to incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with recently adopted corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the Securities and Exchange Commission and the NYSE. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. We also expect these new rules and regulations may make it more difficult and more expensive for us to maintain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our Board of Directors or as executive officers. We are currently evaluating and monitoring developments with respect to these new rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
The price of our common stock may fluctuate substantially and your investment may decline in value.
The market price of our common stock is likely to be highly volatile and may fluctuate substantially due to many factors, including:
• actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-based revenues;
• variance in our financial performance from the expectations of market analysts;
• conditions and trends in the end markets we serve and changes in the estimation of the size and growth rate of these markets;
• announcements of significant contracts by us or our competitors;
• changes in our pricing policies or the pricing policies of our competitors;
• loss of one or more of our significant customers;
• legislation;
• changes in market valuation or earnings of our competitors;
• the trading volume of our common stock; and
• general economic conditions.
In addition, the stock market in general, and the New York Stock Exchange and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our
common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company's securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management's attention and resources, which could materially harm our business, financial condition, future results and cash flow.
Future sales of our common stock may depress our share price.
We have 31,562,495 shares of common stock outstanding, of which 7,187,500 shares are freely tradable without restriction or further registration under federal securities laws unless purchased by our affiliates. The remaining shares of common stock outstanding are subject to lock-up agreements, are available for sale in the public market beginning 180 days after November 10, 2004, and will be subject to certain volume limitations under Rule 144 of the Securities Act of 1933, as amended. Lehman Brothers Inc. may waive the lock-up provisions in its sole discretion.
Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, 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 are 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.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is included in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this annual report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Ormat Technologies, Inc.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income, of stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets.
/s/ PricewaterhouseCoopers LLP
Sacramento, California
March 21, 2005
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of the financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of the financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Business
Ormat Technologies, Inc. (the "Company"), a subsidiary of Ormat Industries Ltd. (the "Parent"), is engaged in the geothermal and recovered energy business, including the supply of equipment that is manufactured by the Company and the design and construction of such power plants for projects owned by the Company or for third parties. The Company owns and operates geothermal power plants in various countries, including the United States of America ("U.S"), Kenya, Nicaragua, the Philippines and Guatemala. The Company also owned coal fired heating and electricity power plants and distribution facilities in the Republic of Kazakhstan ("Kazakhstan"), that were sold on September 16, 2002 (see Note 2). The Company's equipment manufacturing operations are located in Israel.
Several of the Company's power plant facilities are listed as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act ("PURPA"). The related power purchase agreements for such facilities are dependent upon their maintaining QF status. Management believes that all of the facilities were in compliance with QF status as of December 31, 2004.
Recapitalization
On June 29, 2004, the Company amended and restated its certificate of incorporation, pursuant to which the authorized capital stock of the Company was increased from 754 shares of $1.00 par value common stock to 155,892,833 authorized shares, comprised of 150,892,833 shares of $0.001 par value common stock and 5,000,000 shares of $0.001 par value preferred stock, of which 500,000 shares have been designated as Series A Preferred Stock. The Company's Board of Directors has the authority to issue the undesignated preferred stock in one or more series and to establish the rights, preferences, privileges and restrictions thereof. On October 21, 2004, the Company further amended and restated its certificate of incorporation, pursuant to which the authorized capital stock of the Company was increased from 150,892,833 shares of $0.001 common stock immediately following the split (see below) to 200,000,000 authorized shares of $0.001 par value common stock.
Additionally, on June 29, 2004, the issued and outstanding 151 shares of $1.00 par value common stock were divided and converted (stock split) to 23,214,281 shares of $0.001 par value common stock.
Further, on June 29, 2004, $20 million outstanding pursuant to the note payable to the Parent was converted to 1,160,714 shares of $0.001 par value common stock of the Company. Such conversion reduced the amounts payable pursuant to the Parent Loan Agreement and increased the stockholder's equity by $20 million and no gain or loss was recognized as a result thereof.
On October 21, 2004, the Board of Directors approved a 1-for-1.325444 reverse stock split of the Company's common stock. Accordingly, all common share and per common share amounts in these consolidated financial statements have been restated to give retroactive effect to the reverse stock split for all years presented. The par value of the common stock remained at $0.001 per share.
Cash Dividend
On October 21, 2004, the Company's Board of Directors declared and authorized the payment of a cash dividend in the aggregate amount of $2.5 million ($ 0.1025 per share). Such dividend was paid on March 2, 2005 and is presented in the balance sheet as of December 31, 2004, in the "Due to Parent" balance.
Initial public offering
In November 2004, the Company completed an initial public offering ("IPO") of 7,187,500 shares of common stock. Net proceeds to the Company after deducting underwriting fees and offering related expenses, were approximately $97 million.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Rounding
Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000.
Basis of presentation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, an 85% interest in OrYunnan Geothermal Co. Ltd. ("OrYunnan"), an 80% interest in Ormat Leyte Co, Ltd. ("OLCL") prior to March, 31, 2004, a 50% interest in Karaganda Holding Company ("KHC") prior to March 12, 2002, and a 100% interest in KHC from March 12, 2002 to September 16, 2002. All intercompany accounts and transactions are eliminated.
In November 1999, the Company, through a wholly owned subsidiary, entered into an agreement with Yunnan Province Geothermal Development Co. ("YPGD") to form OrYunnan, a limited liability joint venture, whereby the Company is to contribute, for an 85% ownership interest, $2,550,000 and YPGD is to contribute, for the remaining 15% ownership interest, $450,000. Pursuant to such agreement, 15% of the capital contribution was made in April 2000, and the remaining portion is to be paid within 60 days after the date on which a power purchase agreement is executed. OrYunnan is currently in the process of negotiating a power purchase agreement. OrYunnan was formed for the purpose of utilizing, for electric power generation, all of the geothermal resources of Teng Chong County of the Yunnan Province in the People's Republic of China.
OLCL is a limited partnership established for the purpose of developing, financing, constructing, owning, operating, and maintaining geothermal power plants in Leyte Provina, the Philippines.
The Company's consolidated balance sheets include 100% of the assets and liabilities of OrYunnan and of OLCL prior to March 31, 2004. The unrelated entity's 15% interests in OrYunnan, and 20% interest in OLCL prior to March 31, 2004, have been reflected as "Minority interest in net assets of subsidiaries" in the Company's consolidated balance sheets and the earnings therefrom have been reflected on the consolidated statements of operations and comprehensive income for all years presented and have been reflected in "Minority interest in earnings of subsidiaries". Intercompany accounts and transactions have been eliminated in the consolidation.
The Company accounts for its interests in partnerships and companies in which it has equal to or less than a 50% ownership interest under the equity method. Under the equity method, original investments are recorded at cost and adjusted by the Company's share of undistributed earnings or losses of such companies. The Company's earnings in investments accounted for under the equity method have been reflected as "Equity in income of investees" on the Company's consolidated statements of operations and comprehensive income.
Adoption of FIN No. 46R
In January 2003, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB 51 ("FIN No. 46"), and amended it by issuing FIN No. 46R in December 2003. Among other things, FIN No. 46R generally deferred the effective date of FIN No. 46 to the quarter ended March 31, 2004. The objectives of FIN No. 46R are to provide guidance on the identification of Variable Interest Entities ("VIEs") for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which company (if any), as the primary beneficiary, should consolidate the VIE. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity's economic variability.
Effective as of March 31, 2004, the Company adopted FIN No. 46R. In connection with the adoption of FIN No. 46R, the Company concluded that OLCL, in which the Company has an 80%
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ownership interest, should be deconsolidated. OLCL's operating results continued to be accounted for using the consolidated method of accounting for the three month period ended March 31, 2004 Effective April 1, 2004, the Company's ownership interest in OLCL is accounted for using the equity method of accounting. The Company's maximum exposure to loss as a result of its involvement with OLCL is estimated to be $4.6 million, which is the Company's net investment at December 31, 2004.
The Company also has variable interests in certain other consolidated wholly owned VIEs that will continue to be consolidated because the Company is the primary beneficiary. Further, the Company has concluded that the Company's remaining significant equity investments do not require consolidation as they are not VIEs.
Purchase of the power generation business from the Parent
As of July 1, 2004, a wholly owned subsidiary of the Company, Ormat Systems Ltd. ("OSL"), an Israeli company, acquired from the Parent for $11 million the power generation business which includes the manufacturing and sale of energy-related products pertaining mainly to the geothermal and recovered energy industry.
The Company considers this business to be synergistic with its ownership and operation of geothermal power plants as well as to the construction of the projects (on a turnkey basis). In addition to acquiring the tangible net assets of the power generation business, OSL has assumed the title and interest to: (i) certain related contracts, and (ii) liabilities and rights under agreements with employees and consultants, and obtained a perpetual license of all intellectual property pertaining to the power generation business from the Parent. Further, in connection with binding work and product orders that the Parent had with its customers, which were transferred to OSL as part of the acquisition, OSL has agreed to pay the Parent a commission ranging from 2.5% to 5% of sales by OSL related to such work and product orders. The maximum aggregate amount of such commissions, which is subject to receipt of payments from customers, is approximately $2.2 million. Commissions expense for the six-month period ended December 31, 2004 was $0.8 million.
In connection with the acquisition, OSL and the Parent have entered into an agreement whereby OSL will provide to the Parent, for a monthly fee of $10,000, certain corporate administrative services, including the services of executive officers. In addition, OSL has agreed to provide the Parent with services of certain skilled engineers at OSL's cost plus 10%, adjusted annually for changes in the Israeli Consumer Price Index. Such agreements may be terminated by either party after the initial term which ends in 2009.
Also in connection with the acquisition, OSL entered into a rental agreement with the Parent for the use of office and manufacturing facilities in Yavne, Israel, for a monthly rent of $52,000, adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties. The term of the rental agreement is 59 months and it expires in June 2009, which term has been extended by a consent of the Israeli Land Administration for a period the shorter of: (i) 25 years (including the initial term) or (ii) the remaining period of the underlying lease agreement with the Israel Land Administration (which terminates between 2018 and 2047).
The Company has recorded the purchase of the power generation business at historical net book value, and has accounted for the purchase as a transfer of assets between entities under common control in a manner similar to the pooling of interests; accordingly, all prior period consolidated financial statements of the Company have been restated to include the results of operations, financial position, and cash flows of the power generation business.
The financial statements for all years presented include the historical financial information of the Company prior to the acquisition of the power generation business, combined with the historical financial information of the acquired power generation business which was carved out of the Parent for all years presented. The difference between the assets and liabilities of the power generation
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
business consists of accumulated retained earnings (deficit) as well as amounts due to/from Parent resulting from cash transfers. Such amounts have been aggregated and presented in the statements of stockholders' equity as "divisional deficit" because it is not possible to distinguish the beginning balance as the records were not available to accurately break out the two components. On July 1, 2004, the effective date of the transaction, the divisional deficit was reclassified to retained earnings and unearned stock-based compensation. Retained earnings in the statements of stockholders' equity for all years prior to the year ended December 31, 2004 represent the retained earnings of the Company prior to the acquisition of the power generation business.
The preparation of these financial statements included the use of "carve out" accounting procedures wherein certain assets, liabilities, revenues and expenses historically recorded or incurred at the Parent level, which were related to OSL, have been identified and allocated as appropriate to present the financial position, operating results, and cash flows of OSL for the years presented.
The statement of operations for OSL was carved out using specific identification for revenues and cost of revenues, research and development expense, selling and marketing expenses, general and administrative expenses and interest income and expense. The income tax provision was recalculated based on the separate return method pursuant to Statement of Financial Accounting Standards ("SFAS") No. 109, Accounting for Income Taxes.
The balance sheet for OSL was carved out of the Parent using specific identification of assets and liabilities. Certain assets and liabilities were allocated in accordance with the terms of the signed definitive agreements.
The OSL financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and in a manner which management believes are reasonable and appropriate. All significant intercompany transactions and accounts have been eliminated. The allocations and estimates used may not necessarily reflect the financial position, operating results and cash flows for the periods presented had OSL been operated as a separate entity.
Of the $11 million purchase price, the Company paid $4.8 million in cash and assumed $6.2 million in debt and other liabilities. As the Company's purchase of the power generation business effective July 1, 2004 has been accounted as a transfer of assets between entities under common control, the excess of the consideration paid over the historical net book value of the purchased business has been recorded as a distribution to the Parent, which reduced stockholders' equity by approximately $4.8 million at July 1, 2004. Because the deferred income taxes at June 30, 2004 had a full valuation allowance, there was no tax effect for the difference between the book and tax basis of the purchased assets and liabilities. Additionally, as mentioned above, on July 1, 2004, the Company reclassified the divisional equity to retained earnings and unearned stock-based compensation.
Cash and cash equivalents
The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.
Marketable securities
Marketable securities consist of debt securities (preferred auction rated securities). The Company accounts for such securities in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. The Company determines the appropriate classification of all marketable securities as held-to-maturity, available-for-sale or trading at the time of the purchase and re-evaluates such classification at each balance sheet date. At December 31, 2004 all of the Company's investments in marketable securities were classified as available-for-sale securities and as a result, were reported at their fair value upon the quoted market prices of such securities at year end. Net unrealized gains or
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
losses are reported as a component of accumulated other comprehensive income (loss) in stockholders' equity. Net realized gains or losses are reported in interest income. The net unrealized gains or losses at December 31, 2004 are immaterial.
The securities are included in the balance sheet at December 31, 2004, as follows:
The cost of the marketable securities at December 31, 2004 approximates their fair value.
Restricted cash, cash equivalents and marketable securities
Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserve, cash collateral and operating fund accounts that have been classified as restricted cash, cash equivalents and marketable securities. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash, cash equivalents and marketable securities, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts are invested primarily in money market accounts and preferred auction rated securities with a minimum investment grade of "AA". The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents. Preferred auction rated securities are classified as available-for-sale.
Certain of the restricted cash accounts can be replaced by a letter of credit, and as further described in Note 17, two letters of credit aggregating $14.4 million were issued by the Company to release restriction on funds that were used as collateral for the Company's 8¼ senior secured notes (the "Notes") and loan agreement with Beal Bank ("Beal Bank Credit Agreement").
Concentration of credit risk
Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments, marketable securities and accounts receivable.
The Company places its temporary cash investments and marketable securities with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31, 2004 and 2003, the Company had deposits in five and six, respectively, U.S. financial institutions that were federally insured up to $100,000 per financial institution. At December 31, 2004 and 2003, the Company's deposits in foreign countries of approximately $9,184,000 and $9,927,000, respectively, were not insured.
At December 31, 2004 and 2003, accounts receivable related to operations in foreign countries amounted to approximately $7,963,000 and $13,029,000, respectively. At December 31, 2004 and 2003, accounts receivable from the Company's major customers (see Note 14) amounted to approximately 80% and 57% of the Company's accounts receivable, respectively. The Company performs ongoing credit evaluations of its customers' financial condition. The Company requires the customer in Nicaragua to provide a cash security arrangement for its payment obligations. The Company has historically been able to collect on substantially all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.
Inventories
Inventories consist primarily of raw material parts and sub assemblies for power units, and are stated at the lower of cost or market value, using the moving-average cost method and are stated net of provision for slow-moving and obsolescence, which was not significant.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deposits and other
Deposits and other consist primarily of performance bonds for construction projects, a long-term insurance contract and hedge instruments.
Property, plant and equipment
Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction incurred as part of the construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance costs are expensed. Power plants operated by the Company are depreciated using the straight-line method over the term of the relevant power purchase agreement (see Note 12). The geothermal power plants in the Philippines and Nicaragua are to be fully depreciated over the period that the plants are owned by the Company. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently and is recorded in operating income.
The Company capitalizes interest costs as part of constructing power plant facilities. Such capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset's estimated useful life. Capitalized interest costs amounted to approximately $628,000, $297,000, and $201,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
Deferred financing costs
Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the statement of operations. Accumulated amortization related to deferred financing costs amounted to $1,708,000 and $576,000 at December 31, 2004 and 2003, respectively. Amortization expense for the years ended December 31, 2004, 2003 and 2002 amounted to $2,705,000, $576,000, and $0, respectively.
Intangible assets
Intangible assets consist of allocated acquisition costs of power purchase agreements, which are amortized over the 15 to 23-year terms of the agreements using the straight-line method.
Impairment of long-lived assets and long-lived assets to be disposed of
Long-lived assets including unconsolidated investments and power purchase agreements are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets, however, future estimates as to the recoverability of such assets may change based on revised circumstances.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative instruments
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
The Company maintains a risk management strategy that incorporates the use of interest rate swaps and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes are included as a component of other comprehensive income or loss and are subsequently reclassified into earnings when interest on the related debt is paid. Gains or losses on contracts that are not designated to qualify as a cash flow hedge are included as a component of interest expense.
The Company is subject to the provisions of SFAS No. 133 Derivative Implementation Group ("DIG") Issue No. C15, Normal Purchases and Normal Sales Exception for Certain Option-Type Contracts and Forward Contracts in Electricity, which expands the requirements for the normal purchase and normal sales exception to include electricity contracts entered into by a utility company when certain criteria are met. Also under DIG Issue No. C15, contracts that have a price adjustment clause based on an index that is not directly related to the electricity generated, as defined in SFAS No. 133, do not meet the requirements for the normal purchases and normal sales exception. The Company has power sales agreements that qualify as derivative instruments under DIG Issue No. C15 because they have a price adjustment clause based on an index that does not directly relate to the sources of the power used to generate the electricity. The adoption of the provisions of DIG Issue No. C15 in 2002 did not have a material impact on the Company's consolidated financial position and results of operations.
In June 2003, the FASB issued DIG Issue No. C20, Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature. DIG Issue No. C20 superseded DIG Issue No. C11, Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception, and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 was effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company). In conjunction with initially applying the implementation guidance, DIG Issue No.C20 requires contracts that did not previously qualify for the normal purchases normal sales scope exception, and do qualify for the exception under DIG Issue No. C20, to freeze the fair value of the contract as of the date of the initial application, and amortized such fair value over the remaining contract period. Upon adoption of DIG Issue No. C20, the Company elected the normal purchase and normal sales scope exception under SFAS No. 133 related to its power purchase agreements. Such adoption did not have a material impact on the Company's consolidated financial position and results of operations.
Foreign currency translation
The functional currency of all foreign entities is the reporting currency (U.S. dollar or dollar). For these entities, monetary assets and liabilities are translated at the current exchange rate, while non-monetary items are translated at historical rates. Income and expense items are translated at the average exchange rate for the year, except for depreciation, which is translated at historical rates. Translation adjustments and transaction gains or losses are included in results of operations.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's functional currency of certain Kazakhstan activities was considered to be the local currency; accordingly, all assets and liabilities were translated at the exchange rate as of the balance sheet date. Revenues, costs and expenses were translated at the weighted average exchange rate for the period. Translation adjustments were accumulated in a separate component of stockholders' equity. Upon sale of the Kazakhstan business (see Note 2), the accumulated foreign currency translation losses were eliminated.
Comprehensive income reporting
The Company accounts for comprehensive income with SFAS No. 130, Reporting Comprehensive Income, which requires comprehensive income and its components to be reported when a company has items of other comprehensive income. Comprehensive income includes net income plus other comprehensive income, which for the Company consists of foreign currency translation adjustments and the mark-to-market losses on derivative instruments designated for cash flow hedge. The adjustments for the year ended December 31, 2002 did not have any tax effect as Karaganda Holding Company ("KHC") was not in a taxable position due to its recurring losses that resulted in a full valuation of deferred income taxes. In connection with the sale of KHC that is further discussed in Note 2, the Company recorded a reduction of $1,184,000 in accumulated foreign currency translation losses, and included such accumulated losses as a component of "Loss on sale of Kazakhstan operations" in determining the net loss for the year ended December 31, 2002.
Revenues and cost of revenues
Revenues are primarily related to: (i) sale of electricity from geothermal power plants owned and operated by the Company; and (ii) geothermal and recovered energy power plant equipment engineering, sale, construction and installation and operating services.
Revenues related to the sale of electricity from geothermal power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. As described below, for power purchase agreements ("PPAs") acquired as part of the projects purchased since July 1, 2003 (see Note 2), revenues related to the lease element of the PPA are included as "lease portion of energy and capacity " revenues, with the remaining revenues related to the production and delivery of energy presented as "energy and capacity".
Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts. Revenues from the supply and/or construction of geothermal and recovered energy power plant equipment on behalf of others are recognized on the percentage completion method. Revenue is based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined.
In May 2003, the Emerging Issues Task Force ("EITF") reached consensus in EITF Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, to clarify the requirements of identifying whether an arrangement contains a lease at its inception. The guidance in the consensus is designed to broaden the scope of arrangements, such as power purchase agreements, accounted for as leases. EITF Issue No. 01-8 requires both parties to an arrangement to determine whether a service contract or similar arrangement is, or includes, a lease within the scope of SFAS No. 13, Accounting for Leases. The consensus is being applied prospectively to arrangements agreed to, modified, or acquired in business combination on or after July 1, 2003. The adoption of EITF Issue No. 01-8 effective July 1,
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2003 did not have a material effect to the Company's financial position or results of operations. As further discussed in Note 12, PPAs acquired as part of the projects purchased since July 1, 2003 (Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects, see Note 2), contain lease elements within the scope of SFAS No. 13. Lease revenue related to the Heber 1 and 2 projects from the date of acquisition (December 18, 2003) to December 31, 2003 was not material.
Warranty on products sold
The Company generally provides a one-year warranty against defects in workmanship and materials related to the sale of products for electricity generation. Estimated future warranty obligations are provided by charges to operations in the period in which the related revenue is recognized. Such charges have historically been immaterial.
Research and development
Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the Office of the Chief Scientist ("OCS") of the Israeli Government are offset against the related research and development expenses. Such grants amounted to $0, $142,000 and $531,000 during the years ended December 31, 2004, 2003, and 2002, respectively.
Advertising expense
Advertising costs are expensed as incurred and totaled $74,000, $58,000 and $72,000 for the years ended December 31, 2004, 2003, and 2002, respectively.
Patent expense
Patents are internally developed, and therefore costs are expensed as incurred and totaled $290,000, $377,000 and $436,000 for the years ended December 31, 2004, 2003, and 2002, respectively.
Income taxes
Income taxes are accounted for using an asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law; the effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are not expected to be realized.
Income (loss) per share
Basic income (loss) per share is computed by dividing income (loss) available to common stock shareholders by the weighted average number of shares of common stock outstanding for the year. The Company does not have any equity instruments that are dilutive, except for employee stock options which were granted on November 10, 2004 and whose dilutive effect on the net income per share for the year ended December 31, 2004 is immaterial. The stock options granted to employees of the Company in the Parent's stock are not dilutive to the Company's income per share.
Stock-based compensation
The Company accounts for stock-based compensation based on the provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB No. 25"), and FASB Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation, and
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
other related interpretations which states that no compensation expense is required to be recorded for stock options or other stock-based awards to employees that are granted with an exercise price equal to or above the estimated fair value per share of common stock on the grant date. In the event that stock options are granted at a price lower than the fair market value at that date, the difference between the fair market value of the common stock and the exercise price of the stock options is recorded as unearned compensation. Unearned compensation is amortized to compensation expense over the vesting period applicable to the stock option. The Company has adopted the disclosure requirements of SFAS No. 123, Accounting for Stock-Based Compensation, as it relates to stock options granted to employees, which requires pro forma net income (loss) be disclosed based on the fair value of the options granted at the date of the grant.
The Company calculated the fair value of each option on the date of grant using the Black-Scholes option pricing model using the following assumptions:
Had compensation cost for the options granted to employees of the Company been determined based on the fair value method prescribed by SFAS No. 123, the Company's pro forma net income (loss) and earnings (loss) per share would have been as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair value of financial instruments
The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments. The marketable securities are presented at fair value. The fair value of long-term debt is estimated based on the current borrowing rates for similar issues, which approximates carrying amount for all long-term debt except for the Notes. For the Notes (see Note 9) such fair value amounted to $191.9 million compared to carrying amount of $189.5 million at December 31, 2004.
Accounting estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
New accounting pronouncements
SFAS No. 123 (Revised 2004) - Share-Based Payments
In December 2004, the FASB issued the revised SFAS No. 123, Share-Based Payment ("SFAS No.123R"), which addresses the accounting for share-based payment transactions in which a company obtains employee services in exchange for: (i) equity instruments of the company, or (ii) liabilities that are based on the fair value of the company's equity instruments or that may be settled by the issuance of such equity instruments. SFAS No.123R eliminates the ability to account for employee share-based payment transactions using APB No. 25 and requires instead that such transactions be accounted for using the grant date fair value based method. SFAS No.123R will be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005 (July 1, 2005 for the Company). Early adoption of SFAS No.123R is encouraged. SFAS No.123R applies to all awards granted or modified after the Statement's effective date. In addition, compensation cost for the unvested portion of previously granted awards that remain outstanding on the Statement's effective date shall be recognized on or after the effective date, as the related services are rendered, based on the awards' grant date fair value as previously calculated for the pro forma disclosure under SFAS No.123.
The Company estimates that the cumulative effect of adopting SFAS No.123R as of its adoption date by the Company (July 1, 2005), based on the awards outstanding as of December 31, 2004, will be immaterial. This estimate does not include the impact of additional awards, which may be granted, or forfeitures, which may occur subsequent to December 31, 2004 and prior to the Company's adoption of SFAS No.123R. The Company expects that upon the adoption of SFAS No.123R, it will apply the modified prospective application transition method, as permitted by the Statement. Under such transition method, upon the adoption of SFAS No.123R, The Company's consolidated financial statements for periods prior to the effective date of the Statement will not be restated. The Company does not expect SFAS No. 123R to have a material impact on its results of operations and financial position in future periods.
SFAS No. 151 - Inventory Costs
In November 2004, the FASB issued SFAS No. 151, Inventory Costs - An Amendment of ARB 43, Chapter 4. SFAS No.151 amends the guidance in ARB No. 43, Chapter 4, Inventory Pricing, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. This Statement requires that those items be recognized as current period charges. In
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
addition, this Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No.151 will be effective for inventory costs incurred during fiscal years beginning after June 15, 2005 (January 1, 2006 for the Company). Earlier application of SFAS No.151 is permitted. The provisions of SFAS No.151 shall be applied prospectively. The Company does not expect SFAS No.151 to have a material impact on its results of operations and financial position in future periods.
SFAS No. 153 - Exchange of Nonmonetary Assets
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets - An Amendment of APB Opinion No. 29. SFAS No. 153 amends APB Opinion No. 29, Accounting for Nonmonetary Transactions. The amendments made by SFAS No. 153 are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, the amendments eliminate the exception for nonmonetary exchanges of similar productive assets and replace it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. The provisions in SFAS No.153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005 (July 1, 2005 for the Company). Early application of SFAS No.153 is permitted. The provisions of SFAS No.153 shall be applied prospectively. The Company does not expect SFAS No.153 to have a material impact on its results of operations and financial position in future periods.
EITF Issue No. 02-14 - Whether an Investor Should Apply the Equity Method of Accounting to
Investments Other Than Common Stock
In July 2004, the FASB issued EITF Issue No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock. EITF Issue No. 02-14 addresses whether the equity method of accounting applies when an investor does not have an investment in voting common stock of an investee but exercises significant influence through other means. EITF Issue No. 02-14 states that an investor should only apply the equity method of accounting when it has investments in either common stock or in-substance common stock of the investee, provided that the investor has the ability to exercise significant influence over the operating and financial policies of the investee. The provisions in EITF Issue No. 02-14 are effective for reporting periods beginning after September 15, 2004 (October 1, 2004 for the Company). The adoption of EITF Issue No. 02-14 by the Company did not have any impact on its results of operations and financial position.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 - BUSINESS ACQUISITIONS AND SALE
Acquisitions and sale in 2002
Karaganda Holding Company ("KHC")
KHC was established for the purpose of generating power and selling and distributing electricity and heating power in Kazakhstan. Prior to March 12, 2002, the Company had a 50% ownership interest in KHC. Effective March 12, 2002, the Company purchased the remaining 50% interest in KHC for $500,000. Such transaction was accounted for under the purchase method of accounting, and the allocation of the $500,000 purchase price was as follows:
On September 16, 2002, the Company sold all of its ownership interest in KHC to a third party for approximately $4.1 million, less approximately $0.2 million of costs related to the sale. The Company recognized a loss on the sale of this subsidiary equal to approximately $6.4 million during 2002, in addition to the operational losses incurred prior to such sale. The net assets of KHC on the date of the sale were as follows:
The sale of KHC resulted in the Company discontinuing its operating activities in Kazakhstan. The net results of operations of the discontinued activities in Kazakhstan prior to September 16, 2002 are shown in the statement of operations for the year ended December 31, 2002 as "Loss from discontinued activities in Kazakhstan".
The Ormesa Project
On April 15, 2002, the Company acquired 100% of the equity interests in the Ormesa Project, located in Imperial Valley, California, to expand its geothermal power plant operations. The Ormesa Project consists of six power plants and was owned by several unrelated companies. The Company acquired 100% interests in four of the entities and acquired the assets of a fifth entity. These entities
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and assets were merged into Ormesa, LLC ("Ormesa") in 2002. The Company paid approximately $41.7 million for the ownership of the Ormesa Project, of which approximately $35.7 million and $6.0 million has been allocated to property, plant and equipment and intangible assets, respectively. The acquisition was accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of five to fifteen years. The results of operations of the Ormesa Project have been included in the consolidated financial statements since April 15, 2002.
Acquisitions in
The Steamboat 1/1A Project
On June 30, 2003, the Company acquired from two groups of unrelated sellers, a 100% interest in Steamboat Geothermal LLC ("SG"), which owns geothermal power plants ("Steamboat 1/1A") in Nevada. The purchase price of $1.2 million was paid in cash, of which, $2.1 million has been recorded as property, plant and equipment, less assumption of liabilities of $0.9 million. The acquisition has been accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of three to fifteen years. The results of operations of the Steamboat 1/1A Project have been included in the consolidated financial statements since July 1, 2003.
The Heber and Mammoth Projects
On December 18, 2003, the Company purchased certain geothermal assets from Covanta Energy Corporation ("CEC"), an unrelated entity for a total purchase price of $215 million, plus transaction costs of approximately $3.2 million. As further discussed in Note 9, the Company entered into a loan agreement and borrowed $154.5 million from Beal Bank, all of which is collateralized by the acquired assets described below, except for the assets related to the Company's 50% ownership interest in Mammoth-Pacific, L.P. ("Mammoth").
The assets purchased include: (i) a 100% ownership in Heber Geothermal Company, which owns a 38 megawatt ("MW") geothermal power plant ("Heber 1"), located near Heber, California; (ii) a 100% ownership in Second Imperial Geothermal Company ("SIGC"), that has rights to the lessee position of a 34 MW geothermal power plant ("Heber 2"), adjacent to the Heber 1 plant; (iii) a 100% ownership in Heber Field Company, that has the rights to the geothermal resources used by Heber 1 and 2; and (iv) 50% ownership interest in Mammoth, that owns and operates three geothermal plants, with a combined generating capacity of 25 MW, located near the city of Mammoth, California.
In addition, the Company acquired all of the beneficial rights, title and interest in the Heber 2 geothermal power plant from the lessor for a purchase price of approximately $38.5 million.
The results of operations of the Heber Projects have been included in the consolidated financial statements since December 18, 2003. The results of operations of the Mammoth Project have been included in the consolidated financial statements using the equity method of accounting since December 18, 2003.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Steamboat 1/1A and the Heber and Mammoth projects' asset acquisitions have been accounted for under the purchase method of accounting and the acquired assets and intangibles are being depreciated over their estimated useful lives of three to twenty years. The purchase price has been allocated based on independent valuation and management's estimates as follows:
The following unaudited pro forma financial information for the years ended December 31, 2003 and 2002, assumes the Heber and Mammoth projects acquisitions occurred as of the beginning of the respective years, after giving effect to certain adjustments, including the amortization of intangible assets, interest expense on acquisition debt, depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of the Heber and Mammoth projects been affected on the dates indicated.
Acquisitions in
The Steamboat 2/3 Project and Meyberg Property
On February 11, 2004, the Company acquired 100% of the outstanding shares of capital stock of Steamboat Development Corp. ("SDC"), and certain real property ("Meyberg Property") from an unrelated party. SDC owned certain leasehold interests as a lessee in the two Steamboat 2/3 geothermal power plants and certain related geothermal leases. On February 13, 2004, the Company acquired all of the beneficial rights, title, and interest in the Steamboat 2/3 geothermal power plants from the lessor. The Company acquired SDC and the Meyberg Property to increase its geothermal power plant operations in the United States. The Company acquired the lessee and lessor positions of the Steamboat 2/3 geothermal power plants for a combined purchase price of approximately $82 million, plus transaction cost of approximately $0.8 million. The results of SDC's operations have been included in the consolidated financial statements since February 11, 2004.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Steamboat Hills Project
On May 20, 2004, the Company completed the acquisition of 100% of the equity interests of Yankee Caithness Joint Venture, L.P. ("Yankee"), which we refer to as Steamboat Hills, from unrelated parties for a purchase price of approximately $20.3, including acquisition costs of approximately $0.1 million. Yankee owns and operates a geothermal electric generation plant, located in Steamboat Springs, Nevada. The Company purchased Yankee in order to increase its geothermal power plant operations in the United States. Yankee was subsequently renamed as Steamboat Hills. The results of Steamboat Hills' operations have been included in the consolidated financial statements since May 20, 2004.
The Puna Project
On June 3, 2004, the Company completed the acquisition of 100% of the equity interests of Puna Geothermal Venture ("PGV") from an unrelated party for a purchase price of $72.9 million, including acquisition costs of approximately $0.2 million. PGV operates a geothermal power plant ("Puna Project") located on the island of Hawaii. The Company purchased PGV in order to increase its geothermal power plant operations in the United States. The results of PGV's operations have been included in the consolidated financial statements since June 3, 2004.
The Puna Project was not in compliance with the threshold minimum performance requirements of its power purchase agreement at the time of the acquisition, and is currently not in compliance with such requirements, which non-compliance has resulted in the imposition of sanctions that reduce the aggregate amounts of revenues payable to the Company from the relevant power purchaser, and amounted to $0.4 million for the period from June 3, 2004 to December 31, 2004.
The Steamboat 2/3 Project, the Meyberg Property, the Steamboat Hills Project and the Puna Project acquisitions have been accounted for under the purchase method of accounting and the acquired depreciable assets and intangibles are being depreciated over their estimated useful lives of 14 to 23 years. The purchase price (including of the lessee and lessor position in the Steamboat 2/3 Project) has been allocated based on independent valuation and management's estimates as follows:
The following unaudited pro forma financial information for the years ended December 31, 2004 and 2003, assumes the Steamboat 2/3 Project and Meyberg Property, the Steamboat Hills Project and the Puna Project acquisitions occurred as of the beginning of the respective years, after giving effect to certain adjustments, including the amortization of intangible assets, interest expense on acquisition debt, depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of the Steamboat 2/3 Project and Meyberg Property, the Steamboat Hills Project and the Puna Project been affected on the dates indicated.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 - INVENTORIES
Inventories consist of the following:
NOTE 4 - COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS
These amounts are included in the balance sheets under the following captions:
The completion costs of the Company's construction contracts are subject to estimation. Due to uncertainties inherent in the estimation process, it is reasonably possible that estimated contract earnings will be further revised in the near term.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - UNCONSOLIDATED INVESTMENTS
Unconsolidated investments in power plant projects consist of the following:
The Zunil Project
The Company has a 21% ownership interest in Orzunil I de Electricidad, Limitada ("Orzunil"), a limited responsibility company incorporated in Guatemala and established for the purpose of the generation and co-generation of power from a geothermal power plant in the Province of Quetzaltenango in Guatemala. The Company operates and maintains the geothermal power plant and the power purchaser supplies geothermal fluid to the power plant. The Company's 21% ownership interest in Orzunil is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Orzunil.
Notes receivable for cash advances to Orzunil consist of the following:
All available cash after the debt service under the subordinated loan is used to repay the junior subordinated loan. Interest income received from these loans amounted to approximately $ 214,000, $270,000 and $296,000 during the years ended December 31, 2004, 2003 and 2002, respectively.
The Company's equity in income of Orzunil was not significant for each of the years presented in these financial statements.
The Mammoth Project
As discussed in Note 2, on December 18, 2003, the Company acquired a 50% interest in the Mammoth Project, which is comprised of three geothermal power plants. The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the power purchase agreements, which range from 12 to 17 years. Effective December 18, 2003, the Company operates and maintains the geothermal power plants under an operating and maintenance ("O&M") agreement. The Company's 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The condensed financial position and results of operations of Mammoth are summarized below:
The Leyte Project ("OLCL")
The Company holds an 80% interest in OLCL (which owns the Leyte Project), however, as further discussed in Note 1, upon the adoption of FIN No. 46R, the balance sheet of OLCL was deconsolidated as of March 31, 2004, and the income and cash flow statements have been deconsolidated effective April 1, 2004.
The condensed financial position and results of operations of OLCL are summarized below:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OLCL's operating results for all periods prior to March 31, 2004 have been accounted for on the consolidated method of accounting, and effective April 1, 2004, the Company's ownership interest in OLCL is accounted for using the equity method of accounting.
NOTE 6 - PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, net, consist of the following:
Depreciation expenses for the years ended December 31, 2004, 2003 and 2002 amount to $31,729,000, $15,519,000 and $14,115,000, respectively.
U.S. operations:
The net book value of the property, plant and equipment, including construction in process, located in the United States is approximately $ 444,703,000 and $274,465,000 as of December 31, 2004 and 2003, respectively.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Foreign operations:
In 1996, OLCL entered into a Build, Operate, and Transfer ("BOT") agreement with PNOC-Energy Development Corporation ("PNOC") in connection with the geothermal power plants located in Leyte, Philippines. The BOT agreement calls for the Company to design, construct, own, and operate geothermal electricity generating plants, utilizing the geothermal resources of the Leyte Geothermal Power Optimization Project Area. During 1997, the power plants started commercial operations and began selling power to PNOC under a ten year power purchase agreement (tolling arrangement). The Company owns the plants for a ten-year period ending September 2007, at which time they will be transferred to PNOC for no further consideration. As such, the Company's cost is being depreciated over the ten-year period. The net book value of the assets related to the geothermal power plants located in the Philippines amounted to approximately $17,433,000 at December 31, 2003. As further discussed in Note 1, the Company deconsolidated the balance sheet of OLCL as of March 31, 2004.
During 1998, the Company entered into a power purchase agreement with Kenya Power and Lighting Company Limited ("KPLC"). Under the agreement, the Company will design, construct and operate geothermal power plants in Kenya in several phases. Upon the completion of construction of each phase, KPLC is committed to purchase the electricity generated by the power plants for a minimum of 20 years under the terms of the power purchase agreement. Phase I of the Olkaria III project has been completed and the net book value of the assets related to the generation power plant and the related wells amounted to approximately $32,533,000 and $32,722,000 at December 31, 2004 and 2003, respectively. The Company is currently in discussions with the Kenyan government and KPLC regarding, among other things, the construction of Phase II of the Olkaria III project and the provision of certain collateral and government support. The Company must notify KPLC, by April 17, 2005, whether it will proceed to construct Phase II of the Olkaria III project and, if the Company notifies KPLC that it will not proceed with such construction, then the portion of the current power purchase agreement applicable to Phase II of the Olkaria III project will be terminated (but the current portion applicable to Phase I will be unaffected). If the Company fails to provide such notification it will be required to construct Phase II and reach commercial operations by May 31, 2007 in order to avoid the application of financial penalties, or at the latest by April 17, 2008 in order to avoid termination of the entire power purchase agreement. As of December 31, 2004 and 2003, the Company had incurred approximately $20,890,000 and $22,189,000, respectively, (included in construction-in-process) in connection with construction of Phase II of the power plant, which is required to be completed no later than 2007. Management believes that the discussions will be successful and the project will be completed in the required timeframe. If the Company does not proceed with the construction of Phase II, the Company may lose some or all of its investment in the construction-in-process relating to Phase II.
In June 1999, the Company entered into an agreement with Nicaraguan Electricity Company ("NEC") a Nicaraguan power utility, whereby the Company will rehabilitate existing wells, drill new wells, and operate the geothermal facilities. The Company owns the plants for a fifteen-year period ending in 2014, at which time they will be transferred to NEC at no cost. The Company sells the power from the facilities to two power companies who are assignees of NEC at the agreed upon price and terms of the "take or pay" power purchase agreement. The net book value of the assets related to the constructed plant and wells and rehabilitated existing wells amounted to approximately $23,784,000 and $26,087,000 at December 31, 2004 and 2003, respectively. Additionally, as of December 31, 2004 and 2003, the Company has incurred approximately $1,046,000 and $1,103,000, respectively, (included in construction-in-process) to drill an additional well.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company is engaged in the construction of several geothermal power plants in other foreign countries. At December 31, 2004 and 2003, such projects were in the early stages of construction and the related costs totaling approximately $2,781,000 and $3,588,000, respectively, have been included as construction-in-process.
NOTE 7 - INTANGIBLE ASSETS
Intangible assets consist of all of the Company's power purchase agreements acquired in business combinations and amounted to $48,930,000 and $32,005,000, net of accumulated amortization of $3,449,000 and $926,000 as of December 31, 2004 and 2003, respectively. Amortization expense for the years ended December 31, 2004, 2003 and 2002 amount to $2,523,000, $524,000, and $362,000, respectively.
Estimated future amortization expense for the intangible assets as of December 31, 2004 is as follows:
NOTE 8 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consist of the following:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 - LONG-TERM DEBT
Long-term debt consists of notes payable under the following agreements:
Eximbank credit agreement (Term Loan)
In connection with the construction of four geothermal power generation plants, with a total capacity of 49MW in Leyte, Philippines, the subsidiary in the Philipines (which was deconsolidated as from April 1, 2004) obtained a term loan ("Term Loan") amounting to approximately $44.5 million from the Export-Import Bank of the government of the United States ("Eximbank"). Principal is payable in equal quarterly installments through July 2007. Interest on the Term Loan is at a fixed rate of 6.54% and is payable quarterly. The Term Loan is collateralized by a mortgage on all real property, an assignment of revenues, and the pledge of partnership interests in OLCL. There are various covenants under the Term Loan, which include maintaining minimum levels of equity ratio, as defined, and limitations on additional indebtedness and payment of dividends. As of December 31, 2004, management believes the Company was in compliance with the covenants under the Term Loan.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Ormesa loan
On December 31, 2002, a wholly owned subsidiary of the Company ("Ormesa LLC"), that owns and operates the Ormesa Complex, entered into a senior secured credit facility agreement ("Ormesa Loan") amounting to $20 million with a bank. On December 31, 2004, Ormesa LLC repaid this loan in its entirety.
Beal Bank Credit Agreement
In December 2003, in connection with the acquisition of the CEC geothermal power plant assets (see Note 2), OrCal Geothermal, Inc. ("OrCal"), a wholly owned subsidiary of the Company, entered into a loan agreement with Beal Bank amounting to $154.5 million. Principal payments range from 0.25% to 3.5% of the outstanding balance and are payable in quarterly payments that commenced in June 2004 and continue through December 2019. Interest payments on the unpaid principal balance commenced in March 2004, and are payable quarterly at a variable rate determined on each anniversary date of the loan as the greater of 7.125% or LIBOR plus 5.125%. The applicable interest rate will increase by 0.5% starting in December 2011. The LIBOR rate as of December 31, 2004 was 3.017%.
The Beal Bank Credit Agreement is collateralized by substantially all of the assets of OrCal and certain OrCal subsidiaries ("OrCal Subsidiaries"). Performance under the Beal Bank Credit Agreement is guaranteed by OrCal and its subsidiaries. Funds held in debt service reserve accounts established under a depository agreement are pledged for the benefit of Beal Bank and have been included in restricted cash in the balance sheet.
There are various restrictive covenants under the Beal Bank Credit Agreement, which include limitations on indebtedness, transactions with related parties and payments of dividends. As of December 31, 2004, management believes that the Company is in compliance with all covenant terms.
During the second quarter of 2004, the OrCal entered into two separate interest rate cap agreements ("Cap Transactions") with two different financial institutions to mitigate the interest rate risk associated with the Beal Bank Credit Agreement. Pursuant to the Cap Transactions, OrCal paid an aggregate of $3,820,000 to the financial institutions providing such interest rate investments. The Cap Transactions are effective as of March 30, 2007 and terminate on March 31, 2011. Pursuant to the terms of the Cap Transactions, the financial institutions providing the cap are required to pay to OrCal the difference between the LIBOR rate and 6.0%, (if LIBOR is greater than 6.0%), times the notional amount, which for each of the contracts will be $67,401,000 on the effective date and reduces each payment period down to $49,633,000 upon termination. As of October 1, 2004, the Cap Transactions qualify for cash flow hedge accounting. The fair value of the Cap Transactions at December 31, 2004 amounted to $1,663,000, and the decrease in the fair value for the period from the initiation of the Cap Transactions through September 30, 2004 of $1,637,000 has been recorded in the consolidated statement of operations as interest expense, while the decrease in the fair value for the period from October 1, 2004 to December 31, 2004 of $520,000, net of related taxes of $198,000 is included as "Loss in respect of derivatives instruments designated for cash flow hedge, net of related taxes" under "Other comprehensive income (loss)". The fair value of the Cap Transactions is the estimated amount that OrCal would currently pay to terminate the transactions at the reporting date, taking into account current interest rates and the current creditworthiness of the counterparties to the agreements.
Credit facility agreement (the Momotombo Project)
In September 2000, Ormat Momotombo Power Company ("OMPC"), a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. pursuant to which OMPC executed a two-phase loan with the bank in the amounts of $11,435,000 ("Phase I Loan") and
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$36,800,000 ("Phase II Loan") (collectively "Credit Facility Agreement"). In March 2003, OMPC signed an amendment to the Credit Facility Agreement changing the amount of the Phase II Loan from $36,800,000 to $15,000,000. Principal and interest payments on the Phase I Loan are payable in 32 equal quarterly payments that commenced upon completion of Phase I of the project in December 2001. Interest on the Phase I Loan is variable based on LIBOR plus 2.375%. Principal and interest payments on the Phase II Loan are payable in equal 28 quarterly payments that commenced in March 2004. Interest on the Phase II Loan is variable based on LIBOR plus 3.0%, and is added to the outstanding balances of the Phase II Loan until the commencement of the principal and interest payments. At December 31, 2004, and 2003, $6,856,000 and $8,046,000, respectively, was outstanding under the Phase I Loan and approximately $10,172,000 and $11,869,000, respectively, was outstanding under the Phase II Loan. The Credit Facility Agreement is collateralized by liens over all real and personal property comprising the Momotombo Project and the Company's ownership interest in OMPC. There are various restrictive covenants under the Credit Facility Agreement, which include maintaining certain levels of debt to equity ratio and debt service coverage ratio, and limitations on additional indebtedness and payment of dividends. As of December 31, 2004, management believes that the Company was in compliance with the covenants under the Credit Facility Agreement.
Loan one
In May 1998, the Company entered into an $8 million loan agreement, with principal payable in $1 million annual installments that commenced in May 2001, and continue through May 2008. Interest is computed at LIBOR plus 1.7%, and is payable annually. The Parent provided a guarantee, whereby in the event that the Company failed to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan. Such guarantee was cancelled on July 15, 2004.
In 2003, the Parent obtained a waiver from the bank with respect to the failure by the Parent in 2001 and 2002 to meet certain financial ratios contained in its guarantee. The Parent provided no consideration for such waiver. The Parent has since been in compliance with the required financial ratios. Management believes the Parent was in compliance with the covenants under this loan agreement.
Loan two
In July 2000, the Company entered into a $5.6 million loan agreement with principal payable in equal semi-annual payments that commenced in January 2003, and continue through July 2010. On July 14, 2004, the Company repaid the loan in full.
Loan three
In March 2001, the Company entered into a $10 million loan agreement, with principal payable in equal quarterly payments that commenced in April 2003, and continue through January 2006. Interest is computed at LIBOR plus a margin as calculated by the bank each quarter (2.6% at December 31, 2004), and is payable quarterly. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the bank the remaining outstanding balance of the loan. On March 10, 2005, the Company repaid the loan in full.
Loan four
In July 2001, the Company entered into a $9.5 million loan agreement, with principal payable in equal semi-annual payments that commenced in July 2003, and continue through July 2006. On November 21, 2004, the Company repaid the loan in full.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Loan five
In July 2001, the Company entered into a $9.5 million loan agreement, with principal payable in equal semi-annual payments that commenced in May 2003, and continue through May 2006. On November 21, 2004, the Company repaid the loan in full.
Bridge loan
During 2003, a wholly owned subsidiary of the Company amended the Bridge Loan by changing the maximum loan amount from $40 million to $20 million. On September 1, 2004, the Company repaid $15 million of the loan. On December 1, 2004, the Company repaid the remaining $5 million balance of the loan. The unutilized line of credit as of December 31, 2004 was valid through February 2, 2005 and was guaranteed by the Parent.
Bridge loan two
In June 2004, the Company entered into a $20 million loan agreement, with principal payable by November 2005. Interest is computed at LIBOR plus 1.45% with principal payable no later than December 31, 2005 and interest payable quarterly. The Parent has provided a guarantee, whereby in the event that the Company fails to perform its obligation under the loan agreement, the Parent would be required to pay the financial institution the remaining outstanding balance of the loan. On February 10, 2005, the Company repaid the loan in full. The unutilized line of credit as of February 10, 2005 and thereafter is valid through December 31, 2005 and is guaranteed by the Parent.
Future minimum payments
Future minimum payments under long-term obligations, excluding the senior secured notes and notes payable to Parent, as of December 31, 2004 are as follows:
Senior secured notes
On February 13, 2004, the Company, through Ormat Funding Corporation ("OFC"), a wholly owned subsidiary, completed the issuance of 8¼% senior secured notes (the "Notes") pursuant to an exempt offering under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the "Offering"), amounting to $190 million, and received net cash proceeds of approximately $179.7 million after deduction of deferred bond issuance costs of approximately $10.3 million, which have been included in deferred financing costs at December 31, 2004. The Notes have a final maturity date of December 30, 2020. Principal and interest on the Notes are payable in semi-annual payments that commenced in June 30, 2004. The Notes are collateralized by substantially all of the assets of OFC and fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC, and (with certain exceptions) by all real property, contractual rights, revenues and bank accounts, intercompany notes, certain insurance policies and guarantees of OFC and its subsidiaries. There are various
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
restrictive covenants under the Notes, which include limitations on additional indebtedness and payment of dividends. As of December 31, 2004, management believes that the Company was in compliance with the covenants under the Notes.
The Company may redeem the Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the Notes to be redeemed plus accrued interest, premium and liquidated damages, if any, plus a "make-whole" premium. Upon certain events, as defined in the note agreement, the Company may be required to redeem a portion of the Notes at a redemption price ranging from 100% to 101% of the principal amount of the Notes being redeemed plus accrued interest, premium and liquidated damages, if any.
A registration statement on Form S-4 relating to the Notes was filed with and declared effective by the Securities and Exchange Commission on February 9, 2005. Pursuant to the registration statement, OFC made an offer to the holders of the Notes to exchange them for publicly registered exchange notes with substantially identical terms until March 11, 2005. On March 16, 2005 the exchange offer was completed.
Non-current restricted cash at December 31, 2004 relating to proceeds from the Offering consists of the following:
Galena re-powering construction reserve
As required under the terms of the Notes, the Company was required to set aside approximately $25.8 million ($19.4 million at December 31, 2004) to replace the existing equipment at the Steamboat 1/1A project with more efficient equipment, in order to optimize the geothermal resources available. After such replacement, the Company will rename the Steamboat 1/1A project as the Galena project. The Company expects the re-powering will be complete and the project will achieve commercial operations by the end of 2005.
Also as required under the terms of the Notes, the Company has restricted cash accounts, consisting of the following, which are classified as current on the balance sheet:
Debt service reserve
The Company maintains an account to fund an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the Notes in the following six months. As of December 31, 2004, the restricted cash accounts have been replaced by a letter of credit which was issued by the Company on July 1, 2004 and December 30, 2004 in the total amount of approximately $10.8 million (see Note 17).
Revenue reserve
The Company deposits all revenues received into the revenue account. Such amounts are used to pay operating expenses and fund the debt service reserve account, but the funds are only available to the Company upon submission of draw requests by the Company to the bank. As such amounts are not fully unrestricted to use by the Company, they have been classified as restricted in the balance sheets. As of December 31, 2004, the balance of such account was $0.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Future minimum payments under the Notes, as of December 31, 2004 are as follows:
Refinancing of the Puna project
The Company intends to refinance the acquisition cost of the Puna project by the first half of 2005. In connection with such refinancing the Company signed a term sheet with an equity investor and it is currently holding negotiations with two financial institutions which the Company expects to provide debt financing part of the contemplated leverage lease financing transaction.
In anticipation of the above refinancing, on December 30, 2004, the Company entered into a treasury rate lock agreement ("Rate Lock Agreement") with a financial institution, at a locked-in treasury rate of 4.2693%, with a notional amount of $52.0 million, and terminating on February 28, 2005 (the "Determination Date"). The rate lock is based on a 10-year treasury security that matures on August 15, 2014. Pursuant to the Rate Lock Agreement, if the base treasury rate on the Determination Date is greater than 4.2693%, the counterparty will be required to pay the Company a floating amount; however, if the base treasury rate is less than 4.2693%, the Company will be required to pay to the counterparty the floating amount. If the base treasury rate equals 4.2693% on the Determination Date, no payment will be required to be made by either party. On February 25, 2005, the Company extended the Rate Lock Agreement until March 31, 2005 (the "New Determination Date") at a new lock-in treasury rate of 4.31%. The extended Rate Lock is based on a 10-year treasury security that matures on February 15, 2015. There was no consideration paid by either party as a result of such extension. Based on treasury rates and the yield curve on December 31, 2004, each 1 basis point difference between the locked-in rate and the base treasury rate equaled approximately $42,000.
NOTE 10 - ASSET RETIREMENT OBLIGATION
The Company adopted SFAS No. 143, Accounting for Obligations Associated with the Retirement of Long-Lived Assets, effective January 1, 2003. Under SFAS No. 143, entities are required to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company's legal liabilities include capping wells and post-closure costs of geothermal power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, an entity settles the obligation for its recorded amount or incurs a gain or loss. On January 1, 2003, the Company recorded a cumulative effect of change in accounting principle of $205,000, net of related tax benefit of $125,000.
The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the fourth quarter of 2004, the Company increased the aggregate carrying amount of its asset retirement obligation by $2,210,000. The increase is a result of increased costs associated with drilling rigs, cement and cement services, general manpower, engineering fees and other outside services, since the adoption of SFAS No. 143.
NOTE 11 - STOCK OPTIONS
The 2004 Incentive Compensation Plan
On October 21, 2004, the Company's Board of Directors adopted the 2004 Incentive Compensation Plan ("2004 Incentive Plan"), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights, stock units, performance awards, phantom stock, incentive bonuses and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 1,250,000 shares of the Company's common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. On November 10, 2004, the Company granted incentive stock options to purchase 200,000 shares of common stock to employees and non-qualified stock options to purchase 22,500 shares of common stock to non-employee directors at an exercise price of $15 per share, which represented the fair value of the Company's common stock on such date. Such options will expire ten years from the date of grant, with options granted to employees vesting at 25%, 25% and 50%, in year two, three, and four, respectively, after the date of grant, and options granted to non-employee directors vesting immediately upon the filing of a registration statement by the Company on Form S-8 with the Securities and Exchange Commission with respect to the shares of common stock underlying such option grants. The weighted average fair value of each option as of the grant date is $0.96.
The Parent's Stock Option Plans
The Parent has four stock option plans: the 2001 Employee Stock Option Plan, the 2002 Employee Stock Option Plan, the 2003 Employee Stock Option Plan, and the 2004 Employee Stock Option Plan (collectively "the Parent's Plans"). Options under the 2004 Employee Stock Option Plan were granted in April 2004. Under the Parent's Plans, employees of the Company were granted options in the Parent's ordinary shares, which are registered and traded on the Tel-Aviv Stock Exchange Ltd. Options under the Parent's Plans cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Vested shares may be exercised for up to five years from the date of grant. The maximum aggregate number of shares that may be optioned and sold under the Parent's Plans is determined each year by the board of directors of the Parent, and is equal to the number of options granted during each plan year. None of the options are exercisable or convertible into shares of the Company.
The following table summarizes the status of the Parent's Plans as of and for the periods presented below (shares in thousands):
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company recorded deferred stock compensation for options granted below fair value of $52,000, $14,000 and $149,000 in the years ended December 31, 2004, 2003 and 2002, respectively. These balances represent the difference between the exercise price of the options and the fair market value of the Parent's shares on the date of grant. The deferred stock compensation is being amortized to expense over the vesting period. The amortization of deferred stock compensation for the years ended December 31, 2004, 2003 and 2002 is $61,000, $39,000 and $38,000.
The following table summarizes information about stock options outstanding at December 31, 2004 (shares in thousands):
The following table summarizes information about stock options outstanding at December 31, 2003 (shares in thousands):
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12 - POWER PURCHASE AGREEMENTS
U.S. operations:
The Company has various power purchase agreements in the U.S. as follows:
Southern California Edison Company ("SCE")
The Company has two power purchase agreements ("PPAs") with SCE related to the Ormesa Complex and two PPAs related to Heber 1 and 2 project. The PPAs provide for the sale of capacity and energy through their respective terms, with the following expiration dates: Ormesa PPAs expiring in 2017 and 2018, and Heber 1 and 2 PPAs expiring in 2015 and 2023, respectively. Under the PPAs, the Company receives a fixed energy payment through April 30, 2007, and thereafter an energy payment based on SCE's short-run avoided cost ("SRAC"). The PPAs provide for firm capacity and bonus payments established by the contracts and are paid to the Company each month through the contracts' term based on plant performance. Bonus capacity payments are earned based on actual capacity available during certain peak hours.
In connection with the PPAs for the Ormesa project, SCE has expressed its intent not to pay the contract rate for the power supplied under the Ormesa power purchase agreement as a result of the supply of auxiliary power by the GEM 2 and GEM 3 plants to the Ormesa project . The Company expects to resolve the issue through the sale of the GEM 2 and 3 power that was used to supply auxiliary power to Ormesa, to a different offtaker. In the interim period, SCE has tentatively agreed to pay a lower fixed price for such power. The Company cannot evaluate the potential long-term financial impact of a failure to reach a resolution with SCE, among other things because the current contract rates will fluctuate as of May 2007; however, financial loss at the reduced price paid by SCE for the year ending December 31, 2005 may be in the range of $1 million. The Company is currently negotiating with a third party the sale of an additional 10 MW under a long-term PPA.
The temperature of the geothermal resource at the Heber 1 project has declined since the project commenced operations and as a result the project was operating at a level that was close to the minimum performance requirements set forth in its power purchase agreement. In the first quarter of 2005, the Company completed the construction of a pipeline which increased the project's output generation by 2 MW net. As a result of such construction the Company achieved the minimum performance requirements.
Sierra Pacific Power Company ("SPPC") - Nevada
The Company also has six PPAs with SPPC for operating projects; one related to the Brady Power Plant, two related to the Steamboat 1 and 1A Power Plants, one related to the Steamboat Hills Power Plant, and two related to the Steamboat 2 and 3 Power Plants. The PPAs provide for the sale of energy, and for capacity for all power plants except Brady, through their respective terms, with the following expiration dates: Steamboat 1 and 1A expire in 2006 and 2018, Steamboat Hills expires in 2018, and Brady and Steamboat 2 and 3 expire in 2022. Energy payments under the Brady PPA are based on deliveries during specified winter and summer seasons for on-peak, mid-peak, and off-peak times. Energy payments under the Steamboat 1/1A PPAs are based on the monthly average of the California-Oregon Border power market pricing, which is SPPC's adopted SRAC.
Hawaii Electric Light Company ("HELCO")
The Company has a PPA with HELCO related to the Puna project. The PPA provides for monthly energy payments and capacity payments. The energy payments for a portion of the energy delivered are equal to the higher of the SRAC rates for energy in effect for the relevant billing period
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
or a fixed rate. The energy payments for a smaller portion of energy to be delivered are equal to an amount based on a fuel rate and a variable operation and maintenance rate, as each are adjusted over the term of the agreement, but which rate will never go below a minimum floor. The Puna project also receives a payment for providing reactive power to HELCO.
Foreign operations:
The Company has power purchase agreements in various foreign countries as follows:
The Olkaria III Project (Kenya)
In connection with the agreement with KPLC (see Note 6), the subsidiary in Kenya, sells power to KPLC at the agreed upon price and terms of a 20-year PPA. Fees are paid each month through the term of the agreement and vary based on plant performance.
The Leyte Project (Philippines)
In connection with the BOT agreement with PNOC (see Note 6), OLCL,the subsidiary in the Philippines (which was deconsolidated as from April 1, 2004) converts the steam delivered by PNOC into electric energy required by the National Power Corporation ("NPC") in accordance with the power purchase agreement between NPC and PNOC during the term of the BOT agreement. OLCL receives capacity and energy fees from PNOC established by the BOT agreement. Fees are paid each month through the term of the BOT agreement and vary based on plant performance.
The Momotombo Project (Nicaragua)
In connection with the agreement with NEC (see Note 6), the subsidiary in Nicaragua sells power to two assignees of NEC at the agreed upon price and terms of a "take or pay" power purchase agreement. Fees are paid each month through the term of the agreement and vary based on plant performance.
Pursuant to the terms of certain of the power purchase agreements, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall on delivery of renewable energy and energy credits, and not meeting certain threshold performance requirements, as defined. The amount of payment required is dependent upon the level of shortfall on delivery or performance requirements and is recorded in the period the shortfall occurs. The Brady and Steamboat 2 and 3 PPAs provide that if the project does not maintain peak period capacity values of at least 85% of those listed in each of their respective contracts, the Company will be obligated to pay liquidated damages to SPPC in amounts ranging from $1.0 million to $1.5 million. If the Ormesa and Heber 1 and 2 projects fail to meet minimum performance requirements, as defined, the respective project may be placed on probation, the capacity of the relevant plant may be permanently reduced and, in such an instance, a refund would be owed from such project to SCE. Each of the projects may also reduce the capacity of the plants upon notice to SCE and after making a specified payment to it. If the Puna project does not meet its minimum capacity performance requirement, such project will be required to pay HELCO $0.0214 per on-peak hour for each kilowatt of deficiency for the first 5 MW of deficiency and $0.0339 per on-peak hour for each kilowatt of deficiency in excess of 5 MW of deficiency. In addition, for each contract year in which the on-peak availability of the facility is less than 95%, unless the deficiency is due to a catastrophic equipment failure, the Puna project is required to pay $8,000 to HELCO for each full percentage point of the deficiency, and if such availability is less than 80%, the Puna project is required to pay $12,000 for each full percentage point of the deficiency. The Company has not and does not currently expect to be obligated to make any material payments under their power purchase agreements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As required by EITF 01-8 (see Note 1), the Company assessed all PPAs acquired since July 1, 2003, and concluded that all such PPAs related to our Heber 1 and 2, Steamboat 2/3, Steamboat Hills, and Puna projects (see Note 2) contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the PPA is presented as "lease portion of energy and capacity" revenue, with the remaining revenue related to the production and delivery of the energy being presented as "energy and capacity" revenue in the consolidated statements of operations. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2004 were as follows:
NOTE 13 - INCOME TAXES
Income from continuing operations before provision for income taxes, minority interest, and equity in income of investees consisted of:
The components of income tax expense (benefit) from continuing operations are as follows:
The significant components of the deferred income tax expense (benefit) from continuing operations are as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The difference between the U.S. federal statutory tax rate and the Company's effective rate are as follows:
The net deferred tax assets and liabilities consist of the following:
Realization of the deferred tax assets and investment tax credits is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset at December 31, 2004 will be realized.
At December 31, 2004, the Company had U.S. federal net operating loss ("NOL") carryforwards of approximately $30.0 million and $20.7 million, respectively and state NOL carryforwards of approximately $20.8 million and $7.3 million, respectively, available to reduce future taxable income, which expire between 2021 and 2024 for federal NOLs and between 2023 and 2024 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2004 carry over indefinitely until utilized.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Through June 30, 2004, the Company had net operating loss carryforwards related to its Israeli operations, which were carved out from the Parent, of approximately $14.0 million available to reduce future taxable income, which could be carried over indefinitely until utilized. Further, despite the fact that the net operating losses carryforward indefinitely, there is currently uncertainty as to the Israeli tax laws related to establishing limitations on the use of net operating losses. In addition, there are uncertainties as to the ability to transfer those losses from the Parent. Due to these uncertainties, management believed that it was not more likely than not that such net operating loss carryforwards will be utilized. Subsequent to July 1, 2004, it was determined that the losses could not be transferred, therefore, the deferred tax assets in respect of the Parent's net operating loss carryforwards and the valuation allowance relating to such deferred tax assets were removed.
The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $40 million at December 31, 2004. It is the Company's intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes which may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.
Income taxes related to foreign operations
The Philippines - From OLCL's inception in 1996 to September 2003, OLCL, an 80% owned subsidiary (which was deconsolidated as of April 1, 2004) with operations in the Philippines, had an income tax holiday. Subsequent to September 2003, OLCL is subject to the Philippines regular corporate income tax rate of 32%. The tax holiday, assuming a tax rate of 32%, had the effect of reducing tax expense by $0, $798,000 and $1,978,000 and increasing net income per share by $0, $0.03 and $0.09 for the years ended December 31, 2004, 2003 and 2002, respectively.
Israel - The Company's operations in Israel through OSL are taxed at the regular corporate tax rate of 36% in 2002 and 2003, 35% in 2004, 34% in 2005, 33% in 2006 and 32% in 2007 and thereafter. However, under the Israeli Law for the Encouragement of Capital Investments, some of the operations of OSL have been granted "Approved Enterprise" status under expansion plans of 1996 and 2003, whereby income from the Approved Enterprise, which is determined as the increase of revenues in a particular year compared to those of the program's determined base year (1995 and 2002, respectively), will be exempt from taxes for two years commencing in the first year OSL generates taxable income, which for OSL has not commenced yet, and at a reduced tax rate of 25% for the remaining five years. The Approved Enterprise status plans of 1996 and 2003 expire in 2010 and 2017, respectively.
Other significant foreign countries - The Company's operations in Nicaragua and Kenya are taxed at the rates of 25% and 40%, respectively.
NOTE 14 - BUSINESS SEGMENTS
The Company has two reporting segments that are aggregated based on similar products, market and operating factors: electricity and products segments. Such segments are managed and reported separately as each offers different products and serves different markets. The electricity segment is engaged in the sale of electricity pursuant to power purchase agreements. The products segment is engaged in the manufacture, including design and development, of turbines and power units for the supply of electrical energy and in the associated construction of power plants utilizing the power units manufactured by the Company to supply energy from geothermal fields and other alternative energy sources. Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller's business segment.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information concerning the Company's reportable segments is shown in the following tables:
Reconciling information between reportable segments and the Company's consolidated totals is shown in the following table:
Business segments according to geographical location: The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following table presents certain data by geographic area:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Revenues as reported in the geographic area in which they originate
The following table presents revenues from major customers:
(1) Revenues reported in electricity segment
(2) Revenues reported in products segment
NOTE 15 - TRANSACTIONS WITH RELATED ENTITIES
Transactions between the Company and the related entities during the years presented below and balances as of the dates presented below, other than those disclosed elsewhere in these financial statements, approximated:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has an agreement with the Parent whereby, for a fee, the Parent maintains certain standby letters of credit on behalf of the Company. During the years ended December 31, 2004, 2003 and 2002, the fees under the agreement totaled approximately $548,000, $709,000 and $783,000, respectively.
The current liability due to Parent at December 31, 2004 and 2003 of $18,484,000 and $151,000, respectively, represents the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest is computed on balances greater than 60 days at LIBOR plus 1%, however not less than the change in the Israeli Consumer Price Index plus 4%, compounded quarterly, and is accrued and paid to the Parent annually.
Notes payable to Parent
In 2003, the Company entered into a loan agreement with the Parent, which was further amended on September 20, 2004 ("Parent Loan Agreement") pursuant to which the Company may borrow from the Parent up to $150 million in one or more advances. Interest accrues on the unpaid principal of the loan amount at a rate per annum of the Parent's average effective interest plus 0.3% (7.5% during 2004 and 2003). The principal and interest on the Parent Loan Agreement are payable in varying amounts through the loan due date of June 2010. The outstanding balance of such loan at December 31, 2004 and 2003 was $143,187,000 (including current portion of $22,047,000) and $126,339,000, respectively. As further discussed in Note 1, on June 29, 2004, $20 million outstanding under the Parent Loan Agreement was converted to 1,160,714 shares of $0.001 par value common stock of the Company.
In 2003, the Company entered into a NIS 240 million non-interest bearing note agreements with the Parent. Principal is payable upon demand at any time after November 2007, but no later than December 2009. The loan is subordinated to all other liabilities of the Company. In accordance with the terms of such note, the Company will not be required to repay any amount in excess of $50,669,000 (using the exchange rate existing on the date of such note). As of December 31, 2004 the ceiling of $50,669,000 is effective.
Future minimum payments under the notes payable to Parent (excluding the non-interest bearing note) as of December 31, 2004 are as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reimbursement agreement
On July 15, 2004, the Company entered into a reimbursement agreement with its Parent pursuant to which the Company agreed to reimburse its Parent for: (i) any draws made on any standby letter of credits issued by the Parent for the benefit of the Company; and (ii) any payments made under any guarantee provided by the Parent for the benefit of the Company. Interest on any amounts owing pursuant to the reimbursement agreement is payable at a rate per annum equal to the Parent's average effective cost of funds plus 0.3% in U.S. dollars.
Registration rights agreement
Prior to the closing of the Company's initial public offering in November 2004, the Company and the Parent entered into a registration rights agreement pursuant to which the Parent may require the Company to register its common stock for sale on Form S-1 or Form S-3. In addition, the Company will be required to file a registration statement on Form S-3 to register for sale of its common stock that are or have been acquired by directors, officer and employees of the Parent upon the exercise of the options granted to them by the Parent. The Company also agreed to pay all expenses that result from the registration of the Company's common stock under the registration rights agreement, other than underwriting commissions for such shares and taxes. The Company has also agreed to indemnify the parent, its directors, officer and employees against liability that may result from their sale of the Company's common stock, including Securities Act liabilities.
NOTE 16 - EMPLOYEE BENEFIT PLAN
401(k) Plan
Prior to July 1, 2002, the Company had a Simple IRA ("IRA Plan") plan covering substantially all employees of the Company, ages 21 or older, with minimum service requirements. The Company contributed 2% of the eligible employees' compensation for the year, and $6,000 to the plan for the six-month period ended June 30, 2002. On July 1, 2002 the Company discontinued making contributions to the IRA Plan, as the Company exceeded the maximum number of employees allowed for such a plan due to the purchase of the Ormesa Project. Any amounts remaining in the IRA Plan will continue to be invested, and earnings applied to the participating employees' accounts. All contributions after July 1, 2002 are made into the Company's 401(k) plan, discussed below.
On July 1, 2002 the Company established a 401(k) Plan (the "Plan") for the benefit of its employees. Employees of the Company who have completed one year of service or who had one year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to 60% of their annual salary. Contributions made by the Company are matched up to a maximum of 2% of the employee's annual salary. The Company's contributions to the Plan were $185,000, $83,000 and $46,000 for the years ended December 31, 2004, 2003 and 2002.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Severance plan
The Company, through OSL, provides limited non-pension benefits to all current employees in Israel who are entitled to benefits in the event of termination or retirement in accordance with the Israeli Government sponsored programs. These plans generally obligate the Company to pay one month's salary per year of service to employees in the event of involuntary termination. There is no limit on the number of years of service in calculation of the benefit obligation. The liabilities for these plans are accounted for under the guidance of EITF Issue No. 88-1, Determination of Vested Benefit Obligation for a Defined Benefit Pension Plan, using what is commonly referred to as the "shut down" method, where a company records the undiscounted obligation as if it were payable at each balance sheet date. Such liabilities have been presented on the balance sheet as "Liability for severance pay". The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to $10,503,000 and $9,440,000 at December 31, 2004 and 2003, of which $9,187,000 and $8,227,000 was restricted, respectively, and has been presented on the balance sheet as part of "Deposits and other". Under the Israeli severance pay law, restricted funds may not be withdrawn or pledged until the respective severance pay obligations have been met. As allowed under the program, earnings from the investment are used to offset severance pay costs. Severance pay expenses for the years ended December 31, 2004, 2003 and 2002 were $537,000, $511,000 and $456,000, respectively, which includes losses (income) amounting to $(122,000) $65,000 and $8,000, respectively, generated from the regular deposits and amounts accrued in severance funds.
NOTE 17 - COMMITMENTS AND CONTINGENCIES
Geothermal resources
The Company, through its project subsidiaries in the United States, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management ("BLM") or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the lessors as defined in the respective agreements. Royalties expense under the geothermal resource agreements were $4,716,000, $2,283,000 and $572,000 for the years ended December 31, 2004, 2003 and 2002, respectively.
Letters of credit
In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit and other financial guarantees obtained by the Parent and issued on behalf of the Company totaling $25,794,000 and $19,736,000 at December 31, 2004 and 2003, respectively. Management does not expect any material losses to result from these off-balance-sheet instruments because performance is not expected to be required, and, therefore, is of the opinion that the fair value of these instruments is zero.
LOC Agreement
On June 30, 2004, a subsidiary of the Company entered into a letter of credit and loan agreement ("LOC Agreement") with a bank pursuant to which the bank agreed to issue one or more letters of credit aggregating to $15 million. The LOC Agreement expires on June 30, 2007, which shall be extended for successive one-year periods unless notice is provided by either the Company or the bank to the contrary. In the event that the bank is required to pay on a letter of credit drawn by the beneficiary thereof, such letter of credit converts into a loan, bearing interest at LIBOR plus 4.0%, to be repaid in equal installments at the end of each of the next four quarters. There are various restrictive covenants in the LOC Agreement, which include maintaining certain levels of tangible net
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
worth, leverage ratio, and minimum coverage ratio. At December 31, 2004 the Company was in compliance with the covenants under the LOC Agreement. On July 1, 2004, a letter of credit amounting to $8,125,000 and on July 6, 2004, another letter of credit amounting to $3,644,000 were issued under the LOC Agreement, which have been used to replace cash on deposit in reserve funds that were used as a pledge against the OFC Notes and the Beal Bank Credit Agreement. The amount on one of the letters of credit was increased by $2,674,000 on December 30, 2004.
Grants and royalties
The Company, through OSL, has historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. OSL is required to pay royalties to the Israeli Government at a rate of 3.5% to 5.0% of the revenues derived from products and services developed using such grants, and amounted to $1,883,000, $1,171,000 and $700,000 for the years ended December 31, 2004, 2003 and 2002, respectively. The Company is not liable for royalties if the Company does not sell the respective products. Such royalties are capped at the amount of the grants received plus interest at LIBOR, and the cap at December 31, 2004 and 2003, amounted to $5,617,000 and $7,166,000, respectively, of which approximately $1,165,000 and $825,000 of the cap, respectively, increases based on the LIBOR rate, as defined.
In addition, OSL is obligated to pay royalties to an unaffiliated entity at 2% of its domestic sales up to a cumulative amount of $9.25 million, and royalties at a rate of 0.2% of revenues on the next $5.4 million related to a certain technology that is not currently being utilized. However, no royalties will be paid after 30 years have elapsed from the completion of the related project. OSL has not derived any revenues from this technology to date, nor have any royalties been paid to date.
Employment agreements
The Company has employment agreements with four of its senior executive officers, the terms of which expire at various times through June 2008. Such agreements provide for monthly or annual base salary amounts, as well as for bonus and other benefits. The aggregate commitment for future salaries at December 31, 2004, excluding bonuses and benefits, was approximately $1.7 million.
Such executives are also entitled to change in control payments, whereby, if within three years following the occurrence of a change in control, the Company terminates the employee or the employee terminates his or her employment for good reason, as defined, or if, within 180 days following a change in control, the employee terminates his or her employment, the Company is required to pay 24 months of such employee's monthly base salary at the time of the change in control, plus unpaid and accrued base salary and bonuses. The aggregate of 24 months of these executive's base salary, excluding bonuses and benefits, as of December 31, 2004 approximated $0.9 million.
Contingencies
In response to an order issued by a California State Court of Appeals, the California Public Utilities Commission ("CPUC"), has commenced an administrative proceeding in order to address short run avoided cost ("SRAC") pricing for Qualifying Facilities for the period spanning from December 2000 to March 2001. The court directed that the CPUC modify SRAC pricing on a retroactive basis to the extent that the CPUC determined that SRAC prices were not sufficiently "accurate" or "correct." On February 15, 2005, the CPUC issued a draft decision affirming that SRAC priced during the disputed period were corrected and compliant with the Public Utility Regulated Policies Act ("PURPA") requirements and that no retroactive adjustments are warranted. Comments on the draft may be filed and a final decision from the CPUC could happen in late March or early
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
April 2005. If the SRAC prices charged during the period in question were determined by the CPUC to not be "accurate" or "correct," retroactive price adjustments could be required for any of the Company's Qualifying Facilities in California whose payments are tied to SRAC pricing, including the Heber 1, Mammoth and Ormesa projects. Currently it is not possible to predict the outcome of such proceedings; however, any retroactive price adjustment required to be made in relation to any of the Company's projects may require such projects to make refund payments or charge less for future sales, which could materially and adversely effect the business, the financial condition, future results and cash flow of the Company.
Steamboat Geothermal LLC ("SG") is party to litigation related to a dispute over amounts owed to the plaintiffs under certain operating agreements. SG has initiated settlement discussions with the plaintiff and the Company believes that any outcome will not have a material impact on the Company's results of operations.
The Company is a defendant in various other legal suits in the ordinary course of business. It is the opinion of the Company's management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the results of operations and financial condition of the Company.
Certain of the Company's projects are subject to contested Federal Energy Regulatory Commission ("FERC") rulings whereby an adverse outcome could result in a refund of a portion of previous revenues and/or a reduction in future revenues from those projects. The outcome of this matter cannot be predicted at this time.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 18 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 19 - SUBSEQUENT EVENTS (UNAUDITED)
On December 9, 2004, the Company received a purchase order in the amount of $16.9 million for the supply of 102 remote power units for communication and cathodic protection along a pipeline of the Sakhalin Island in the Russian Federation. The order remained subject to final approval by the customer, which was received on January 28, 2005.
On January 4, 2005, through a newly established project subsidiary, the Company entered into a 25-year power purchase agreement ("PPA") with Basin Electric Power Corporation, according to which the Company will supply approximately 22 MW from recovered energy generation power plants. The power plants are to be constructed between 15 and 18 months from the effectiveness of the PPA. The power plants will be constructed on gas compressor stations along a Natural Gas pipeline in North and South Dakota. The PPA has not yet become effective and is subject to certain conditions.
On February 14, 2005, two of the Company's subsidiaries entered into a contract for the supply and engineering procurement of a geothermal power plant on Sao Miguel Island in the Azores in the total amount of Euro 19.2 million (approximately $25 million).
On March 22, 2005, by a unanimous written consent of the Board of Directors, the Company declared, approved and authorized the payment of an additional dividend of $0.03 per share, on account of fourth quarter profits, to all issued and outstanding shares of common stock of the Company on April 4, 2005, payable on April 18, 2005.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES
a. Evaluation of disclosure controls and procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities and Exchange Act of 1934, as amended, as of the end of the period covered by this annual report. The evaluation included certain control areas in which we have made, and are continuing to make, changes to improve and enhance controls. Based on that evaluation as of December 31, 2004, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) were effective to ensure that the information required to be disclosed by us in this annual report on Form 10-K was recorded, processed, summarized and reported accurately and within the time periods specified within the SEC's rules and instructions for Form 10-K. In designing and evaluating the disclosure controls and procedures, management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost benefit relationship of possible controls and procedures.
b. Changes in internal controls over financial reporting
There were no changes in our internal controls over financial reporting in the fourth quarter of 2004 that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
Recently, we began to enhance our documentation and further analyze our system of internal controls. We have initially identified areas of our internal controls requiring improvement, and are in the process of designing enhanced processes and controls to address issues identified through this review. An area of improvement includes enhancing and streamlining our domestic and international financial reporting procedures. We plan to continue this initiative, as well as prepare for our first management report on internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, on December 31, 2005.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this Item in addition to that below is incorporated by reference herein from the Company's definitive 2005 Proxy Statement.
Directors and Executive Officers Information
The following table sets forth the name, age and positions of our directors, executive officers, persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:
Name
Age
Position
Lucien Bronicki
Chairman of the Board of Directors;
Chief Technology Officer(3)
Yehudit "Dita" Bronicki
Chief Executive Officer; President; Director(2)
Yoram Bronicki
Chief Operating Officer-North America; Director (1)
Joseph Tenne
Chief Financial Officer*(4)
Lisa Kidron
Vice President of Financial Controls*
Nadav Amir
Executive Vice President-Engineering, *
Hezy Ram
Executive Vice President-Business Development, North America**
Joseph Shiloah
Executive Vice President-Marketing and Sales, Rest of the World*
Zvi Reiss
Executive Vice President-Project Management*
Aaron Choresh
Vice President-Operations Rest of the World and Product Support*
Zvi Krieger
Vice President-Geothermal Engineering*
Etty Rosner
Vice President-Contract Administrator; Corporate Secretary*
Connie Stechman
Vice President
Independent Directors:
Dan Falk
Independent Director (3)
Edward R. Muller
Independent Director (1)
Jacob J. Worenklein
Independent Director (2)
* Performs the functions described in the table, but is employed by Ormat Systems.
** Performs the functions described in the table, but is employed by Ormat Nevada.
(1) Denotes Class I Director - Term expiring at 2005 Annual Shareholders Meeting
(2) Denotes Class II Director - Term expiring at 2006 Annual Shareholders Meeting
(3) Denotes Class III Director - Term expiring at 2007 Annual Shareholders Meeting
(4) Mr. Tenne was appointed Chief Financial Officer on March 9, 2005.
Lucien Bronicki. Lucien Bronicki is the Chairman of our Board of Directors, a position he has held since our inception in 1994, and is also our Chief Technology Officer, effective as of July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the Board of Directors of Ormat Industies, the publicly-traded successor to Ormat Turbines Ltd., and various of its subisidiaries. Since 1992, Mr. Bronicki has been the Chairman of the Board of Directors of Bet Shemesh Engines, a manufacturer of jet engines, and of OPTI Canada Inc. Since 1997, Mr. Bronicki has been the Chairman of the Board of Bet Shemesh Holdings, Mr. Bronicki is also the Chairman of the Board of Directors of Orad Hi-Tec Systems Ltd., a manufacturer of image processing systems, and
was the Co-Chairman of Orbotech Ltd., a NASDQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. Mr. Bronicki has worked in the power industry since 1958. He is a member of the Executive Council of the Weizmann Insitutute of Science and chairs the Israeli Committee of the World Energy Council. Yehudit Bronicki and Lucien Bronicki are married. Mr. Bronicki obtained a postgraduate degree in Nuclear Engineering from Conservatoire National des Arts et Metiers in 1958 and a Master of Science in Physics from Universite de Paris in 1958 and a Master of Science in Mechanical Engineering from Ecole Nationale Superieure d'Ingenieurs Arts et Metiers in 1957.
Yehudit "Dita" Bronicki. Yehudit "Dita" Bronicki is our Chief Executive Officer, effective as of July 1, 2004, and is also a member of our Board of Directors and our President, positions she has held since our inception in 1994, and was our Secretary from 1994 through November 2004. Mrs. Bronicki is also the President of Ormat Systems, effective as of July 1, 2004. Mrs. Bronicki was also a co-founder of Ormat Turbines Ltd. and is a member of the Board of Directors and the General Manager (a CEO-equivalent position) of Ormat Industries, the publicly-traded successor to Ormat Turbines Ltd., and various of its subsidiaries. Since 1992, Mrs. Bronicki has also been a director of Bet Shemesh Engines. Mrs. Bronicki is also a member of the Board of Directors of OPTI Canada Inc., and of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. From 1994 to 2001, Mrs. Bronicki was on the Advisory Board of the Bank of Israel. Mrs. Bronicki has worked in the power industry since 1965. Yehudit Bronicki and Lucien Bronicki are married. Mrs. Bronicki obtained a Bachelor of Arts in Social Sciences from Hebrew University in 1965.
Yoram Bronicki. Yoram Bronicki is our Chief Operating Officer, North America, effective as of July 1, 2004. Mr. Bronicki is also a member of the Board of Directors of Ormat Industries, a position he has held since 2001, and a member of the Board of Directors of OPTI Canada Inc. Mr. Bronicki was appointed a director of Ormat Technologies, Inc. as of November 12, 2004. From 2001 to 2004, Mr. Bronicki was Vice President of OPTI Canada Inc. From 1999 to 2001, he was Project Manager of Ormat Industries and Ormat International. From 1996 to 1999, he was Project Manager of Ormat Industries, and from 1995 to 1996, he was Project Engineer of Ormat Industries. Mr. Bronicki is the son of Lucien and Yehudit Bronicki. Mr. Bronicki obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1989 and a Certificate from the Technion Insitute of Management Senior Executives Program.
Joseph Tenne. Effective on March 9, 2005, Mr. Joseph Tenne was appointed Chief Financial Officer of the Company. From 2003 to 2004, Mr. Tenne was the Chief Financial Officer of Treofan Germany GmbH & Co. KG, a German company. From 1997 until 2003, Mr. Tenne was a partner in Kesselman & Kesselman, Certified Public Accountants in Israel (a member firm of PricewaterhouseCoopers International Limited). Mr. Tenne is also a member of the Board of Directors of AudioCodes Ltd., a NASDAQ-listed company. Mr. Tenne obtained a Master of Business Administration from Tel Aviv University in 1987 and a Bachelor of Arts in Accounting and Economics from Tel Aviv University in 1981. Mr. Tenne is a Certified Public Accountant in Israel.
Lisa Kidron. Effective on March 9, 2005, and in connection with the appointment of Joseph Tenne as the new Chief Financial Officer for the Company, Lisa Kidron ceased serving as the Company's Chief Financial Officer and assumed the position of Vice President of Financial Controls. Ms. Kidron performed the functions of Chief Financial Officer of Ormat Systems from July 1, 2004 to March 9, 2005. Ms. Kidron is the Chief Financial Officer of Ormat Industries, a position she has held since 2002. From 2000 to 2002, Ms. Kidron was Chief Financial Officer at MUL-T-LOCK Ltd. and from 1999 to 2000, Ms. Kidron was Chief Financial Officer at MUL-T-LOCK Technologies Ltd. Ms. Kidron served as a director on the boards of various subsidiaries within the MUL-T-LOCK group from 1999 to 2002. Until 1999, Ms. Kidron was a senior manager in the accounting firm Kost-Forrer & Gabai (Ernst & Young, Global Services). Ms. Kidron obtained an L.L.M. Degree in Law from Bar-Ilan University in 2002, a Bachelor of Arts in Accounting from Tel Aviv University in 1994, a Master of Science in Industrial Engineering from Ben Gurion University in 1987 and a Bachelor of Science in Computer Science and Mathematics from Rutgers University in 1985.
Nadav Amir. Nadav Amir performs the function of our Executive Vice President of Engineering, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Amir was Executive Vice President of Engineering of Ormat Industries, from 1993 to 2001, he was Vice President of Engineering of Ormat Industries, from 1988 to 1993, he was Manager of Engineering of Ormat Industries, from 1984 to 1988, he was Manager of Product Engineering of Ormat Industries, and from 1983 to 1984, he was Manager of Research and Development of Ormat Industries. Mr. Amir obtained a Bachelor of Science in Aeronautical Engineering from Technion Haifa in 1972.
Hezy Ram. Hezy Ram performs the function of our Executive Vice President of Business Development in North America, a position he has held since January 1, 2004. From 1999 through December 31, 2003, Mr. Ram was Vice President of Business Development of Ormat Industries. Mr. Ram obtained a Master of Business Administration from Hebrew University in 1978, a Master of Science in Mechanical Engineering from Ben Gurion University in 1977 and a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.
Joseph Shiloah. Joseph Shiloah performs the function of our Executive Vice President of Marketing and Sales, Rest of the World, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Shiloah was the Executive Vice President of Marketing and Sales at Ormat Industries, from 1989 to 2000, he was Vice President of Marketing and Sales of Ormat Industries, from 1983 to 1989, he was Vice President of Special Projects of Ormat Turbines Ltd., from 1984 to 1989, he was Operating Manager of the Solar Pond project of Solmat Systems Ltd., a subsidiary of Ormat Turbines Ltd., and from 1981 to 1983, he was Project Administrator of the Solar Pond power plant project of Ormat Turbines Ltd. and Solmat Systems Ltd. Mr. Shiloah obtained a Bachelor of Arts in Economics from Hebrew University in 1972.
Zvi Reiss. Zvi Reiss performs the function of our Executive Vice President of Project Management, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Reiss was the Executive Vice President of Project Management of Ormat Industries, from 1995 to 2000, he was Vice President of Project Management of Ormat Industries and, from 1993 to 1994, he was Director of Projects of Ormat Industries. Mr. Reiss obtained a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.
Aaron Choresh. Aaron Choresh performs the function of our Vice President of Operations and Product Support, Rest of the World, effective as of July 1, 2004. From 1999 through June 30, 2004, Mr. Choresh was the Vice President of Operations and Product Support of Ormat Industries, from 1993 to 1998, he was the Director of Operations and Product Support of Ormat Industries, from 1991 to 1992, he was Manager of Project Engineering and Product Support, and from 1989 to 1990, he was Manager of Project Engineering of Ormat Industries. Mr. Choresh obtained a Bachelor of Science in Electrical Engineering from Technion Haifa in 1982.
Zvi Krieger. Zvi Krieger performs the function of our Vice President of Geothermal Engineering, effective as of July 1, 2004. From 2001 through June 30, 2004, Mr. Krieger was the Vice President of Geothermal Engineering of Ormat Industries. Mr. Krieger has been with Ormat Industries since 1981 and served as Application Engineer, Manager of System Engineering, Director of New Technologies Business Development and Vice President of Geothermal Engineering. Mr. Krieger obtained a Bachelor of Science in Mechanical Engineering from the Technion, Israel Institute of Technology in 1980.
Etty Rosner. Etty Rosner performs the function of our Corporate Secretary, effective as of July 1, 2004. Ms. Rosner is also the Corporate Secretary of Ormat Industries, a position she has held since 1991, and Vice President of Contract Management of Ormat Industries, a position she has held since 1999. From 1991 to 1999, Ms. Rosner was Contract Administrator Manager and Corporate Secretary and from 1981 to 1991, she was the Manager of the Export Department and Office Administrative Manager. Ms. Rosner obtained a Diploma in General Management from Tel Aviv University in 1990.
Connie Stechman. Connie Stechman is our Vice President, a position she has held since our inception in 1994. Prior to joining Ormat Technologies, Inc., Ms. Stechman worked for an
international public accounting firm. Ms. Stechman is a Certified Public Accountant and obtained a Bachelor of Science in Business and Concentration Accounting from California State University, Sacramento, in 1977.
Dan Falk. Dan Falk was appointed as a director of Ormat Technologies, Inc. as of November 12, 2004. Mr. Falk is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., ClickSoftware Technologies Ltd. and Jacada Ltd, all NASDAQ publicly traded companies. In addition, Mr. Falk serves as a member of the Board of Directors of the following public non-US companies: Dor Chemicals Ltd., Visionix Ltd., Orad Hi-Tech Systems Ltd., Dmatek Ltd., and Poalim Ventures I Ltd. From 2001 to 2004, Mr. Falk was a business consultant to several public and private companies. From 1999 to 2000, Mr. Falk was Chief Operating Officer and Chief Exeuctive Officer of Sapiens International NV. From 1995 to 1999, Mr. Falk was an Executive Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbot Systems Ltd. and of Orbotech Ltd. Mr. Falk obtained a Master of Business Administration from Hebrew University in 1972 and a Bachelor of Arts in Economics and Political Science from Hebrew University in 1968. Mr. Falk is the Chair of Ormat Technologies, Inc.'s Audit Committee. The Board of Ormat Technologies, Inc. has determined that Mr. Falk qualifies as an Audit Committee "financial expert" under Section 407 of the Sarbanes-Oxley Act of 2002 and Item 401(h) of Regulation S-K, and is "independent" as that term is used in Item 7(d)(3)(IV) of Schedule 14A under the Securities Exchange Act of 1934.
Edward R. Muller. Edward Muller was appointed a director of Ormat Technolgies, Inc. as of November 12, 2004. Mr. Muller is also a member of the Board of Directors of GlobalSantaFe Corp. and The Keith Companies, Inc. Since 2000, Mr. Muller has been a private investor. From 1993 to 2000, Mr. Muller was President and Chief Executive Officer of Edison Mission Energy, a wholly owned subsidiary of Edison International. During his tenure, Edison Mission Energy was engaged in developing, owning and operating independent power production facilities worldwide. From 1999 to 2000, Mr. Muller was Deputy Chairman of the Board of Directors of Contact Energy Ltd., a New Zealand electric generation company partially owned by Edison Mission Energy. Mr. Muller obtained a Bachelor of Arts in History from Dartmouth College in 1973 and a Juris Doctor in Law from Yale Law School in 1976.
Jacob J. Worenklein. Jacob Worenklein was appointed a director of Ormat Technologies, Inc. as of November 12, 2004. Mr. Worenklein is also President and Chief Executive Officer of US Power Generating Company. From 1998 to 2003, he was Managing Director and Global Head of Project and Sectorial Finance for Societe Generale and, from 1996 to 1998, he was Managing Director and Head of Project Finance, Export Finance and Commodities for the Americas, for Societe Generale. Prior to joining Societe Generale in 1996, Mr. Worenklein was Managing Director and Global Head of Project Finance at Lehman Brothers and prior thereto was a partner and member of the executive committee of the law firm of Milbank, Tweed, Hadley & McCloy LLP, where he founded and headed the firm's power and project finance practice. Mr. Worenkein served as Adjunct Professor of Finance at New York University and is a trustee of the Committee for Economic Development and a member of the Council on Foreign Relations. He is a member of the Board of Directors and Audit Committee of CDC Globeleq, an affiliate of the UK's Commonwealth Development Corporation. Mr. Worenklein obtained a Bachelor of Arts from Columbia College in 1970 and a Juris Doctor and Master of Business Administration from New York University in 1973.
Audit Committee
We are a listed issuer, as defined in Sec. 240.10A-3 of Regulation S-K, and have a separately designated audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934, composed of independent directors as required by Section 303A.07 of the NYSE Listed Company Manual. The members of such committee are Dan Falk (Chair), Edward Muller and Jacob Worenklein, who are also independent directors of our company, as defined in Section 303A.02 of the NYSE Listed Company Manual.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required under this item is incorporated by reference herein from the Company's definitive 2005 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under this item is incorporated by reference herein from the Company's definitive 2005 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under this item is incorporated by reference herein from the Company's definitive 2005 Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required under this item is incorporated by reference herein from the Company's definitive 2005 Proxy Statement.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) List of Financial Statements
See Index to Financial Statements at Item 8 of this annual report.
(2) List of Financial Statement Schedules
All applicable schedules information is included in our Financial Statements at Item 8 of this annual report.
(c) EXHIBIT INDEX
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
ORMAT TECHNOLOGIES, INC.
Date: March 28, 2005
By:
/s/Yehudit Bronicki
Name: Yehudit Bronicki
Title: Chief Executive Officer,
President and Director
Pursuant to the requirement of the Securities Act of 1934, this annual report has been signed below by the following persons on behalf of the Registrant in the capacities indicated, on March 28, 2005.
(c) EXHIBIT INDEX