ITEM 1. BUSINESS
Certain Definitions
Unless the context otherwise requires, all references in this annual report to ‘‘Ormat’’, ‘‘the Company’’, ‘‘we’’, ‘‘us’’, ‘‘our company’’, ‘‘Ormat Technologies’’ or ‘‘our’’ refer to Ormat Technologies, Inc. and its consolidated subsidiaries. The ‘‘OFC Senior Secured Notes’’ refers to the 8¼% Senior Secured Notes due 2020 that were issued in February 2004 by our subsidiary, Ormat Funding Corp. The ‘‘OrCal Senior Secured Notes’’ refers to the 6.21% Senior Secured Notes due 2020 that were issued in December 2005 by our subsidiary, OrCal Geothermal Inc.
Overview
We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture. Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while all of our recovered energy-based plants have been constructed by us. We conduct our business activities in two business segments, which we refer to as our Electricity Segment and Products Segment. In our Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In our Products Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. Both our Electricity Segment and Products Segment operations are conducted in the United States and throughout the world. We currently own or control, as well as operate, geothermal projects in the United States, Guatemala, Kenya and Nicaragua, as well as recovered energy generation (REG) plants in the United States.
The charts below show the relative contributions of the Electricity Segment and the Products Segment to our consolidated revenues and the geographical breakdown of our segment revenues for our fiscal year ended December 31, 2007. Additional information concerning our segment operations, including year-to-year comparisons of revenues, the geographical breakdown of revenues, cost of revenues, results of operations, and trends and uncertainties is provided below in Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and Item 8 - ‘‘Financial Statements and Supplementary Data’’.
The following chart sets forth a breakdown of revenues for the year ended December 31, 2007:
The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity Segment for the year ended December 31, 2007:
The following chart sets forth the geographical breakdown of the revenues attributable to our Products Segment for the year ended December 31, 2007:
Most of the projects that we currently own or operate produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable form of energy derived from the natural heat of the earth. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Therefore, electricity produced from geothermal energy sources contributes significantly less to local and regional incidences of acid rain and global warming than energy produced by burning fossil fuels. Geothermal energy is also an attractive alternative to other sources of energy as part of a national diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.
In addition to our geothermal energy business, we have developed and continue to develop products that produce electricity from recovered energy or so-called ‘‘waste heat’’. We also own and are constructing new recovered energy projects to be owned and operated by us. Recovered energy or waste heat represents residual heat that is generated as a by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Such residual heat, that would otherwise be wasted, may be captured in the recovery process and used by recovered energy power plants to generate electricity without burning additional fuel and without emissions.
Company Contact and Sources of Information
We file annual, quarterly and periodic reports, proxy statements and other information with the Securities and Exchange Commission, which we refer to as the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and other information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the Internet at that website.
On May 17, 2007, we submitted to the New York Stock Exchange (NYSE) an Annual Written Affirmation, in the prescribed form and with no qualifications, regarding our compliance with the NYSE’s Corporate Governance listing standards. In addition, our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports are available at our website www.ormat.com for downloading,
free of charge, as soon as reasonably practicable after these reports are filed with the SEC. Our Code of Business Conduct and Ethics, Code of Ethics Applicable to Senior Executives, Audit Committee Charter, Corporate Governance Guidelines, Nominating and Corporate Governance Committee Charter, Compensation Committee Charter, and Insider Trading Policy, as amended, are also available at our website address mentioned above. The content of our website, however, is not part of this annual report.
You may request a copy of our SEC filings, as well as the foregoing corporate documents, at no cost to you, by writing to the Company address appearing in this annual report or by calling us at (775) 356-9029.
Our Power Generation Business
We own or control, and operate geothermal and recovered energy projects in the United States. We also own or control, and operate geothermal projects in Guatemala, Kenya and Nicaragua. We continue to pursue opportunities to acquire and develop similar projects throughout the world. Most of our projects are located in regions where there is, or is expected to be, demand for additional generating capacity. During 2007, we completed the construction of power plants that added an additional 61 megawatts (MW) to our owned generating capacity. Our ownership interest in generating capacity was increased by 14 MW between December 31, 2006 and December 31, 2007. This change is primarily attributable to the following:
• A reduction of 39 MW in our owned generating capacity, attributable to our September 25, 2007 transfer of the Leyte power plant to PNOC Energy Development Corporation, upon termination of a Build, Operate, and Transfer agreement under which we previously owned and operated the power plant.
• An increase of 17 MW, attributable to the Galena 3 project at the Steamboat complex, which commenced commercial operation on February 21, 2008
• An increase of 10 MW, attributable to the Galena 2 project at the Steamboat complex, which commenced commercial operation in the second quarter of 2007;
• An increase of 20 MW, attributable to the completion of Amatitlan geothermal power plant in Nicaragua;
• An increase of 14 MW, attributable to increased generating capacity of our existing geothermal power plants, which was achieved during the second quarter of 2007; and
• A reduction of 7 MW in the generating capacity at our Brady complex, attributable to the shutdown of the Desert Peak 1 project in the first quarter of 2007.
Projects in Operation
The table below summarizes certain key non-financial information relating to our projects that are in operation as of February 28, 2008:
Projects under Ownership(1)
(1) We own and operate all of our projects, except the Momotombo project in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government, and the Mammoth project, in which we have a 50% ownership interest.
(2) References to generating capacity refers to the gross capacity less auxiliary power, in the case of all of our existing domestic projects and the Momotombo, Amatitlan and Olkaria III projects (three 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 Zunil project (one of our foreign projects). We determine the generating capacity figures in any given year from available historical operational data of our operating projects taking into account resource capabilities. This column represents the generating capacity of the project, not our net ownership in such generating capacity.
In any given year, the actual power generation of a particular project may differ from that project’s generating capacity due to operational issues affecting performance during that year. In 2007, the total actual power generation of the projects we operate in the U.S. was 282,618 MWh lower than the energy potential commensurate with our generating capacity due to operational factors discussed elsewhere in this annual report.
(3) The Heber complex includes the Heber 1 and 2 projects and the Gould project.
(4) The Steamboat complex includes the Steamboat 1 and 1A projects, the Steamboat 2 and 3 projects, the Burdette project, the Steamboat Hills project, the Galena 2 project, and the Galena 3 project which reached commercial operation on February 21, 2008.
(5) The initial term of the power purchase agreement expired on December 31, 2006, but it continues to be in effect until either party terminates it on a one month notice.
(6) The power purchase agreement for the Olkaria III project will expire 20 years from the completion of Phase II of this project. Phase II of this project involves the construction of additional facilities that we expect would add approximately 35 MW of generating capacity to this project. See ‘‘Description of our Projects’’ below.
Projects under Construction
The table below summarizes certain key non-financial information relating to projects that were under construction as of December 31, 2007:
(1) We are currently negotiating a power purchase agreement with Southern California Public Power Authority and Southern California Edison for this project.
(2) The power purchase agreement for the Olkaria III Phase II project will expire 20 years from the completion of Phase II.
(3) Two units of the OREG II projects are expected to come on line by the end of 2008 or early 2009 and the other two units are expected to come on line by the end of 2009.
(4) The power purchase agreement is currently under negotiation with Hawaii Electric Light Company.
(5) The power purchase agreement for the Peetz project will expire the earlier of 20 years from the commercial operation date or the end of 2029.
Projects under Development
The table below summarizes certain key non-financial information relating to projects under development, which, if implemented, will come on-line after 2009:
(1) The GRE project is a recovered energy generation power plant.
(2) We are currently negotiating a power purchase agreement with Great River Energy
(3) Currently our ownership interest in the project is 25%, but we expect to reduce it to 12.75%.
(4) The contract will expire 360 months after completion of the last stage of the project, and in all cases 504 months after the effective date of the contract, which is subject to financing closing.
Almost all of the revenues that we currently derive from the sale of electricity are pursuant to long-term power purchase agreements. Approximately 76.4% of our total revenues in the year ended December 31, 2007 from the sale of electricity by our domestic projects were derived from power purchasers that currently have investment grade credit rating. The purchasers of electricity from our foreign projects are either state-owned entities or private entities. We have obtained political risk insurance from the Multilateral Investment Guarantee Agency of the World Bank Group (MIGA) or from Zurich Re, a private sector political risk insurer, for all of our foreign projects (with the exception of the Zunil project for which we are currently negotiating insurance coverage) 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, development of new power plants and the expansion and enhancement of our existing projects, including the following: (i) We completed the construction of the 10 MW Galena 2 and 17 MW Galena 3 power plants, which were added to the Steamboat complex, (ii) we increased the generating capacity of the Ormesa complex by an additional 10 MW; and (iii) we completed the construction of the 20 MW Amatitlan project in Guatemala. We currently expect to continue growing our power generation business through:
• the development and construction of new geothermal and recovered energy-based power plants;
• the expansion and enhancement of our existing projects;
• the acquisition of additional geothermal and other renewable assets from third parties; and
• the entry into geothermal leases for future development.
As part of these efforts, we regularly monitor requests for proposals from, and submit bids to, investor-owned and other electric utilities in the United States to provide additional generating capacity, primarily in the western United States where geothermal resources are generally concentrated. During 2007, we responded to several requests for proposals issued by different utilities interested in purchasing renewable energy. Our proposals covered approximately 120 MW of capacity in Nevada and California. There can be no assurance, however, that we will succeed in negotiating power purchase agreements with the various utilities. We also respond to international tenders issued by foreign state-owned electric utilities for the development, construction and operation of new geothermal power plants. In addition, we apply our technological expertise to upgrade the facilities of our existing geothermal power plants and to continuously monitor and manage our existing geothermal resources in order to increase the efficiency and generating capacity of such facilities.
We are currently in varying stages of development of new projects and construction of new and existing projects. Based on our current development and construction schedule, which is subject to change at any time and which may not be met in its entirety, we expect to declare commercial operation of the 10 MW Heber South project during the first half of 2008, and of the 50 MW North Brawley project by the end of 2008. In addition, we expect to add approximately 84 MW in generating capacity from geothermal and recovered energy power plants in the United States by the end of 2009 or early 2010. Outside of the U.S., we expect to complete the construction of the 35 MW Olkaria III Phase II project in Kenya by the end of 2008. In addition, we expect to add approximately 10 MW from the GDL project in New Zealand, in which we have a 49% ownership interest.
The total of owned generating capacity that we have under construction and under development is between 286 and 322 MW.
We are a member in a consortium, which is in the process of developing a geothermal power project in Indonesia of approximately 340 MW that is expected to come on line in phases between 2010 and 2012. The consortium is currently negotiating a power purchase agreement with a local utility. We estimate that our minority interest will be equivalent to 43 MW, taking into account the reduction in our ownership in the consortium from 25% to 12.75%.
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.
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.
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.
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.
History
We were formed by Ormat Industries Ltd. (also referred to in this annual report as the ‘‘Parent’’, ‘‘Ormat Industries’’, ‘‘the parent company’’ or ‘‘our parent’’) in 1994 in the State of Delaware for the purpose of investing and holding ownership interests in power projects, as well as constructing and operating power plants owned by us and by third parties. Ormat Industries, which is based in Israel, is an international power systems company whose predecessor, Ormat Turbines Ltd., was founded in 1965 by Lucien and Dita Bronicki for the principal purpose of developing equipment for the production of a clean, renewable and generally sustainable form of energy. Ormat Industries sold to us its business relating to the manufacturing and sale of energy-related equipment and services. Following this sale, we now hold all of Ormat Industries’ power generation products business. Ormat Industries owns approximately 60.3% of our outstanding common stock.
Industry Background
Geothermal Energy
Most of our projects in operation produce electricity from geothermal energy. Geothermal energy is a clean, renewable and generally sustainable energy source that, because it does not utilize combustion in the production of electricity, releases significantly lower levels of emissions, principally steam, than those that result from energy generation based on the burning of fossil fuels. Geothermal energy is derived from the natural heat of the earth when water comes sufficiently close to hot molten rock to heat the water to temperatures of 300 degrees Fahrenheit or more. The heated water then ascends toward the surface of the earth where, if geological conditions are suitable for its commercial extraction, it can be extracted by drilling geothermal wells. The energy necessary to operate a geothermal power plant is typically obtained from several such wells which are drilled using established technology that is in some respects similar to that employed in the oil and gas industry. Geothermal production wells are normally located within approximately one to two miles of the power plant as geothermal fluids cannot be transported economically over longer distances due to heat and pressure loss. The geothermal reservoir is a renewable source of energy if natural ground water sources and reinjection of extracted geothermal fluids are adequate over the long-term to replenish the geothermal reservoir following the withdrawal of geothermal fluids and if the well field is properly operated. Geothermal energy projects typically have higher capital costs (primarily as a result of the costs attributable to well field development) but tend to have significantly lower variable operating costs, principally consisting of maintenance expenditures, than fossil fuel-fired power plants that require ongoing fuel expenses.
Geothermal Power Plant Technologies
Geothermal power plants generally employ either binary systems or conventional flash systems, as described below. 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 saturated steam, which drives a turbine generator to produce electricity. In some cases, the brine at the outlet of the separator is flashed a second time (dual flash), providing additional steam at lower pressure used in the low pressure section of the steam turbine to produce additional electricity. Steam exhausted from the steam turbine is condensed in a surface or direct contact condenser cooled by cold water from a cooling tower. The non-condensable gases (such as carbon dioxide) are removed through the removal system in order to optimize the performance of the steam turbines. The condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected back into the geothermal resource through a series of injection wells. The flash technology is depicted in the graphic below.
In some instances, the wells directly produce dry steam (the flashing occurring under ground). In such cases, the steam is fed directly to the steam turbine and the rest of the system is similar to the flash power plant described above.
Market Opportunity
The geothermal energy industry in the United States experienced significant growth in the 1970s and 1980s, followed by a period of consolidation of owners and operators of geothermal assets in the 1990s. The industry, once dominated by large oil companies and investor-owned electric utilities, now includes several independent power producers. During the 1990s, growth and development in the geothermal energy industry occurred primarily in foreign markets, and only minimal growth and development occurred in the United States. Since 2001, there has been renewed interest in geothermal energy in the United States as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation, due to the increasing cost of natural gas, and as legislative and regulatory incentives, such as state renewable portfolio standards, have become more prevalent.
Although electricity generation from geothermal resources is currently concentrated in California, Nevada, Hawaii, Idaho and Utah, there are opportunities for development in other states such as Alaska, Arizona, New Mexico and Oregon due to the availability of geothermal resources and, in some cases, a favorable regulatory environment in such states.
The Western Governors Association (WGA) estimates that 13,000 MW of identified resources will be developed by 2025. Of that amount, 5,600 MW is expected to be added by 2015, assuming geothermal generated electricity remains at competitive prices (taking into account production tax credits).
In January 2007, the Massachusetts Institute of Technology published a study that projects a potential of 100,000 MW of generating capacity from geothermal power plants if the development of enhanced geothermal systems is successful.
An additional factor fueling recent growth in the renewable energy industry is global concern about the environment. Power plants that use fossil fuels generate higher levels of air pollution and their emissions have been linked to acid rain and global warming. In response to an increasing demand for ‘‘green’’ energy, many countries have adopted legislation requiring, and providing incentives for, electric utilities to sell electricity generated from renewable energy sources. In the United States, Arizona, California, Colorado, Connecticut, Delaware, Hawaii, Illinois, Iowa, Maine, Maryland, Massachusetts, Minnesota, Missouri, Montana, New Hampshire, Nevada, New Jersey, New Mexico, New York, North Carolina, North Dakota, Oregon, Pennsylvania, Rhode Island, Texas, Virginia, Vermont, Washington, Wisconsin and the District of Colombia have all adopted renewable portfolio standards, renewable portfolio goals, or other similar laws requiring or encouraging electric utilities in such states to generate or buy a certain percentage of their electricity from renewable energy sources or recovered heat sources. Twenty states (including California, Nevada and Hawaii, where we have been the most active in our geothermal energy development and in which all of our U.S. geothermal projects are located) and the District of Columbia define geothermal resources as ‘‘renewables’’ and seven states recognize recovered heat sources as eligible for renewable portfolio standards. A bill establishing renewable portfolio standards is currently before the Kansas legislature.
We believe that these legislative measures and initiatives present a significant market opportunity for us. For example, California generally requires that each investor-owned electric utility company operating within the state increase the amount of renewable generation in its resource mix by 2% per year so that 20% of its retail sales are procured from eligible renewable energy sources by 2010, ahead of the previous statutory mandated target of December 2017. California’s three large electric utilities collectively served 13.2% of their 2006 electricity retail sales with renewable power. Nevada’s renewable portfolio standard requires each Nevada electric utility to obtain 9% of its annual energy requirements from renewable energy sources in 2007-2008, which requirement thereafter increases by 3% every two years until 2015, when 20% of such annual energy requirements must be provided from renewable energy sources or energy efficiency projects. As of December 2006, 6% of the electricity
retail sales in Nevada were from renewable energy sources Hawaii’s renewable portfolio standard requires each Hawaiian electric utility to obtain 10% of its net electricity sales from renewable energy sources by December 31, 2010 and 20% by December 31, 2020. In 2006, Hawaiian Electric Company and its subsidiaries achieved a consolidated renewable portfolio standard of 13.8%.
In addition to renewable portfolio standards, several federal climate change proposals are being considered. For example, the Lieberman-Warner Climate Security Act (S. 2191) was approved by the United States Senate Environment and Public Works Committee on December 5, 2007. This bill would place a cap on greenhouse gas emissions and require increasing reductions in greenhouse gas emissions. In the absence of federal legislation, states are passing greenhouse gas legislation. For example, on September 27, 2006, the California Global Warming Solutions Act of 2006 (the Act) was signed into law. The Act regulates most sources of greenhouse gas emissions and is expected to result in a reduction of carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies, one of which may involve the use of market-based trading of emissions rights. In addition to California, sixteen other states have set greenhouse gas emissions targets (Arizona, Connecticut, Florida, Hawaii, Illinois, Massachusetts, Maine, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington). Regional Initiatives are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. For example, many northeastern states are part of the Regional Greenhouse Gas Initiative (‘‘RGGI’’), a regional cap-and trade system to limit carbon dioxide. In addition to RGGI, other states have also established the Midwestern Regional Greenhouse Gas Reduction Accord and the Western Climate Initiative. Although individual and regional programs will take some time to develop, their requirements, particularly the creation of any market-based trading mechanism to achieve compliance with emissions caps, should be advantageous to in-state and in-region (and, in some cases, such as RGGI and the state of California, inter-regional) energy generating sources that have low carbon emissions such as geothermal energy. Although it is currently hard to quantify the direct economic benefit of these efforts to reduce greenhouse gas emissions, we believe they will prove advantageous to us.
The federal government also encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit’’, which in 2007 was 2.0 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. The owner of the project must choose between the production tax credit and the 10% investment tax credit described above. In either case, under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward. Whether we claim the production tax credit or the investment credit, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost may be deducted in the first few years than during the remainder of the depreciation period. If we claim the investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a production tax credit; there is no reduction in the tax basis for depreciation.
Collectively, these tax benefits (to the extent fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new project.
On December 15, 2007, delegates from nearly 190 nations, including the U.S., announced in Bali the adoption of a plan that will be negotiated through 2009 and ultimately would succeed the Kyoto Protocol following 2012.
Outside of the United States, the majority of power generating capacity has historically been owned and controlled by governments. Since the early 1990s, however, many foreign governments
have privatized their power generation industries through sales to third parties and have encouraged new capacity development and/or refurbishment of existing assets by independent power developers. These foreign governments have taken a variety of approaches to encourage the development of competitive power markets, including awarding long-term contracts for energy and capacity to independent power generators and creating competitive wholesale markets for selling and trading energy, capacity and related products. Some countries have also adopted active governmental programs designed to encourage clean renewable energy power generation. Several Latin American countries have rural electrification programs and renewable energy programs. For example, Guatemala, where our Zunil and Amatitlan projects are located, approved in November 2003 a law which creates incentives for power generation from renewable energy sources by, among other things, providing economic and fiscal incentives such as exemptions from taxes on the importation of relevant equipment and various tax exemptions for companies implementing renewable energy projects. We believe that these developments and governmental plans will create opportunities for us to acquire and develop geothermal power generation facilities internationally as well as create additional opportunities for us to sell our remote power units and other products.
In addition to our geothermal power generation activities, we are pursuing recovered energy-based power generation opportunities in North America and the rest of the world. We believe recovered energy-based power generation will benefit from the increased attention to energy efficiency. For example, in the United States, FERC has indicated its position that the primary goal of natural gas pipeline design should be the efficient, least cost transportation of fuel, including using waste heat (recovered energy) from combustion turbines or reciprocating engines that drive station compressors to generate electricity for use at compressor stations or to generate electricity for sale. Recently, FERC has requested natural gas pipeline operators filing for a certificate of approval for new pipeline construction or expansion projects to discuss ‘‘opportunities to enhance efficiencies for any energy consumption processes in the development and operation’’ of the new pipeline. We have initially targeted the North American market, where we have begun to build power plants, which generate electricity from ‘‘waste heat’’ from gas turbine-driven compressor stations along interstate natural gas pipelines, from midstream gas processing facilities, and from processing industries in general.
Further supporting recovered energy-based power generation, several states, as well as the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Nevada, Connecticut, New Mexico and Hawaii allow electric utilities to include recovered energy-based power generation in calculating their compliance with renewable portfolio standards. In addition, North Dakota, South Dakota and the U.S. Department of Agriculture (through the Rural Utilities Service) have approved recovered energy-based power generation units as renewable energy resources, which qualifies recovered energy-based power generators (whether in those two states or elsewhere in the United States) for federally funded, low interest loans. We believe that the European market has similar potential and we expect to leverage our early success in North America in order to expand into Europe and other markets worldwide. In North America alone, we estimate the potential total market for recovered energy-based power generation to be approximately 1,000 MW.
Competitive Strengths
Competitive Assets. Our assets are competitive for the following reasons:
• Contracted Generation. Virtually all of the electricity generated by our geothermal power plants is currently sold pursuant to long-term power purchase agreements, providing generally predictable cash flows.
• Baseload Generation. All of our geothermal power plants supply a part of the baseload capacity of the electric system in their respective markets, meaning that they operate to serve all or a part of the minimum power requirements of the electric system in such market on an around-the-clock basis. Because our projects supply a part of the baseload needs of the respective electric system and are only marginally weather dependent, we have a competitive
advantage over other renewable energy sources, such as wind power, solar power or hydro-electric power (to the extent dependent on precipitation), which compete with us to meet electric utilities’ renewable portfolio requirements but which cannot serve baseload capacity because of the weather dependence and thus intermittent nature of these other renewable energy sources.
• Competitive Pricing. Geothermal power plants, while site specific, are economically feasible to develop, construct, own and operate in many locations, and the electricity they generate is generally price competitive as compared to electricity generated from fossil fuels or other renewable sources under existing economic conditions and existing tax and regulatory regimes.
Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating projects produce electricity from geothermal energy sources. Geothermal energy is a clean, renewable and generally sustainable energy source. Unlike electricity produced by burning fossil fuels, electricity produced from geothermal energy sources is produced without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide. Such clean and sustainable characteristics of geothermal energy give us a competitive advantage over fossil fuel-based electricity generation as countries increasingly seek to balance environmental concerns with demands for reliable sources of electricity.
High Efficiency from Vertical Integration. Unlike our competitors in the geothermal industry, we are a fully-integrated geothermal equipment, services and power provider. We design, develop and manufacture most of the equipment we use in our geothermal power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our projects efficiently and to respond to operational issues in a timely and cost-efficient manner. Moreover, given the efficient communications among our subsidiary that designs and manufactures the products we use in our operations and our subsidiaries that own and operate our projects, we are able to quickly and cost effectively identify and repair mechanical issues and to have technical assistance and replacement parts available to us as and when needed.
Highly Experienced Management Team. We have a highly qualified senior management team with extensive experience in the geothermal power sector. Key members of our senior management team have worked in the power industry for most of their careers and average over 20 years of industry experience.
Technological Innovation. We own or have rights to use over 75 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, developing and constructing new geothermal and recovered energy-based power projects and entering into long-term power purchase agreements providing stable cash flows in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development and which meet our investment criteria;
• Developing Recovered Energy Projects - establishing a first-to-market leadership position in recovered energy projects in North America and building on that experience to expand into other markets worldwide;
• Acquisition of New Assets - acquiring from third parties additional geothermal and other renewable assets that meet our investment criteria;
• Increasing Output from Our Existing Projects - increasing output from our existing geothermal power projects by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery; and
• Technological Expertise - investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities.
Operations of our Power Generation Segment
How We Own Our Power Plants. We customarily establish a separate subsidiary to own interests in each power plant. Our purpose in establishing a separate subsidiary for each plant is to ensure that the plant, and the revenues generated by it, will be the only source for repaying indebtedness, if any, incurred to finance the construction or the acquisition (or to refinance the acquisition) of the relevant plant. If we do not own all of the interest in a power plant, we enter into a shareholders agreement or a partnership agreement that governs the management of the specific subsidiary and our relationship with our partner in connection with our project. Our ability to transfer or sell our interest in certain projects may be restricted by certain purchase options or rights of first refusal in favor of our project partners or the project’s power purchasers and/or certain change of control and assignment restrictions in the underlying project and financing documents. All of our domestic projects, with the exception of the Puna project, which is an Exempt Wholesale Generator (EWG), are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and are eligible for regulatory exemptions from most provisions of the Federal Power Act (FPA) and certain state laws and regulations.
How We Obtain Development Sites and Geothermal Resources. For domestic projects, we either lease or own the sites on which our power plants are located. In our foreign projects, our lease rights for the plant site are generally contained in the terms of a concession agreement or other contract with the host government or an agency thereof. In certain cases, we also enter into one or more geothermal resource leases (or subleases) or a concession or other agreement granting us the exclusive right to extract geothermal resources from specified areas of land, with the owners (or sublessors) of such land. A geothermal resource lease (or sublease) or a concession or other agreement will usually give us the right to explore, develop, operate and maintain the geothermal field including, among other things, the right to drill wells (and if there are existing wells in the area, to alter them) and build pipelines for transmitting geothermal fluid. In certain cases, the holder of rights in the geothermal resource is a governmental entity and in other cases a private entity. Usually, the terms of the lease (or sublease) and concession agreement correspond to the terms of the relevant power purchase agreement. In certain other cases, we own the land where the geothermal resource is located, in which case there are few restrictions on its utilization. Leasehold interests in federal land in the United States are regulated by the Bureau of Land Management and the Minerals Management Service. These agencies recently issued separate final rules revising the geothermal leasing process. The new rules include, among other things, a requirement that geothermal resources be offered through a competitive lease process; the introduction of a new royalty methodology; the introduction of increased rental payments; a new scheme of lease terms and extensions; and new ‘‘production incentives’’ for new facilities and qualified expansion facilities that are put into commercial operation by August 8, 2011, in the form of a four-year 50% reduction in royalties from what would otherwise be due.
How We Explore and Evaluate Geothermal Resources. Historically we have located and developed proven geothermal resources. In 2006, we expanded our activities to include the exploration and identification of geothermal resources. After entering into an appropriate lease we carry out several tests followed by exploratory drilling first to validate and then to quantify the size of the potential geothermal resource. Resource validation and exploratory drilling is a long process that requires substantial capital investment, as it may necessitate the drilling of shallow temperature-gradient wells, ‘‘slim holes’’, exploration wells, and production-sized exploration wells. We do not expect to succeed in developing every resource that undergoes exploration activity.
How We Sell Electricity. In the United States, the purchasers of power from our projects are typically investor-owned electric utility companies. Outside of the United States, the purchaser is typically a state-owned utility or distribution company or a recently privatized state-owned entity and we typically operate our facilities pursuant to rights granted to us by a governmental agency pursuant to a concession agreement. In each case, we enter into long-term contracts (typically called power purchase agreements) for the sale of electricity or the conversion of geothermal resources into electricity. A project’s revenues under a power purchase agreement usually consist of two payments: energy payments and capacity payments (although our recent power purchase agreements provide for energy payments only). Energy payments are normally based on a project’s electrical output actually delivered to the purchaser measured in kilowatt hours, with payment rates either fixed or indexed to the power purchaser’s ‘‘avoided’’ costs (i.e., the costs the power purchaser would have incurred itself had it produced the power it is purchasing from third parties, such as us). Capacity payments are normally calculated based on the generating capacity or the declared capacity of a project available for delivery to the purchaser, regardless of the amount of electrical output actually produced or delivered. In addition, most of our domestic projects located in California are eligible for capacity bonus payments under the respective power purchase agreements upon reaching certain levels of generation.
How We Operate and Maintain Our Power Plants. We usually employ one of our subsidiaries, (Ormat Nevada Inc., for our domestic projects) to act as operator of our power plants pursuant to the terms of an operation and maintenance agreement. Our operations and maintenance practices are designed to minimize operating costs without compromising safety or environmental standards while maximizing plant flexibility and maintaining high reliability. Our approach to plant management emphasizes the operational autonomy of our individual plant managers and staff to identify and resolve operations and maintenance issues at their respective projects; however, each project draws upon our available collective resources and experience and that of our subsidiaries. We have organized our operations such that inventories, maintenance, backup and other operational functions are pooled within each project complex and provided by one operation and maintenance provider. This approach enables us to realize cost savings and enhances our ability to meet our project availability goals.
We currently own 400 MW of generating capacity (See Note (2) page 9 for an explanation of how we determine the generating capacity of our projects). As a result of our vertical integration, our proprietary technology and our operational and maintenance expertise, we have been successful in increasing the capacity, efficiency and performance of most of our acquired facilities in California, Hawaii and Nevada, and were able to use the staff required to operate these facilities more efficiently. For example, we have been able to increase the output of the Ormesa project by approximately 10 MW following its acquisition in 2002. We have also increased the capacity of the Heber complex by 10 MW.
Safety is a key area of concern to us. We believe that the most efficient and profitable performance of our projects can only be accomplished within a safe working environment for our employees. Our compensation and incentive program includes safety as a factor in evaluating our employees, and we have a well-developed reporting system to track safety and environmental incidents at our projects.
How We Finance Our Power Plants. Historically we have funded our projects with a combination of non-recourse or limited recourse debt, lease financing, parent company loans, funds
for which are derived from various liquidity sources available to us, as discussed in Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ under the heading ‘‘Liquidity and Capital Resources’’ and internally generated cash. Such leveraged financing permits the development of projects with a limited amount of equity contributions, but also increases the risk that a reduction in revenues could adversely affect a particular project’s ability to meet its debt obligations. Leveraged financing also means that distributions of dividends or other distributions by plant subsidiaries to us are contingent on compliance with financial and other covenants contained in the financing documents.
Non-recourse debt or lease financing refers to debt or lease arrangements involving debt repayments or lease payments that are made solely from the project’s revenues (rather than our revenues or revenues of any other project) and generally are secured by the project’s physical assets, major contracts and agreements, cash accounts and, in many cases, our ownership interest in that project affiliate. These forms of financing are referred to as ‘‘project financing’’. Project financing transactions generally are structured so that all revenues of a project are deposited directly with a bank or other financial institution acting as escrow or security deposit agent. These funds then are payable in a specified order of priority set forth in the financing documents to ensure that, to the extent available, they are used first to pay operating expenses, senior debt service (including lease payments) and taxes and to fund reserve accounts. Thereafter, subject to satisfying debt service coverage ratios and certain other conditions, available funds may be disbursed for management fees or dividends or, where there are subordinated lenders, to the payment of subordinated debt service.
In the event of a foreclosure after a default, our project affiliate owning the project would only retain an interest in the assets, if any, remaining after all debts and obligations have been paid in full. In addition, incurrence of debt by a project may reduce the liquidity of our equity interest in that project because the interest is typically subject both to a pledge in favor of the project’s lenders securing the project’s debt and to transfer and change of control restrictions set forth in the relevant financing agreements.
Limited recourse debt refers to project financing as described above with the addition of our agreement to undertake limited financial support for the project affiliate in the form of certain limited obligations and contingent liabilities. These obligations and contingent liabilities take the form of guarantees of certain specified obligations, indemnities, capital infusions and agreements to pay certain debt service deficiencies. To the extent we become liable under such guarantees and other agreements in respect of a particular project, distributions received by us from other projects and other sources of cash available to us may be required to be used to satisfy these obligations. To the extent of these limited recourse obligations, creditors of a project financing of a particular project may have direct recourse to us.
Recently, we have also used a financing structure to monetize production tax credits and other favorable tax benefits derived from the financed projects (as fully described under Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’, under the heading ‘‘OPC Tax Monetization Transactions’’).
How We Mitigate International Political Risk. We generally purchase insurance policies to cover our exposure to certain political risks involved in operating in developing countries, as described below under the heading ‘‘Insurance’’. 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 generally cover, subject to the limitations and restrictions contained therein, 80% to 90% of our revenue loss derived from a specified governmental act such as confiscation, expropriation, riots, the inability to convert local currency into hard currency and, in certain cases, the breach of agreements. We have obtained such insurance for all of our foreign projects in operation with the exception of the Zunil project for which we are currently negotiating insurance coverage.
Recent Developments
• In February 2008, we received a $20 million limited notice to proceed under a fixed-price, date-certain EPC contract to be signed with Nevada Geothermal Power (NGP) to supply and construct the Phase1 power plant of NGP’s planned geothermal power project at Blue Mountain, Nevada. We will commence detailed engineering design, manufacturing and purchasing of certain long-lead items for the project in order to meet the guaranteed substantial completion date of December 31, 2009. Full release of the EPC contract is subject to finalizing of the financing for the project and is expected to occur before June 30, 2008. The EPC contract to be entered with NGP will add approximately $55 million to the $20 million of the limited notice to proceed, bringing the total EPC contract to $75 million.
• During the year ended December 31, 2007, we achieved several milestones related to our projects and operations:
• We acquired two drilling rigs, one of which is used for the drilling of production wells and the second of which is used for exploratory drilling.
• In December 2007, the Sarulla consortium (consisting of our wholly owned subsidiary, a subsidiary of Medco Energi Internasional Tbk, and Itochu Corporation of Japan) developing the 340 MW Sarula project in Indonesia completed the execution of the project documents. The consortium signed an Amendment to the Joint Operating Contract (JOC) with PT Pertamina Geothermal Energy (PGE), a wholly owned subsidiary of the Indonesian state-owned oil and gas company, PT Pertamina (Persero), and, together with PGE, signed an Amendment to the Energy Sale Contract (ESC) with the state-owned Indonesian power company, PT Perusahaan Listrik Negara (PLN).
• We commenced commercial operation of the Desert Peak 2, Galena 2, and Amatitlan projects.
• We completed the construction of additional Ormat Energy Converter (OEC) units in the Ormesa and Steamboat complexes.
• During the last month of 2007 and the first two months of 2008, we have entered into several supply agreements for delivery of our equipment to various customers, thus increasing our product backlog by approximately $16 million. The projected delivery dates under these agreements are during the fourth quarter of 2008 and the first quarter of 2009.
• In December 2007, we signed a 20-year power purchase agreement with Southern California Edison Company (Southern California Edison) for the sale of 30 MW of energy to be produced from a new power plant that will be built in Imperial Valley, California. The power purchase agreement includes an option to increase the capacity of the plant and the amount of energy to be sold up to 100 MW at our discretion, and is subject to the approval of the California Public Utilities Commission. We estimate that the new Imperial Valley power plant will come on line by mid 2012.
• In November 2007, the Nevada Public Utilities Commission approved a new 20-year power purchase agreements that we entered into in May 2007 with Nevada Power Company, a subsidiary of Sierra Pacific Resources, for the sale of 18-30 MW of energy to be produced from the Grass Valley geothermal power plant that we plan to build in Lander County in northern Nevada. We estimate that the Grass Valley project will come on line in late 2010.
• On October 26, 2007, we completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under a shelf registration statement filed in early 2006. Net proceeds to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $137.2 million. On the same date, we completed an unregistered sale of 381,254 shares of common stock to our parent, Ormat Industries Ltd., at a price of $45.90 per share, or approximately $17.5 million in the aggregate. A portion of the proceeds from the block trade and the unregistered sale of shares was used to repay a capital
note owed to our parent in the amount of $50.7 million. On January 8, 2008, we completed another unregistered sale of 693,750 shares of common stock to our parent at a price of $48.02 per share, or approximately $33.3 million. The proceeds of that sale will be used for general corporate purposes, which may include construction of geothermal and recovered energy generation power plants and other investments, and the financing of possible acquisitions.
• In August 2007, we secured lease agreements for seven new sites covering approximately 68,900 acres of federal land in Nevada through a competitive auction conducted by the Bureau of Land Management. Our winning bid was for a total amount of approximately $8.2 million. We expect that this additional acreage will support our growth plans in the years to come; however, there is no assurance that all of the leases will yield sufficient (if any) geothermal resources suitable for commercial projects. This is in addition to other lease agreements in Nevada and California that we have signed since the beginning of the year.
• In August 2007, we entered into a $5.7 million agreement with Italcementi Group of Bergamo, Italy, for the supply of one OEC for a new REG power plant. The OEC is to be installed in the Martinsburg, West Virginia cement plant, belonging to Essroc, an Italcementi subsidiary in the US. The equipment is to be supplied within 14 months from the contract date. The Italcementi Group will construct the REG power plant. When completed, the REG power plant will convert unused exhaust air from the cement plant’s clinker cooler into electric power.
• In July 2007, we signed a 20-year power purchase agreement with Highline Electric Association, a consumer-owned cooperative serving load in Colorado and Nebraska, for the sale of electricity generated from a 4 MW Ormat REG facility to be constructed along a natural gas compression station near Denver, Colorado. The facility will convert the recovered waste heat from the exhaust of existing gas turbines into clean energy, and is expected to be commissioned in mid-2009. We will own and operate this facility through the term of the power purchase agreement.
• In June 2007, we signed a 20-year power purchase agreement with Southern California Edison for the sale of 50 MW of energy to be produced from the North Brawley project, which we are currently constructing in Imperial County, California. The power purchase agreement includes an option to increase the capacity of the plant and the amount of energy to be sold up to 100 MW at our discretion and is subject to the approval of the California Public Utilities Commission. We estimate that the North Brawley project will come on line by the end of 2008.
• In May 2007, we reached agreement with Sierra Pacific Power Company and Nevada Power Company, the purchasers of electricity generated by our existing and planned geothermal power projects in Nevada, regarding certain amendments to the power purchase agreements for a number of our existing geothermal projects in operation and some of our geothermal projects under development and construction. These amendments (i) provide for a mechanism to share production tax credits with the relevant purchaser pursuant to a reduction in the price for electricity paid by the power purchaser under the relevant power purchase agreement, bringing additional power purchase agreements in line with the production tax credit sharing arrangements included in other power purchase agreements with these purchasers in Nevada, (ii) revise certain generation thresholds based on a more definitive understanding of the geothermal resource at the respective projects, and (iii) address certain delays in meeting contract milestones as a result of ordinary course project construction delays. The amendments are subject to the approval of the Public Utilities Commission of Nevada. If the amendments are not approved, we may face claims from the power purchasers under the power purchase agreements stemming from the project delays and reduced power generation.
• In May 2007, pursuant to an existing Power Purchase Option Agreement with Basin Electric Power Cooperative (Basin Electric) that we signed in January 2007, we entered into four out
of the five definitive 25-year power purchase agreements. Under these agreements we will sell electricity that will be produced by four new Ormat REG facilities that will have a net capacity of 5.5 MW each. These facilities will convert the recovered waste heat from the exhaust of existing gas turbines at compressor sites located on the Northern Border natural gas pipeline into clean energy. Two plants are expected to be commissioned at the end of 2008 or early 2009, and the other two, in late 2009. We have secured the rights to the waste heat for all five facilities.
• In April 2007, we received a 21 million New Zealand dollars order (approximately $15.4 million at the date of the order) from Geothermal Development Ltd (GDL), a company in which we own 49%, to supply and construct a geothermal power plant in Kawerau, New Zealand. Ormat will also provide the required construction loan. GDL expects to sell electricity produced by the project to Bay of Plenty Electricity of New Zealand under an existing 7-year power purchase agreement extendable an additional 5 years by mutual agreement. We have an option to acquire the remaining 51% of GDL before the completion of construction. Construction is expected to be completed by late 2008 or early 2009.
• In March 2007, we entered into an $11.5 million contract with ENAGAS, S.A. of Madrid, Spain for the supply of one OEC unit for a REG plant. The REG plant is being specially designed to use the residual energy from the vaporization process of a Liquefied Natural Gas regasification terminal located in Huelva, Spain. The equipment is scheduled to be supplied and installed within 26 months from the receipt of a notice to proceed, which has not yet been received.
Description of Our Projects
In the year ended December 31, 2007, revenues from the sale of electricity by our domestic geothermal and recovered energy projects were $180.0 million, constituting 83.3% of our total revenues from the sale of electricity, and revenues from the sale of electricity by our foreign geothermal projects were $36.0 million, constituting 16.7% of our total revenues from the sale of electricity.
Domestic Projects
Our projects in operation in the United States have a generating capacity of approximately 310MW. Our current domestic projects are located in California, Nevada, Hawaii, North Dakota, and South Dakota. We also have geothermal projects under construction or enhancement in California, Nevada and Hawaii and recovered energy projects in Montana, Minnesota, North Dakota and Colorado.
The Ormesa Complex
The Ormesa complex is located in East Mesa, Imperial County, California. The Ormesa complex consists of six plants. The various plants commenced commercial operations between 1987 and 1989. The plants utilize binary and flash systems. The Ormesa complex had a generating capacity of 47 MW, which we successfully increased to 57 MW in the first quarter of 2007. The Ormesa complex sells its electrical output to Southern California Edison Company (Southern California Edison) under an amended power purchase agreement, which consolidated the previous power purchase agreements dated June 13, 1984 and July 18, 1984, respectively. The amended power purchase agreement, which will expire in 2018, preserved the material terms of the previous agreements; however, the amended agreement provides for the supply of an additional 10MW of electrical output. The Ormesa complex was acquired by us in April 2002, was initially refinanced with project finance debt from United Capital, and was refinanced again with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Ormesa complex (and any and all proceeds arising therefrom). Our project subsidiary, Ormesa LLC, the direct owner of the Ormesa complex, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes.
The Heber Complex
The Heber complex consists of the Heber 1 project, the Heber 2 project and the Gould project.
The Heber 1 Project. The Heber 1 project is located in Heber, Imperial County, California. The Heber 1 project includes one power plant, which commenced commercial operations in 1985, and a geothermal resource field. The plant utilizes a dual flash system and has a generating capacity of approximately 38 MW. The Heber 1 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2015. In certain circumstances, Southern California Edison and its affiliated entities have a right of first refusal to acquire the power plant. Upon satisfaction of certain conditions specified in the power purchase agreement and subject to receipt of requisite approvals and negotiations between the parties, our project subsidiary will have the right to demand that Southern California Edison purchase the power plant. The acquisition of the Heber 1 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal Geothermal Inc. (OrCal) of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber complex (and any and all proceeds arising therefrom). Our project subsidiary, Heber Geothermal Company, the direct owner of the Heber 1 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.
The Heber 2 Project. The Heber 2 project is also located in Heber, Imperial County, California. The Heber 2 project includes one power plant which commenced commercial operations in 1993. The plant utilizes a binary system and has a generating capacity of approximately 34 MW. The Heber 2 project sells its electrical output to Southern California Edison under a long-term power purchase agreement, which will expire in 2023. The acquisition of the Heber 2 project in December 2003 was financed with equity and non-recourse debt from Beal Bank, and was refinanced with the proceeds from the issuance by OrCal of its Senior Secured Notes on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom) and our project subsidiary, Second Imperial Geothermal Company, the direct owner of the Heber 2 project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.
The Gould Project. The Gould project is also located in Heber, Imperial County, California. The Gould project consists of a bottoming-cycle OEC at Heber 1 and additional Ormat Integrated Two Level Units (ITLU) at Heber 2 and has a total generating capacity of 10 MW. The project sells its electrical output under a new long-term power purchase agreement with Southern California Public Power Authority. This power purchase agreement will expire in 2031. The construction of the Gould project was financed with equity, and was included in the financing of OrCal’s Senior Secured Notes issued on December 8, 2005. The OrCal Senior Secured Notes are collateralized by all of the assets of the Heber Complex (and any and all proceeds arising therefrom). Our project subsidiary, OrHeber 2 Inc., the direct owner of the Gould project, has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed OrCal’s obligations under the OrCal Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OrCal Senior Secured Notes.
The Steamboat Complex
The Steamboat complex, located in Washoe County, Nevada, consists of the Steamboat 1/1A project, the Steamboat 2/3 project, the Burdette project, the Steamboat Hills project, the Galena 2 project and the Galena 3 project, which recently reached commercial operation.
The complex is comprised of 8 power plants with a combined generating capacity of 84 MW. The complex currently is not operating at full capacity due to temporary production failures. The Steamboat 1A, Steamboat 2/3, Burdette, Steamboat Hills, and Galena 3 projects sell their electrical output to Sierra Pacific Power Company under separate long-term power purchase agreements, which expire in 2018, 2022, 2026, 2018 and 2028, respectively. The Steamboat 1 project sells its electrical output to Sierra Pacific Power Company under a power purchase agreement whose initial term expired at the end of 2006, but remained in effect unless terminated by either party upon one month prior notice. The Galena 2 project sells its electrical output to Nevada Power Company under a long-term power purchase agreement which expires in 2027. Except for Steamboat Hills, which utilizes a single flash system, all of the projects in the Steamboat complex utilize a binary system.
Steamboat 1/1A, Steamboat 2/3 and the Burdette projects were refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Steamboat 1/1A, Steamboat 2/3 and Burdette projects (and any and all proceeds arising therefrom). Each of our project subsidiaries, that is the direct owners of each particular project, has fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of the collateralization of the OFC Senior Secured Notes.
The Steamboat Hills and Galena 2 projects were refinanced with the proceeds from the OPC Tax Monetization transaction and we expect to refinance Galena 3 project with the proceeds from the second closing under this transaction. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the OPC Tax Monetization transaction.
We have experienced protracted failures of two of the Steamboat 2/3 project’s turbines, which were not manufactured by us. We have implemented a temporary fix and are in the process of replacing the faulty equipment with turbines designed and manufactured by us.
The Mammoth Complex
The Mammoth complex is located in Mammoth Lakes, California. The Mammoth complex is comprised of three plants, which commenced commercial operations between 1985 and1990. The Mammoth complex utilizes a binary system and has a generating capacity of 29 MW, including 4 MW that we added during the course of 2006. Our project subsidiary, OrMammoth, Inc., owns a 50% partnership interest in Mammoth-Pacific, L.P., which owns 100% of the Mammoth complex. The other 50% partnership interest is owned by an unrelated third party. The Mammoth complex sells its
electrical output to Southern California Edison under three separate power purchase agreements, one of which expires in 2014 and the other two in 2020. Our 50% ownership interest in the Mammoth complex was acquired in December 2003 using internally generated cash and project finance debt from Beal Bank, and was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by a pledge of our 50% ownership interest in Mammoth-Pacific, L.P. Our project subsidiary, OrMammoth Inc., has jointly and severally with certain of our other subsidiaries fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for further description of collateralization of the OFC Senior Secured Notes.
The Brady Complex
The Brady complex, located in Churchill County, Nevada, consists of the Brady project and the Desert Peak 2 project.
The Brady Project. The Brady project, utilizes flash and binary systems. It originally had a generating capacity of approximately 19 MW. Following the shutdown of the Desert Peak 1 plant, the Brady project has a generating capacity of 12 MW, and sells its electrical output to Sierra Pacific Power Company under a long-term power purchase agreement that will expire in 2022. We are examining several alternatives to restore the Brady project’s generating capacity to 19 MW. We originally planned to complete the restoration by the end of 2007, but our current plan is to restore the generating capacity during 2008. We can give no assurance, however, that our effort to restore the generating capacity will be successful.
The Brady project was refinanced with the proceeds from the issuance by Ormat Funding of its Senior Secured Notes on February 13, 2004. The OFC Senior Secured Notes are collateralized by all of the assets of the Brady project (and any and all proceeds arising therefrom), Our project subsidiary, Brady Power Partners, the direct owner of the Brady project, has jointly and severally with certain of our other subsidiaries, fully and unconditionally guaranteed Ormat Funding’s obligations under the OFC Senior Secured Notes. See Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ for a further description of the collateralization of the OFC Senior Secured Notes.
The Desert Peak 2 Project. The Desert Peak 2 project includes a water cooled unit and an air cooled unit, utilizing our OEC units. The Desert Peak 2 project has a generating capacity of 11 MW. The project commenced commercial operation in the first quarter of 2007. The Desert Peak 2 project sells its electrical output and transfers its renewable energy and environmental credits to Nevada Power Company under a power purchase agreement that has a 20-year term ending on December 31, 2027.
The construction of the Desert Peak 2 project was financed using internally generated cash and was refinanced with the proceeds from the OPC Tax Monetization Transaction as fully described under Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’.
The Puna Project
The Puna project is located in the Puna district, Big Island, Hawaii. The Puna plant commenced commercial operations in 1993. The Puna plant utilizes an Ormat geothermal combined cycle system, and has a generating capacity of 30 MW. The Ormat geothermal combined cycle system consists of a back pressure steam turbine, in which the lower pressure steam exhausted from the turbine is condensed in a binary system. This system assures a higher efficiency of geothermal steam, with a resulting lower steam rate, in resources producing steam above 150psi (10 bar), or even 100psi if the steam has a high non-condensable gas content. The Puna project sells its electrical output to Hawaii Electric Light Company under two power purchase agreements, which expire in 2027. Although the Puna project has significant geothermal resources, because of existing geological conditions, these
resources are difficult to manage. In the past, the Puna project required extensive levels of investment mainly to address problems with the production and injection wells related to the geothermal resources. The Puna project was acquired in June 2004 with the proceeds of parent company loans and short-term bank loans. We completed operating lease transactions in respect of the project, as described under Item 7 - ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations - Puna Project Lease Transaction’’.
We intend to increase the output of the Puna project by an additional 8 MW through the addition of OEC units. We are in the process of negotiating a new power purchase agreement for the additional generating capacity that will be available as a result of such activities.
The OREG 1 Project
The OREG 1 project is a REG project that consists of four power plants constructed on gas compressor stations along a natural gas pipeline in North and South Dakota. The project came on line during the third quarter of 2006 and has a generating capacity of 22 MW. Our project subsidiary has entered into a 25-year power purchase agreement with Basin Electric Power Cooperative (Basin Electric) pursuant to which the project sells the electrical output to Basin Electric.
Foreign Projects
Our projects in operation outside of the United States have a generating capacity of approximately 87 MW. We also have projects under construction in New Zealand and Kenya.
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. The concession expires in 2014. During 2006 we increased the output of the Momotombo project by 3 MW through a work-over of the project’s existing wells, bringing the generating capacity to approximately 30 MW. The Momotombo project has a power purchase agreement with Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), two corporations which own the power distribution rights in Nicaragua. Our project subsidiary, which operates the Momotombo project, has an outstanding loan from Bank Hapoalim B.M.
The Olkaria III Project - Phase I (Kenya)
The Olkaria III project is located in Naivasha, Kenya. The Olkaria III project is comprised of one plant, which commenced commercial operation in August 2000, and a geothermal field. The plant currently has a generating capacity of approximately 13 MW (Phase I). We are working on the construction of Phase II of this project which we expect, upon completion, will increase the generating capacity of the Olkaria III project to approximately 48 MW. A description of Phase II of this project is set forth below in ‘‘Projects under Development.’’ Phase I of the Olkaria III project utilizes a binary system. In November 1998, following an international tender, our project subsidiary entered into a power purchase agreement with the Kenya Power and Lighting Co. Ltd. (KPLC), the Kenyan parastatal electricity transmission and distribution company, which was recently amended and restated in January 2007. The power purchase agreement for the project will expire 20 years from the completion of Olkaria III Phase II, which is expected to be completed by the end of 2008 (subject to possible delays resulting from the current situation in Kenya as described elsewhere in this report).. Our project subsidiary leases the site on which the geothermal resources and the plant facilities are located from the Kenyan government, pursuant to an agreement which will expire in 2040. The Kenyan government granted our project subsidiary a license giving it exclusive rights of use and possession of the relevant geothermal resources for an initial period of 30 years, expiring in 2029, which initial period may be extended by us for two additional five-year terms. The Kenyan Minister of
Energy has the right to terminate or revoke the license in the event our project subsidiary ceases work in or under the license area during a period of six months, or has failed to comply with the terms of the license or the provisions of the law relating to geothermal resources. Our project subsidiary is obligated to pay the Kenyan government monthly fees and royalties based on the amount of power supplied to KPLC.
The Zunil Project (Guatemala)
The Zunil project is located in Zunil, Guatemala. The Zunil project is comprised of one plant which commenced commercial operations in 1999. The plant utilizes a binary system consisting of Ormat Energy Converters and has a generating capacity of 24 MW. The project is owned by Orzunil I de Electricidad, Limitada, which owns 100% of the Zunil project. Another of our subsidiaries provides operation and maintenance services to the project. The Zunil project sells its generating capacity to Instituto Nacional de Electrification pursuant to a power supply agreement, which expires in 2019. 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, 2007, $13.8 million. The loans are due and payable in quarterly installments through November 2011.
The Amatitlan Project (Guatemala)
Our project subsidiary has completed the construction and owns a geothermal power plant in Amatitlan, Guatemala on a ‘‘build, own and operate’’ or ‘‘BOO’’ basis. The project is comprised of one power plant, with a generating capacity of 20 MW, and rights to various geothermal production and reinjection wells. The Amatitlan plant uses our Ormat Energy Converters. During 2007, we commenced commercial operation of the project, which currently generates approximately 17 MW.
The term of the power purchase agreement expires in 2028. At any time prior to the third quarter of 2009, subject to the result of a reservoir and economic evaluation, our project subsidiary may continue further developments to increase the power generating capacity of the Amatitlan Geothermal Field by up to 30 MW through the drilling of additional wells. We currently sell approximately 10 MW to Instituto Nacional de Electrification according to the rate under the power purchase agreement and approximately 4 MW to a local purchaser at the same rate. The remaining 3 MW is sold on the spot market at prevailing market rates.
Projects under Construction
We are in varying stages of construction or enhancement of projects, both domestic and foreign. Based on our current construction schedule, we expect to add new generating capacity of approximately 144 MW in the United States and approximately 45 MW throughout the rest of the world by the end of 2009 or early 2010. The following is a description of the projects currently undergoing construction:
The Heber South Project (U.S.)
We completed the construction of a 10 MW power plant, located in what is known as the Heber Known Geothermal Resource Area or Heber KGRA and it is now in the commissioning phase. The construction activity included the drilling of production and injection wells and the construction of an OEC unit. Commercial operation is expected in the first quarter of 2008. The power purchase agreement for this addition to the Heber complex is still under negotiation with Southern California Power Public Authority and Southern California Edison.
The North Brawley Project (U.S.)
We are constructing a 50 MW power plant located in the Brawley known geothermal resource area in Imperial County, California. Drilling started in February 2007; construction work is at an
advanced stage; and the key power plant equipment has arrived at the site. In June 2007, we signed a 20-year power purchase agreement with Southern California Edison for the sale of 50 MW of energy to be produced from the project. The North Brawley project is projected to come on line at the end of 2008.
The Olkaria III Project - Phase II (Kenya)
As previously noted, our project subsidiary in Kenya has been working towards the construction of Phase II of the Olkaria III project. As of the date of this report, we have completed the drilling of the project’s wells and the majority of the power plant equipment is on site. We expect to complete construction by the end of 2008. However, the current political instability in Kenya may adversely affect this project, including by delaying its planned construction completion date. On January 19, 2007, we entered into an Amended and Restated Power Purchase Agreement and a Project Security Agreement with Kenya Power and Lighting Co. (KPLC), the Kenyan parastatal electricity transmission and distribution company, with respect to Phase II of the Olkaria III project. These agreements were executed after the receipt of appropriate regulatory approvals from the Kenyan authorities. The construction of the second phase of the project is expected, upon completion, to add approximately 35 MW to the existing facility, bringing the project’s total capacity to approximately 48 MW. Following completion of Phase II, total anticipated annual revenues from the project will be approximately $32 million.
Under the Project Security Agreement, KPLC provided a letter of credit in an amount equal to the value of four months of anticipated revenues from the project under the Amended and Restated Power Purchase Agreement (currently valued at approximately $8 million).
GDL project (New Zealand)
We are constructing a 10 MW power plant, located in the Kawerau, New Zealand. We have a 49% ownership interest in the project and have an option to acquire the remaining 51% before the completion of construction. The project expects to sell the electricity produced to Bay of Plenty Electricity of New Zealand under an existing 7-year power purchase agreement extendable an addition 5 years by mutual agreement Completion of this project is expected in late 2008 or early 2009.
The OREG II Projects (U.S.)
We have entered into 4 power purchase agreements with Basin Electric Power Cooperative (Basin Electric) regarding four new REG Power Plants, with a total generating capacity of 22 MW, along the Northern Border Pipeline. Under these agreements, we will sell electricity that will be produced by four new Ormat REG facilities that will have a net capacity of 5.5 MW each. These facilities will convert the recovered waste heat from the exhaust of existing gas turbines at compressor sites located on the Northern Border natural gas pipeline into clean energy. Two plants are expected to be commissioned at the end of 2008 or early 2009, and the other two, late in 2009. We have secured the rights to the waste heat for all four new facilities.
The Puna Project (U.S.)
We are currently pursuing enhancement activity in the Puna project. We plan to add 8 MW through the construction of OEC units in 2009. We are in discussions with Hawaii Electric Light Company for the sale of additional electrical power from the Puna project.
The Peetz Project (U.S.)
We are currently manufacturing the equipment required for use in the Peetz REG plant, which is expected to have a generating capacity of 4 MW. Our project subsidiary has entered into a 20-year power purchase agreement with Highline Electric Association, a consumer-owned cooperative serving load in Colorado and Nebraska, pursuant to which the project will sell its electrical output to Highline
Electric Association. The power plant will be constructed on a gas compressor station along a natural gas compression station near Denver, Colorado. The facility will convert the recovered waste heat from the exhaust of existing gas turbines into clean energy, and is expected to be commissioned in mid-2009.
The East Brawley Project (U.S.)
We plan to construct and have begun manufacturing equipment for an additional 50 MW power plant, in the Brawley known geothermal resource area in Imperial County, California, adjacent to the North Brawley project. Completion of the project is projected for the end of 2009.
Projects under Development and Future Projects
We also have projects under development in the United States, and Indonesia. We expect to continue to explore these and other opportunities for expansion so long as they continue to meet our business objectives and investment criteria.
The Carson Lake Project (U.S.)
We are currently developing the Carson Lake project, located in Churchill County, Nevada, and have commenced exploration activities. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed in 2010. A portion of the leases for this project have been obtained through an agreement with the U.S. Department of the Navy and the remainder are leases on federal land obtained from the Bureau of Land Management. We are negotiating an agreement with a third party which may become a joint venture partner in this project.
The Buffalo Valley Project (U.S.)
We are conducting exploration activities as part of the development of the Buffalo Valley project on Bureau of Land Management leases located in Lander County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed by the end of 2009 or in the first half of 2010.
The Grass Valley Project (U.S.)
We are currently developing the Grass Valley project on Bureau of Land Management leases located in Lander County, Nevada. The project will deliver between 18 MW to 30 MW of power generation under a 20-year power purchase agreement with Nevada Power Company. We expect the construction to be completed in late 2010.
GRE project (U.S.)
We are developing the 5.5 MW recovered energy generation GRE project, which will be located along the Northern Boarder pipeline in Martin County, Minnesota. We are currently negotiating a power purchase agreement with Great River Energy.
The Sarulla Project (Indonesia)
We are a member of a consortium, which is in the process of developing a geothermal power project in Indonesia of approximately 340 MW. We currently own 25% of the Indonesian special purpose company that will operate the project, but we expect to reduce our ownership interest to 12.75%.
The project, located in Tapanuli Utara, North Sumatra, represents the largest single-contract geothermal power project to date, and reflects the large scale, high productivity and potential of Indonesian geothermal resources. The project will be owned and operated by the consortium members
under the framework of the Joint Operating Contract with PT Pertamina Geothermal Energy PGE, and is to be constructed in three phases over the next five years, with each phase utilizing an Ormat designed and supplied power generation units of 110 to 120 MW. The first unit is scheduled to commence operations within 30 months of the close of financing, which is expected by the end of 2008. The remaining two units are scheduled to commence operation in stages within 18 months after the first unit’s scheduled commissioning. The total project cost is expected to be approximately $800 million. It is expected that the Japan Bank of International Corporation (JBIC) will provide the majority of the project financing based on the Umbrella Note of Mutual Understanding signed between the Ministry of Finance of Indonesia and JBIC. Power delivered by the Sarulla project will serve the base load of PLN’s North Sumatra - Aceh grid systems, and annual electricity sales revenue from the project is anticipated to be approximately $115 million when full capacity is attained. The value of our scope of supply for the project is expected to be over $250 million. The consortium will invest an amount of approximately $15 million in pre-development activity before the closing of financing.
Exploration Activity
In addition to the geothermal projects under construction and development, we have various leases for geothermal resources, in which we have started exploration activity. These geothermal resources include the following:
• Grass Valley - Nevada;
• Jersey Valley - Nevada;
• Magic Hot Springs - Idaho;
• Fireball Ridge - Nevada;
• Gabbs Valley - Nevada
• Rock Hills - Nevada;
• McGinness Hills - Nevada;
• Dead Horse - Nevada; and
• Smith Creek - Nevada.
As described under ‘‘How We Explore and Evaluate Geothermal Resources’’ section on page 20, we carry out exploration activity first to validate and then to quantify the size of the potential geothermal resources. The foregoing development inventories are in various stages of evaluation, permitting and/or cancelation for lack of viable geothermal resources. The North Brawley project is our first project that has advanced from exploration activities to project construction phase. We began our exploration activity in 2006 and have increased these efforts in 2007. In 2008, we plan to carryout parallel exploratory drilling, which we believe will enable us to increase the rate of evaluation and development of new commercially viable projects. We do not expect, however, that our exploration activities will lead to a commercially viable project in each case.
Development Inventory
In addition to the geothermal projects under construction, development or exploration, we have various geothermal leases for future development in the United States and other development rights outside of the United States. These geothermal leases and rights cover approximately 100,000 acres, approximately 50,000 acres of which were secured during 2007. These include the following:
• Oregon - one site;
• California - four sites;
• Nevada - seven sites;
• Hawaii - one site;
• Idaho - one site (and two sites pending);
• Texas - several leases; and
• Outside of the United States - two sites in China and Nicaragua.
Operations of our Products Segment
Power Units for Geothermal Power Plants. We design, manufacture and sell power units for geothermal electricity generation, which we refer to as Ormat Energy Converters or OECs. Our customers include contractors and geothermal plant owners and operators.
The consideration for the power units is usually paid in installments, in accordance with milestones set in the supply agreement. Sometimes we agree to provide the purchaser with spare parts (or alternatively, with a non-exclusive license to manufacture such parts). We provide the purchaser with at least a 12-month warranty for such products. We usually also provide the purchaser (often, upon receipt of advances made by the purchaser) with a guarantee, which expires in part upon delivery of the equipment to the site and fully expires at the termination of the warranty period. The guarantees are at times covered by letters of credit. We have not received any claims under the performance guarantees to date.
Power Units for Recovered Energy-Based Power Generation. We design, manufacture and sell power units used to generate electricity from recovered energy or so-called ‘‘waste heat’’ that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes, such as cement manufacturing, and is not otherwise used for any purpose. Our existing and target customers include interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators, and other companies engaged in other energy-intensive industrial processes. We view recovered energy generation as a significant market opportunity for us, and plan to utilize two different business models in connection with such business opportunity.
The first business model, which is similar to the model utilized in our geothermal power generation business, consists of the development, construction, ownership and operation of recovered energy-based generation power plants. In this case, we will enter into agreements to purchase industrial waste heat, and enter into long-term power purchase agreements with off-takers to sell the electricity generated by the recovered energy generation unit that utilizes such industrial waste heat. We expect that the power purchasers in such cases will be investor-owned electric utilities or local electrical cooperatives. In 2007, we signed a supply contract with Italcementi Group of Bergamo, Italy for the supply of one OEC for a new REG power plant in West Virginia.
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, if structured properly, may be eligible for favorable tax treatment, such as the seven year modified accelerated cost recovery under relevant U.S. federal tax rules.
Remote Power Units and other Generators. We design, manufacture and sell fossil fuel powered turbo-generators with a capacity ranging between 200 watts and 5,000 watts, which operate unattended in extreme climate conditions, whether hot or cold. The remote power units supply energy for remote and unmanned installations and along communications lines and cathodic protection along gas and oil pipelines. Our customers include contractors installing gas pipelines in remote areas. In addition, we manufacture and sell generators for various other uses, including heavy duty direct current generators. Our remote power units were supplied to the Sakhalin pipeline in Russia. The terms of sale of the turbo-generators are similar to those for the power units produced for power plants.
Engineering, Procurement and Construction (EPC) of Power Plants. We engineer, procure and construct, as an EPC contractor, geothermal and recovered energy power plants on a turnkey basis, using power units we design and manufacture. Our customers are geothermal power plant owners as well as the same customers described above that we target for the sale of our power units for recovered energy-based power generation. Unlike many other companies that provide EPC services, we have an advantage in that we are using our own manufactured equipment and thus have better control over the timing and delivery of required equipment and its costs. The consideration for such services is usually paid in installments, in accordance with milestones set in the EPC contract and related documents. We usually provide performance guarantees or letters of credit securing our obligations under the contract. Upon delivery of the plant to its owner, such guarantees are replaced with a warranty guarantee, usually for a period ranging from 12 months to 36 months. The EPC contract usually places a cap on our liabilities for failure to meet our obligations thereunder. For example, we are currently acting as the EPC contractor for the Alliance REG plants in Canada.
We also design and construct the recovered energy generation units on a turnkey basis, and may provide a long-term agreement to supply non-routine maintenance for such units. Our customers are interstate natural gas pipeline owners and operators, gas processing plant owners and operators, cement plant owners and operators and companies engaged in the process industry. For example, we entered into supply and construction contracts with Alliance pipeline in Western Canada for an Ormat Recovered Energy Generation power plant.
In connection with the sale of our power units for geothermal power plants, power units for recovered energy-based power generation and remote power units and other generators, we, from time to time, enter into sales agreements for the marketing and sale of such products pursuant to which we are obligated to pay commissions to such representatives upon the sale of our products in the relevant territory covered by such agreements by such representatives or, in some cases, by other representatives in such territory.
Our manufacturing operations and products are certified ISO 9001, ISO 14001, ASME and TÜV, and we are an approved supplier to many electric utilities around the world.
Backlog
The Company and its wholly owned subsidiaries have a products backlog of $64.2 million as of February 26, 2008, which includes revenues for the period between January 1, 2008 and February 26, 2008, compared to $89.5 million as of February 28, 2007. The following is a breakdown of the Products Segment backlog:
* In addition, once an EPC contract with Nevada Geothermal Power will be signed, it will increase our backlog by approximately $55 million - See ‘‘Recent Developments’’ above.
We expect that our revenues from electricity for the 2008 fiscal year will be approximately $245 million from our wholly owned projects and approximately $9 million from our subsidiary 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.
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 75 United States patents (and about 14 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 also the overall effectiveness of the plant’s systems from the ‘‘fuel’’ (i.e., geothermal fluid, waste heat, biomass or solar) to generated electricity. The duration of such patents ranges from one year to 14 years. No single patent on its own is material to our business.
The products-related patents cover components such as turbines, heat exchanges, seals and controls. The system patents cover subjects such as disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources and use of two-phase fluids. A number of patents cover the combined cycle geothermal power plants, in which the steam first produces power in a backpressure steam turbine and is subsequently condensed in a vaporizer of a binary plant, which produces additional power.
We are also involved in developing new technology (Enhanced Geothermal Systems or EGS) 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. This project named DEEP is being developed at the site of our Desert Peak 2 plant in Nevada.
Competition
In our Electricity Segment, we face competition from geothermal power plant owners and developers as well as other renewable energy providers.
In our Products Segment, we face competition from power plant equipment manufacturers and suppliers.
Electricity Segment
Our main competitors among geothermal power plant owners and developers in the United States are CalEnergy, Calpine, Terra-Gen Power LLC (which acquired all of the owned geothermal assets of Caithness), ENEL SpA and other smaller-sized developers such as Iceland America Energy Inc., U.S. Geothermal Inc., Nevada Geothermal Power Corp., T G Power LLC and Raser Technologies Inc. Some of these companies are also active outside of the United States. Other competitors outside of the United States, aside from these companies, include affiliates of Chevron Corporation and Reykjavik Energy. We may also face competition from national electric utilities or state-owned oil companies.
Our competitors among renewable energy providers include companies engaged in the power generation business from renewable energy sources other than geothermal energy, such as wind power, solar power and hydro-electric power. In the last few years, competition from the wind and solar power generation industries has increased significantly. However, current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements. We cannot ascertain at this time whether the competition from wind and solar energy will have an impact on electricity prices for new renewable projects.
In the recovered energy generation business, our potential competitors are Siemens AG of Germany, as well as other manufacturers of conventional steam turbines; although we believe that our recovered energy generation system has technological and economical advantages over the Siemens/Kalina technology and, under certain conditions, conventional steam technology.
Products Segment
Our main competitors among power plant equipment suppliers are Mitsubishi, Fujifilm and Toshiba of Japan, GE/Nuovo Pignone, Ansaldo Energia and Turboden s.r.l. of Italy, Siemens AG of Germany, Alstom S.A. of France and OAO Kaluga Energo of Russia.
In the recovered energy generation business, our potential competitors are Siemens AG of Germany, as well as other manufacturers of conventional steam turbines; although we believe that our
recovered energy generation system has technological and economical advantages over the Siemens/Kalina technology and, under certain conditions, conventional steam technology.
In the remote power unit business, we face competition from Global Thermoelectric, as well as from manufacturers of diesel generator sets.
None of our competitors competes with us both in the sale of electricity and in the products business.
Customers
Most of our revenues from the sale of electricity in the year ended December 31, 2007 were derived from fully-contracted energy and/or capacity payments under long-term power purchase agreements with governmental and private utility companies. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company accounted for 31.9%, 14.6% and 9.7% of revenues, respectively, for the year ended December 31, 2007. Based on publicly available information, as of December 31, 2007, the issuer ratings of Southern California Edison, Sierra Pacific Power Company, Hawaii Electric Light Company, Nevada Power Company and Southern California Power Public Authority were as set forth below:
Issuer
Standard & Poor’s Ratings Services
Moody’s Investors Service Inc.
Southern California Edison
BBB+ (stable outlook)
A3 (stable outlook)
Sierra Pacific Power Company
BB− (stable outlook)
Ba3 (stable outlook)
Hawaii Electric Light Company
BBB+ (negative outlook)
N/A
Nevada Power Company
BB− (positive outlook)
Ba3 (stable outlook)
Southern California Power Public Authority
A+ (stable outlook)
A1 (stable outlook)
The credit ratings of any power purchaser may decrease from time to time. There is no publicly available information with respect to the credit rating or stability of the power purchasers under the power purchase agreements for our foreign power projects.
Our revenues from the products business were derived from contractors or owners or operators of power plants, process companies and pipelines.
Raw Materials, Suppliers and Subcontractors
In connection with our manufacturing activities, we use raw materials such as steel and aluminum. We do not rely on any one supplier for the raw materials used in our manufacturing activities, as all of such raw materials are readily available from various suppliers.
Since 2005 we have increased the volume of work ordered from subcontractors for some of the manufacturing for our products components and for construction activities of our power plants, which allowed us to expand our construction and development capacity on an as-needed basis. We are not dependent on any one subcontractor and expect to be able to replace any subcontractor, or assume such manufacturing and construction activities of our projects ourselves without adverse effect to our operations.
Employees
As of December 31, 2007, we employed 899 employees, of which 339 were located in the United States, 405 were located in Israel and 155 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. Political risk insurance policies are generally issued by entities which specialize in such policies, such as the Multilateral Investment Guarantee Agency (a member of the World Bank Group), and from private sector providers, such as Zurich Re, AIG and other such companies. To date all of our political risk insurance contracts are with the Multilateral Investment Guarantee Agency and with Zurich Re. We have obtained such insurance for all of our foreign projects with the exception of the Zunil project for which we are currently negotiating insurance coverage. Such insurance policies generally cover, subject to the limitations and restrictions contained therein, 80% to 90% of our revenue loss derived from a specified governmental act, such as confiscation, expropriation, riots, and the inability to convert local currency into hard currency and, in certain cases, the breach of agreements. The level of coverage under the political risk insurance policy for our Olkaria III project in Kenya is set at $88 million.
Regulation of the Electric Utility Industry in the United States
The following is a summary overview of the electric utility industry and applicable federal and state regulations, and should not be considered a full statement of the law or all issues pertaining thereto.
PURPA
PURPA provides certain benefits described below, if a project is a ‘‘Qualifying Facility’’. A small power production facility is a Qualifying Facility if (i) the facility does not exceed 80 megawatts, (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and 75% of the total energy input of the facility is from these sources, and fossil fund input is limited to specified uses; and (iii) the facility has filed with the Federal Energy Regulatory Commission (FERC) a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status, that has been granted. The 80 megawatt size limitation, however, does not apply to a facility if (i) it produces electric energy solely by the use, as a primary energy input, of solar, wind, or waste resources; and (ii) an application for certification or a notice of self-certification of qualifying status of the facility was submitted to the FERC prior to December 21, 1994, and construction of the facility commenced prior to December 31, 1999.
PURPA exempts Qualifying Facilities from regulation under the Public Utility Holding Company Act of 2005 (PUHCA) and exempts Qualifying Facilities from most provisions of the Federal Power Act (FPA) and state laws relating to the financial, organization and rate regulation of electric utilities. In addition, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utility’s incremental cost of purchasing or producing energy (also known as ‘‘avoided cost’’).
Following passage of the Energy Policy Act of 2005, FERC issued a final rule that will require Qualifying Facilities to obtain market-based rate authority pursuant to the FPA for sales of energy or capacity (i) from facilities larger than 20 MW in size; (ii) pursuant to a contract executed after March 17, 2006 that is not a contract made pursuant to a state regulatory authority’s implementation of PURPA; or (iii) not pursuant to another provision of a state regulatory authority’s implementation of PURPA. The practical effect of this final rule is to require Qualifying Facilities that are larger than 20 MW in size that seek to engage in non-PURPA sales of power (i.e. power that is sold in a manner that is not pursuant to a pre-existing contract or state implementation of PURPA) to obtain market-based rate authority from FERC for these non-PURPA sales.
The Energy Policy Act of 2005 also allows FERC to terminate a utility’s obligation to purchase energy from Qualifying Facilities upon a finding that Qualifying Facilities have nondiscriminatory access to either (i) independently administered, auction-based day ahead and real time markets for energy and wholesale markets for long-term sales of capacity; (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales; or (iii) wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC has recently issued a rule to implement these provisions of the Energy Policy Act of 2005. This rule gives utilities the right to apply to eliminate the mandatory purchase obligation. There is a presumption that the application will be granted if the utility is a member of one of four regional transmission organizations. None of our domestic projects sells power pursuant to contracts with utilities in any of these four regional transmission organizations. The rule also creates a rebuttable presumption that a utility provides nondiscriminatory access if it has an open access transmission tariff in compliance with FERC’s pro forma open access transmission tariff. Further, the rule provides a procedure for utilities that are not members of the four named regional transmission organizations to file to obtain relief from the mandatory purchase obligation on a service territory-wide basis, and establishes procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. The rule protects a Qualifying Facility’s rights under any contract or obligation involving purchases or sales that are entered into before FERC has determined that the contracting utility is entitled to relief from the mandatory purchase obligation. The rule also protects a Qualifying Facility’s rights under any contract or obligation for the sale of energy in effect or pending approval before the appropriate state regulatory authority or non-regulated electric utility on August 8, 2005.
In addition, the Energy Policy Act of 2005 eliminated the restriction on utility ownership of a Qualifying Facility. Prior to the Energy Policy Act of 2005, electric utilities or electric utility holding companies could not own more than a 50% equity interest in a Qualifying Facility. Under the Energy Policy Act of 2005, electric utilities or holding companies may own up to 100% of the equity interest in a Qualifying Facility.
We expect that our projects in the United States will continue to meet all of the criteria required for Qualifying Facilities under PURPA. However, since the Heber Projects have power purchase agreements with Southern California Edison that require Qualifying Facility status to be maintained, maintaining Qualifying Facility status remains a key obligation. If any of the Heber Projects loses its Qualifying Facility status our operations could be adversely affected. Loss of Qualifying Facility status would eliminate the Heber Project’s exemption from the FPA and thus, among other things, the rates charged by the Heber Projects in the power purchase agreements with Southern California Edison and SCPPA would become subject to FERC regulation. Further, it is possible that the utilities that purchase power from the projects could successfully obtain an elimination of the mandatory-purchase
obligation in their service territories. If this occurs, the Project’s existing power purchase agreements will not be affected, but the utilities will not be obligated under PURPA to renew these power purchase agreements or execute new power purchase agreements upon the existing power purchase agreements’ expiration.
PUHCA
The Public Utility Act of 1935, (‘‘PUHCA’’) was repealed, effective February 8, 2006, pursuant to the Energy Policy Act of 2005. Although PUHCA was repealed, the Energy Policy Act of 2005 created a new Public Utility Holding Company Act of 2005 (PUHCA 2005). Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. If a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities that make only wholesale sales of electricity, are not subject to state commissions’ rate, financial and organizational regulations and, therefore, in all likelihood would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state.
FPA
Pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are exempt from most provisions of the FPA. If any of the projects were to lose its Qualifying Facility status, such project could also become subject to the full scope of the FPA and applicable state regulations. The application of the FPA and other applicable state regulations to the projects could require our projects to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility. Even if a project does not lose Qualifying Facility status, if a power purchase agreement with a project is terminated or otherwise expires, the project will become subject to rate regulation under the Federal Power Act.
If a project in the United States was to become subject to FERC’s ratemaking jurisdiction under the FPA as a result of loss of Qualifying Facility status and the power purchase agreement remains in effect, the FERC may determine that the rates currently set forth in the power purchase agreement are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that the project refund a portion of amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from the project, either of which would have an adverse effect on our revenues.
Moreover, the loss of the Qualifying Facility status of any of our projects selling energy to Southern California Edison could also permit Southern California Edison, pursuant to the terms of its power purchase agreement, to cease taking and paying for electricity from the relevant project and to seek refunds for past amounts paid. In addition, the loss of any such status would result in the occurrence of an event of default under the indenture for the OFC Senior Secured Notes and the OrCal Senior Secured Notes and hence would give the indenture trustee the right to exercise remedies pursuant to the indenture and the other financing documents.
State Regulation
Our projects in California and Nevada, by virtue of being Qualifying Facilities that make only wholesale sales of electricity, are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The projects each sell or will sell their electrical output under power purchase agreements to electric utilities (Sierra Pacific Power Company, Nevada Power Company,
Southern California Edison or Southern California Public Power Authority). All of the utilities except Southern California Public Power Authority are regulated by their respective state public utility commissions. Sierra Pacific Power Company and Nevada Power Company are regulated by the Public Utility Commission of Nevada. Southern California Edison and a small portion of Sierra Pacific Power Company in the Lake Tahoe area are regulated by the California Public Utility Commission.
Under Hawaii law, non-fossil generators are not subject to regulation as public utilities. Hawaii law provides that a geothermal power producer is to negotiate the rate for its output with the public utility purchaser. If such rate cannot be determined by mutual accord, the Hawaii Public Utility Commission will set a just and reasonable rate. If a non-fossil generator in Hawaii is a Qualifying Facility, federal law applies to such Qualifying Facility and the utility is required to purchase the energy and capacity at its avoided cost. The rates for our project in Hawaii are established under a long-term power purchase agreement with Hawaii Electric Light Company.
Foreign Regulation of the Electric Utility Industry
The following is a summary overview of certain aspects of the electric industry in the foreign countries in which we have an operating geothermal power project and should not be considered a full statement of the laws in such countries or all of the issues pertaining thereto.
Nicaragua. In 1998 two laws were approved by Nicaraguan authorities, Law No. 272-98 and Law No. 271-98, which define the structure of the new energy sector in the country. Law No. 272-98 provides for the establishment of a National Energy Commission, which we refer to as CNE, responsible for setting policies, strategies and objectives as well as approving indicative plans for the energy sector. Law No. 271-98 formally assigned regulatory, supervisory, inspection and oversight functions to the Nicaraguan Institute of Energy, which we refer to as INE.
In 2002, the National Congress enacted Law No. 443 to regulate the granting of exploration and exploitation concessions for geothermal fields. The INE adopted this law.
In 2007, Nicaragua passed a law amending Law No. 290, which governs the organization of the executive branch. Among other matters, the new law established a new ministry of energy and mining, which has assumed all of the functions and responsibilities of the National Energy Commission (CNE). The new ministry of energy and mining is responsible for administrating Law No. 443 described above, and is also responsible for granting concessions and permits relating to the exploration or exploitation of any energy source, as well as concessions and licensing for generation, transmission and distribution of energy.
The Nicaraguan energy sector has been restructured and partially privatized. Following such restructuring and privatization, the government has retained title and control of the transmission assets and has created the Empresa Estatal de Transmision (ENTRESA), which is in charge of the operation of the transmission system in the country and of the new wholesale market. As part of the recent restructuring of the energy sector, most of the distribution facilities previously owned by the Nicaraguan Electricity Company, the government-owned vertically-integrated monopoly, were transferred to two companies, Empresa Distribuidora de Electricidad del Norte (DISNORTE) and Empresa Distribuidora de Electricidad del Sur (DISSUR), which in turn were privatized and acquired by an affiliate of Union Fenosa, a large Spanish utility. Following such privatization, the power purchase agreement for our Momotombo project was assigned by the Nicaraguan Electricity Company to DISNORTE and DISSUR. A subsidiary of the Nicaraguan Electricity Company, ENTRESA, owns the transmission grid. In addition, a National Dispatch Center was created to work with ENTRESA and provide for dispatch and wholesale market administration.
Guatemala. The General Electricity Law of 1996 created a wholesale electricity market in Guatemala and established a new regulatory framework for the electricity sector. The law created a new regulatory commission, the National Electric Energy Commission (CNEE) and a new wholesale power market administrator, the Administrator of the Wholesale Market, for the regulation and administration of such sector. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising and controlling compliance with 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 exemption from corporate income tax and VAT on imports and customs duty.
Kenya. Kenya’s Electric Power Act of 1997 restructured the electricity sector in the country. Among other things, the Act provides for the licensing of electricity power producers and public electricity suppliers or distributors. Kenya Power and Lighting Co. Ltd. (KPLC) is the only licensed public electricity supplier and has a monopoly in the transmission and distribution of electricity in the country. The Act permitted Independent Power Producers (IPPs) to install power generators and sell electricity to KPLC, which is owned by various private and government entities and which currently purchases energy and capacity from two other IPPs in addition to our Olkaria III project. The Act also created the Electricity Regulation Board, as an independent regulator for the electricity sector. KPLC’s retail electricity rates are subject to approval by the Electricity Regulation Board. The Electric Power Act, 1997 has now been repealed by the Energy Act of 2006, which came into effect on July 7, 2007. One of the main changes introduced by the Energy Act was the reconstitution of the Electricity Regulatory Board as Energy Regulatory Commission (ERC) with an expanded mandate to regulate not just the electric power sector but the entire energy sector in Kenya.
Permit Status
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 that are 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.
For example, 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. Because fluids are reinjected to enhance utilization of the geothermal resource, our injection wells typically fall into UIC Class V, one of the least regulated categories.
Our operations are designed and conducted to comply with applicable permit requirements. Non-compliance with any such requirements could result in fines or other penalties. We are not aware of any non-compliance with such requirements that would be likely to result in material fines or penalties. However, the Heber 1 and 2 projects received a notice from the California Division of Oil, Gas and Geothermal Resources that the pressure levels at some of the geothermal fluid injection wells were too high.
As of the date of this annual report, all of the material permits and approvals currently required to operate our projects have been obtained and are currently valid. As of the date of this annual report, we have obtained and are in compliance with all of the material permits and approvals currently required for our projects that are under construction or enhancement. There are some permits that need to be obtained in the future. We believe we will be able to obtain those permits and approvals without material delay and without incurring additional material costs.
Environmental Laws and Regulations
Geothermal operations can produce significant quantities of brine and scale, which builds up on metal surfaces in our equipment with which the brine comes into contact. These waste materials, most of which are currently reinjected into the subsurface, can contain various concentrations of hazardous materials, including arsenic, lead, and naturally occurring radioactive materials. We also use various substances, including isopentane, and industrial lubricants, that could become potential contaminants and are generally flammable. Hazardous materials are also used and generated in connection with our equipment manufacturing operations in Israel. As a result, our projects are subject to numerous domestic and foreign federal, state and local statutory and regulatory standards relating to the use, storage, fugitive emissions and disposal of hazardous substances. The cost of any remediation activities in connection with a spill or other release of such contaminants could be significant.
Although we are not aware of any mismanagement of these materials, including any mismanagement prior to the acquisition of some of our projects, that has materially impaired any of the project sites, any disposal or release of these materials onto project sites, other than by means of permitted injection wells, could result in material cleanup requirements or other responsive obligations under applicable environmental laws. We believe that at one time there may have been a gas station located on the Mammoth project site (which we lease), but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. We believe that, given the subsequent surface disturbance and construction activity in the vicinity of the suspected location of the service station, it is likely that the former facilities and any associated underground storage tanks would have already been encountered if they still existed.
ITEM 1A.
ITEM 1A. RISK FACTORS
Because of the following factors, as well as other variables affecting our business, operating results or financial condition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.
Our financial performance depends on the successful operation of our geothermal power and recovered energy generation plants, which is subject to various operational risks.
Our financial performance depends on the successful operation of our subsidiaries’ geothermal and recovered energy generation power plants. In connection with such operations, we derived approximately 73.0% of our total revenues for the year ended December 31, 2007 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power and recovered energy generation plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:
• regular and unexpected maintenance and replacement expenditures;
• shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;
• labor disputes;
• the presence of hazardous materials on our project sites;
• catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe storms or similar occurrences affecting our projects or any of the power purchasers or other third parties providing services to our projects; and
• the aging of power plants may reduce their availability and increase the cost of their maintenance.
Any of these events could significantly increase the expenses incurred by our projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of our projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
As mentioned above, the aging of our power plants may reduce their availability and increase maintenance costs due to the need to repair or replace our equipment. For example, in 2007, we experienced protracted failures of two of the Steamboat 2/3 project’s turbines, which were not manufactured by us. We have implemented a temporary fix and are in the process of replacing the faulty equipment with turbines designed and manufactured by us. Such major maintenance activities impact both the capacity factor of the affected power plant and its operating costs.
Our exploration, development, and operation of geothermal energy resources is subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our projects.
Our business involves the exploration, development and operation of geothermal energy resources. These activities are subject to uncertainties, which vary among different geothermal reservoirs and are in some respects similar to those typically associated with oil and gas exploration, development and exploitation, such as dry holes, uncontrolled releases and pressure and temperature decline, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. Prior to our acquisition of the Steamboat Hills project, one of the wells related to the project experienced an uncontrolled release. In addition, the high temperature and high pressure in the Puna project’s geothermal energy resource requires special reservoir management and monitoring. Further, since the commencement of their operations, several of our projects have experienced geothermal resource cooling in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal projects depends on different factors directly related to the geothermal resource, such as the heat content (the relevant composition of temperature and pressure) of the geothermal reservoir, the useful life (commercially exploitable life) of the reservoir and operational factors relating to the extraction of geothermal fluids. Our geothermal energy projects may suffer an unexpected decline in the capacity of their respective geothermal wells and are exposed to a risk of geothermal reservoirs not being sufficient for sustained generation of the electrical power capacity desired over time. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power projects.
Another aspect of geothermal operations is the management and stabilization of subsurface impacts caused by fluid injection pressures of production and injection fluids to mitigate subsidence. In the case of the geothermal resource supplying the Heber 1 project and the Heber 2 project, which we refer to collectively as the ‘‘Heber projects’’, and the Gould project (a new power plant at the site of the Heber projects consisting of two Ormat Integrated Two Level Units (ITLU)), pressure drawdown in the center of the well field has caused some localized ground subsidence, while pressure in the peripheral areas has caused localized ground inflation. Inflation and subsidence, if not controlled, can adversely affect farming operations and other infrastructure at or near the land surface. Potential costs, which cannot be estimated and may be significant, of failing to stabilize site pressures in the Heber and Gould projects’ area include repair and modification of gravity-based farm irrigation systems and municipal sewer piping and possible repair or replacement of a local road bridge spanning an irrigation canal.
Additionally, geothermally active areas, such as the areas in which our projects are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our projects or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the power purchase agreement for the affected project, which in turn could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer a serious seismic disturbance, our business interruption and property damage insurance may not be adequate to cover all losses sustained as a result thereof. In addition, insurance coverage may not continue to be available in the future in amounts adequate to insure against such seismic disturbances.
Reduced levels of recovered energy required for the operation of our recovered energy generation power plants may result in decreased performance of such projects.
Our recovered energy generation power plants generate electricity from recovered energy or so-called ‘‘waste heat’’ that is generated as a residual by-product of gas turbine-driven compressor stations and a variety of industrial processes. Any interruption in the supply of the recovered energy source, such as a result of reduced gas flows in the pipelines or reduced level of operation at the compressor stations, or in the output levels of the various industrial processes, may cause an unexpected decline in the capacity and performance of our recovered energy power plants.
Our business development activities may not be successful and our projects under construction may not commence operation as scheduled.
We are currently in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and power purchase agreements, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of construction. We may be unsuccessful in accomplishing any of these matters or doing so on a timely basis. Although we may attempt to minimize the financial risks attributable to the development of a project by securing a favorable power purchase agreement, obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.
Currently, we have power plants under development or construction in the United States and Kenya, 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, 2007, we had approximately $380.3 million of total consolidated indebtedness (including indebtedness to our parent company in the amount of $57.8 million), of which approximately $321.5 million represented non-recourse debt and limited recourse debt held by our subsidiaries. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms.
Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic and capital market conditions, credit availability from banks, investor confidence, the continued success of current projects, the credit quality of the projects being financed, the political situation in the country where the project is located and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing for our projects on a substantially non-recourse or limited recourse basis, we may have to finance them using recourse capital such as direct equity investments, parent company loans or the incurrence of additional debt by us.
Also, in the absence of favorable financing options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects.
Our foreign projects expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions and policies of foreign governments, any of which risks may delay or reduce our ability to profit from such projects.
We have substantial operations outside of the United States that generated revenues in the amount of $92.4 million for the year ended December 31, 2007, which represented 31.2% of our total revenues for such twelve-month period. Our foreign operations are subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in the United States, which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:
• changes in government policies or personnel;
• changes in general economic conditions;
• restrictions on currency transfer or convertibility;
• changes in labor relations;
• political instability and civil unrest;
• changes in the local electricity market;
• breach or repudiation of important contractual undertakings by governmental entities; and
• expropriation and confiscation of assets and facilities.
In particular, in Guatemala the electricity sector was partially privatized, and it is currently unclear whether further privatization will occur in the future. Such developments may affect our Amatitlan and Zunil projects if, for example, they result in changes to the prevailing tariff regime or in the identity and creditworthiness of our power purchasers. In Nicaragua, subsidiaries of Union Fenosa, which are the off-takers of our Momotombo project, have been experiencing difficulties adjusting the tariffs charged to their customers, thus affecting their ability to pay for electricity they purchase from power generators. This may adversely affect our Momotombo project. In addition, recent sentiment in the country suggests increased opposition to the presence of foreign investors generally, including in the electricity sector. In Kenya, the government is continuing to make an effort to deliver on campaign promises to reduce the price of electricity and is applying pressure on independent power producers to lower their tariffs. In addition, Kenya’s government is considering a further restructuring and privatization of the electricity industry and may divide Kenya Power and Lighting Co. Ltd., the
power purchaser for our Olkaria III project, into separate entities and then privatize one or more of such resulting entities. Any break-up and potential privatization of Kenya Power and Lighting Co. Ltd. may adversely affect our Olkaria III project. The recent political instability in Kenya may also adversely affect our Olkaria III project, including by causing delays in our expected construction completion schedule or by adversely affecting the ability to refinance the project. Although we generally obtain political risk insurance in connection with our foreign projects, such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to our political risk insurance policies, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the project lenders as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances.
Our foreign projects and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects and operations.
Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign projects and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign projects and operations.
A significant portion of our net revenue is attributed to payments made by power purchasers under power purchase agreements. The failure of any such power purchaser to perform its obligations under the relevant power purchase agreement or the loss of a power purchase agreement due to a default would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
A significant portion of our net revenue is attributed to revenues derived from power purchasers under the relevant power purchase agreements. Southern California Edison, Hawaii Electric Light Company and Sierra Pacific Power Company have accounted for 31.9%, 14.6% and 9.7%, respectively, of our revenues for the year ended December 31, 2007. Neither we nor any of our affiliates make any representations as to the financial condition or creditworthiness of any purchaser under a power purchase agreement, and nothing in this annual report should be construed as such a representation.
There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their power purchase agreements. For example, as a result of the energy crisis in California, Southern California Edison withheld payments it owed under various of its power purchase agreements with a number of power generators (such as the Ormesa, Heber, and Mammoth projects) payable for certain energy delivered between November 2000 and March 2001 under such power purchase agreements until March 2002. If any of the power purchasers fails to meet its payment obligations under its power purchase agreements, it could materially and adversely affect our business, financial condition, future results and cash flow.
Seasonal variations may cause significant fluctuations in our cash flows, which may cause the market price of our common stock to fall in certain periods.
Our results of operations are subject to seasonal variations. This is primarily because some of our domestic projects receive higher capacity payments under the relevant power purchase agreements during the summer months, and due to the generally higher short run avoided costs in effect during the summer months. Some of our other projects may experience reduced generation during warm periods due to the lower heat differential between the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, future results and cash flow. If our operating results fall below the public’s or analysts’ expectations in some future period or periods, the market price of our common stock will likely fall in such period or periods.
Pursuant to the terms of some of our power purchase agreements with investor-owned electric utilities in states that have renewable portfolio standards, the failure to supply the contracted capacity and energy thereunder may result in the imposition of penalties.
Under the Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake, Buffalo Valley, Grass Valley and North Brawley power purchase agreements, we may be required to make payments to the relevant power purchaser in an amount equal to such purchaser’s replacement costs for renewable energy relating to any shortfall amount of renewable energy that we do not provide as required under the power purchase agreement and which such power purchaser is forced to obtain from an alternate source. Three of the seven power purchase agreements were in commercial operation in 2007 and to date the shortfall amount has not been material. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant power purchase agreement. We may be subject to certain penalties, and we may also be required to pay liquidated damages if certain minimum performance requirements are not met under certain of our power purchase agreements, all of which could materially and adversely affect our business, financial condition, future results and cash flow. With respect to certain of our power purchase agreements, we may also be required to pay liquidated damages to our power purchaser if the relevant project does not maintain availability of at least 85% during applicable peak periods. The maximum aggregate amount of such liquidated damages for the Steamboat 2 and Steamboat 3 power purchase agreements would be approximately $1.5 million for each project.
The short run avoided costs for our power purchasers may decline, which would reduce our project revenues and could materially and adversely affect our business, financial condition, future results and cash flow.
Under the power purchase agreements for our projects in California, the price that Southern California Edison pays for energy is based upon its short run avoided costs, which are the incremental costs that it would have incurred had it generated the relevant electrical energy itself or purchased such energy from others. Under settlement agreements between Southern California Edison and a number of power generators in California that are Qualifying Facilities, including our subsidiaries, the energy price component payable by Southern California Edison has been fixed through April 2007 and, recently, has been fixed again through April 2012, and thereafter will be based on Southern California Edison’s short run avoided costs, as determined by the California Public Utilities Commission. These short run avoided costs may vary substantially on a monthly basis, and are expected to be based primarily on natural gas prices for gas delivered to California as well as other factors. The levels of short run avoided cost prices paid by Southern California Edison may decline following the expiration date of the settlement agreements, which in turn would reduce our project revenues derived from Southern California Edison under our power purchase agreements and could materially and adversely affect our business, financial condition, future results and cash flow.
If any of our domestic projects loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.
Most of our domestic projects are Qualifying Facilities pursuant to the Public Utility Regulatory Policies Act of 1978, as amended, which we refer to as PURPA, which largely exempts the projects from the Federal Power Act, which we refer to as FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.
If any of our domestic projects were to lose its Qualifying Facility status, such project could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.
In addition, pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of public utilities in interstate commerce. These rates may be
based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are largely exempt from the FPA. If a domestic project were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such project pursuant to its power purchase agreements would be subject to the review and approval of the FERC. The FERC, upon such review, may determine that the rates currently set forth in such power purchase agreements are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that some or all of our domestic projects refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic projects, either of which would have an adverse effect on our revenues. Even if a project does not lose its Qualifying Facility status, pursuant to a final rule issued by FERC for projects above 20 MW, if a project’s power purchase agreement is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that project will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreements, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.
Pursuant to the Energy Policy Act of 2005, the FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing power purchase agreements between a Qualifying Facility and a utility are not affected. The FERC has issued regulations under which it would allow a utility to apply to eliminate its mandatory purchase obligation from Qualifying Facilities in certain regions of the country. The regions do not currently include areas in which our domestic projects operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. In rulemaking leading to the issuance of the regulations, the FERC expressly noted that the California Independent System Operator (CAISO) has satisfied one but not all of the criteria for relief from the mandatory purchase obligation. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the project in the region under Federal law upon termination of the existing power purchase agreement or with respect to new projects, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our financial performance is significantly dependent on the successful operation of our 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 domestic and foreign federal, state and local energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. Our power purchasers or we may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
For example, the federal government currently encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim in our consolidated federal tax returns either an investment tax credit for approximately 10% of the cost of each new geothermal power plant or ‘‘production tax credits’’, which in 2007 was 2.0 cents per kWh and is adjusted annually for inflation, on the first ten years of electricity output (Production tax credits can only be claimed on new plants put into service between October 23, 2004 and December 31, 2008). We are also permitted to deduct most of the cost of the power plant as ‘‘depreciation’’ over five years on an accelerated basis. The fact that the deductions are accelerated means that more of the cost is deducted in the first few years than during the remainder of the depreciation period. In addition, we have the ability to transfer the value of these tax incentives when we are not in a position to use them directly. For instance, energy credits can be transferred through lease financing, and production tax credits may be transferred by bringing in another company who can use them as a partner in the project.
President Bush has made it a central theme of his second term to simplify the U.S. tax code. Among the options that may be under consideration are replacing or supplementing the corporate income tax with a value-added-tax, stripping away many tax subsidies, and eliminating taxes on interest, dividends and other returns to capital. Significant tax reform has the potential to have a material effect on our business, financial condition, future results and cash flow. It could reduce or eliminate the value that geothermal companies receive from the current tax subsidies. Any restrictions or tightening of the rules for lease or partnership transactions - whether or not part of major tax reform - could also materially affect our business, financial condition, future results and cash flow.
Any such changes could significantly increase the regulatory-related compliance and other expenses incurred by the projects and could significantly reduce or entirely eliminate the revenues generated by one or more of the projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation, which currently are significant, may increase in the future and could materially and adversely affect our business, financial condition, future results and cash flow; any non-compliance with such laws or regulations may result in the imposition of liabilities which could materially and adversely affect our business, financial condition, future results and cash flow.
Our projects are required to comply with numerous domestic and foreign federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for construction and/or operation. Some of the environmental permits and governmental approvals that have been issued to the projects contain conditions and restrictions, including restrictions or limits on emissions and discharges of pollutants and contaminants, or may have limited terms. If we fail to satisfy these conditions or comply with these restrictions, or with any statutory or regulatory environmental standards, we may become subject to regulatory enforcement action and the operation of the projects could be adversely affected or be subject to fines, penalties or additional costs. In addition, we may not be able to renew, maintain or obtain all environmental permits and governmental approvals required for the continued operation or further development of the projects. As of the date of this report, we have not yet obtained certain permits and government approvals required for the completion and successful operation of projects under construction or enhancement. In addition, a nearby municipality has informed our Amatitlan project that an additional building permit should be obtained from such municipality before construction commences. Our failure to renew, maintain or obtain required permits or governmental approvals, including the permits and approvals necessary for operating projects under construction or enhancement, could cause our operations to be limited or suspended. Environmental laws, ordinances and regulations affecting us can be subject to change and such change could result in increased compliance costs, the need for additional capital expenditures, or otherwise adversely affect us.
We could be exposed to significant liability for violations of hazardous substances laws because of the use or presence of such substances at our projects.
Our projects are subject to numerous domestic and foreign federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We use isobutane, isopentane, industrial lubricants and other substances at our projects which are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the projects, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations (or any change thereto), we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, in the United States, we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.
We believe that at one time there may have been a gas station located on the Mammoth project site, but because of significant surface disturbance and construction since that time further physical evaluation of the former gas station site has been impractical. There may be soil or groundwater contamination and related potential liabilities of which we are unaware related to this site, which may be significant and could materially and adversely affect our business, financial condition, future results and cash flow.
We may not be able to successfully integrate companies which we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:
• failure of the acquired companies to achieve the results we expect;
• inability to retain key personnel of the acquired companies;
• risks associated with unanticipated events or liabilities; and
• the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.
If any of our acquired companies suffers customer dissatisfaction or performance problems, the same could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition, and we encounter competition from electric utilities, other power producers, and power marketers that could materially and adversely affect our business, financial condition, future results and cash flow.
The power generation industry is characterized by intense competition from electric utilities, other power producers and power marketers. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short-term or ‘‘spot’’ markets, and competition has contributed to a reduction in electricity prices. For the most part, we expect that power purchasers interested in long-term arrangements will engage in ‘‘competitive bid’’ solicitations to satisfy new capacity demands. This competition could adversely affect our ability to obtain power purchase agreements and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities. This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will put further pressure on power purchasers to reduce the prices at which they purchase electricity from us.
The existence of a prolonged force majeure event or a forced outage affecting a project could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
The operation of our subsidiaries’ geothermal power plants is subject to a variety of risks discussed elsewhere in these risk factors, including events such as fires, explosions, earthquakes, landslides, floods, severe storms or other similar events.
If a project experiences an occurrence resulting in a force majeure event, our subsidiary that owns that project would be excused from its obligations under the relevant power purchase agreement. However, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our power purchase agreements, will have the right to prematurely terminate the power purchase agreement. Additionally, to the extent that a forced outage has occurred, the relevant power purchaser may not be required to make any capacity and/or energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our power purchase agreements, the purchaser may have the right to permanently reduce the contract capacity (and, correspondingly, the amount of capacity payments due pursuant to such agreements in the future), seek refunds of certain past capacity payments, and/or prematurely terminate the power purchase agreement. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that applies to the force majeure event or forced outage after the relevant waiting period, and may incur significant liabilities in respect of past amounts required to be refunded. Accordingly, our business, financial condition, future results and cash flows could be materially and adversely affected.
The existence of a force majeure event or a forced outage affecting the transmission system of the Imperial Irrigation District could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow.
If the transmission system of the Imperial Irrigation District experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber 1, 2 and Gould 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, 2007, from the projects utilizing the Imperial Irrigation District transmission system, were approximately $98.4 million. The impact of such force majeure would depend on the duration thereof, with longer outages resulting in greater revenue loss.
Some of our leases will terminate if we do not extract geothermal resources in ‘‘commercial quantities’’, thus requiring us to enter into new leases or secure rights to alternate geothermal resources, none of which may be available on terms as favorable to us as any such terminated lease, if at all.
Most of our geothermal resource leases are for a fixed primary term, and then continue for so long as geothermal resources are extracted in ‘‘commercial quantities’’ or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet produced geothermal resources in ‘‘commercial quantities’’. Leases that cover land which remains undeveloped and does not produce, or does not continue to produce, geothermal resources in commercial quantities and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable 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. We may not be able to do this or may not be able to do so without incurring increased costs, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our 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, financial condition, future results and cash flow.
Pursuant to the terms of our Bureau of Land Management (which we refer to as BLM) leases, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. Additionally, certain BLM leases contain additional requirements, some of which relate to the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered plants or animals, the payment of royalties for timber and the imposition of certain restrictions on residential development on the leased land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any of the provisions of the Geothermal Steam Act of 1970 or regulations issued thereunder, the BLM may, 30 days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, future results and cash flow.
Some of our leases (or subleases) could terminate if the lessor (or sublessor) under any such lease (or sublease) defaults on any debt secured by the relevant property, thus terminating our rights to access the underlying geothermal resources at that location.
The fee interest in the land which is the subject of some of our leases (or subleases) may currently be or may become subject to encumbrances securing loans from third party lenders to the lessor (or sublessor). Our rights as lessee (or sublessee) under such leases (or subleases) are or may be subject and subordinate to the rights of any such lender. Accordingly, a default by the lessor (or sublessor) under any such loan could result in a foreclosure on the underlying fee interest in the property and thereby terminate our leasehold interest and result in the shutdown of the project located on the relevant property and/or terminate our right of access to the underlying geothermal resources required for our operations.
In addition, a default by a sublessor under its lease with the owner of the property that is the subject of our sublease could result in the termination of such lease and thereby terminate our sublease interest and our right to access the underlying geothermal resources required for our operations.
Current and future urbanizing activities and related residential, commercial and industrial developments may encroach on or limit geothermal activities in the areas of our projects, thereby affecting our ability to utilize, access, inject and/or transport geothermal resources on or underneath the affected surface areas.
Current and future urbanizing activities and related residential, commercial and industrial development may encroach on or limit geothermal activities in the areas of our projects, thereby affecting our ability to utilize, access, inject and/or transport geothermal resources on or underneath the affected surface areas. In particular, the Heber projects and the Gould project rely on an area, which we refer to as the Heber Known Geothermal Resource Area or Heber KGRA, for the geothermal resource necessary to generate electricity at the Heber projects and Gould project. Imperial County has adopted a ‘‘specific plan area’’ that covers the Heber KGRA, which we refer to as the ‘‘Heber Specific Plan Area’’. The Heber Specific Plan Area allows commercial, residential, industrial and other employment oriented development in a mixed-use orientation, which currently includes geothermal uses. Several of the landowners from whom we hold geothermal leases have expressed an interest in developing their land for residential, commercial, industrial or other surface uses in accordance with the parameters of the Heber Specific Plan Area. Currently, Imperial County’s Heber Specific Plan Area is coordinated with the cities of El Centro and Calexio. There has been ongoing underlying interest since the early 1990s to incorporate the community of Heber. While any incorporation process would likely take several years, if Heber were to be incorporated, the City of
Heber could replace Imperial County as the governing land use authority, which, depending on its policies, could have a significant effect on land use and availability of geothermal resources.
Current and future development proposals within Imperial County and the City of Calexico, applications for annexations to the City of Calexico, and plans to expand public infrastructure may affect surface areas within the Heber KGRA, thereby limiting our ability to utilize, access, inject and/or transport the geothermal resource on or underneath the affected surface area that is necessary for the operation of our Heber projects and Gould project, which could adversely affect our operations and reduce our revenues.
Current transportation construction works and urban developments in the vicinity of our Steamboat complex of projects in Nevada may also affect future permitting for geothermal operations relating to those projects. Such works and developments include the extension of an interstate highway (to be named U.S. 580) by the Nevada Department of Transportation, the construction of a new casino hotel and other commercial or industrial developments on land in the vicinity of our Steamboat projects.
We depend on key personnel for the success of our business.
Our success is largely dependent on the skills, experience and efforts of our senior management team and other key personnel. In particular, our success depends on the continued efforts of Lucien Bronicki, Dita Bronicki, Nadav Amir, Yoram Bronicki and other key employees. The loss of the services of any key employee could materially harm our business, financial condition, future results and cash flow. Although to date we have been successful in retaining the services of senior management and have entered into employment agreements with Lucien Bronicki, Dita Bronicki and Yoram Bronicki, such members of our senior management may terminate their employment agreements without cause and with notice periods ranging from 90 to 180 days. We may also not be able to locate or employ on acceptable terms qualified replacements for our senior management or key employees if their services were no longer available.
Our projects have generally been financed through a combination of parent company loans and limited− or non-recourse project finance debt and lease financing. If our project subsidiaries default on their obligations under such limited or non-recourse debt or lease financing, we may be required to make certain payments to the relevant debt holders and if the collateral supporting such leveraged financing structures is foreclosed upon, we may lose certain of our projects.
Our projects have generally been financed using a combination of parent company loans and limited or non-recourse project finance debt or lease financing. Non-recourse project finance debt or lease financing refers to financing arrangements that are repaid solely from the project’s revenues and are secured by the project’s physical assets, major contracts, cash accounts and, in many cases, our ownership interest in the project subsidiary. Limited recourse project finance debt refers to our additional agreement, as part of the financing of a project, to provide limited financial support for the project subsidiary in the form of limited guarantees, indemnities, capital contributions and agreements to pay certain debt service deficiencies. If our project subsidiaries default on their obligations under the relevant debt documents, creditors of a limited recourse project financing will have direct recourse to us, to the extent of our limited recourse obligations, which may require us to use distributions received by us from other projects, as well as other sources of cash available to us, in order to satisfy such obligations. In addition, if our project subsidiaries default on their obligations under the relevant debt documents (or a default under such debt documents arises as a result of a cross-default to the debt documents of some of our other projects) and the creditors foreclose on the relevant collateral, we may lose our ownership interest in the relevant project subsidiary or our project subsidiary owning the project would only retain an interest in the physical assets, if any, remaining after all debts and obligations were paid in full.
Changes in costs and technology may significantly impact our business by making our power plants and products less competitive.
A basic premise of our business model is that generating baseload power at geothermal power plants achieves economies of scale and produces electricity at a competitive price. However,
traditional coal-fired systems and gas-fired systems may under certain economic conditions produce electricity at lower average prices than our geothermal plants. In addition, there are other technologies that can produce electricity, most notably fossil fuel power systems, hydroelectric systems, fuel cells, microturbines, windmills and photovoltaic (solar) cells. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants; however, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our projects may be significantly impaired.
Our expectations regarding the market potential for the development of recovered energy-based power generation may not materialize, and as a result we may not derive any significant revenues from this line of business.
We have identified recovered energy-based power generation as a significant market opportunity for us. Demand for our recovered energy-based power generation units may not materialize or grow at the levels that we expect. We currently face competition in this market from manufacturers of conventional steam turbines and may face competition from other related technologies in the future. If this market does not materialize at the levels that we expect, such failure may materially and adversely affect our business, financial condition, future results and cash flow.
Our intellectual property rights may not be adequate to protect our business.
Our intellectual property rights may not be adequate to protect our business. While we occasionally file patent applications, patents may not be issued on the basis of such applications or, if patents are issued, they may not be sufficiently broad to protect our technology. In addition, any patents issued to us or for which we have use rights may be challenged, invalidated or circumvented.
In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.
Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties’ patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management’s attention from our core business.
We are subject to risks associated with a changing economic and political environment, which may adversely affect our financial stability or the financial stability of our counterparties.
The risk of terrorist attacks in the United States or elsewhere continues to remain a potential source of disruption to the nation’s economy and financial markets in general. The availability and cost of capital for our business and that of our competitors has been adversely affected by the bankruptcy of Enron Corp. and events related to the California electric market crisis. Additionally, the recent rise in fuel costs may make it more expensive for our customers to operate their businesses. These events could constrain the capital available to our industry and could adversely affect our financial stability and the financial stability of our transaction counterparties.
Possible fluctuations in the cost of construction, raw materials and drilling may materially and adversely affect our business, financial condition, future results and cash flow.
Our manufacturing operations are dependent on the supply of various raw materials, including primarily steel and aluminum, and on the supply of various industrial equipment components that we
use. We currently obtain all such materials and equipment at prevailing market prices. We are not dependent on any one supplier and do not have any long-term agreements with any of our suppliers. We have recently experienced increases in the cost of raw materials and in transportation costs. We have also experienced an increase in construction costs and an increase in drilling costs. To the extent not otherwise passed along to our customers, these and future cost increases of such raw materials and equipment could adversely affect our profit margins.
Conditions in Israel, where the majority of our senior management and all of our production and manufacturing facilities are located, may adversely affect our operations and may limit our ability to produce and sell our products or manage our projects.
Operations in Israel accounted for approximately 26.4%, 24.1% and 25.2% of our operating expenses in the year ended December 31, 2007, 2006 and 2005, respectively. Political, economic and security conditions in Israel directly affect our operations. Since the establishment of the State of Israel in 1948, a number of armed conflicts have taken place between Israel and its Arab neighbors, and the continued state of hostility, varying in degree and intensity, has led to security and economic problems for Israel. Since October 2000, there has been a significant increase in violence, primarily in the West Bank and Gaza Strip. As a result, negotiations between Israel and representatives of the Palestinian Authority have been sporadic and have failed to result in peace. We could be adversely affected by hostilities involving Israel, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results and cash flow.
Failure to comply with certain conditions and restrictions associated with tax benefits provided to Ormat Systems Ltd. by the Government of Israel as an ‘‘approved enterprise’’ may require us to refund such tax benefits and pay future taxes in Israel at higher rates.
Our subsidiary, Ormat Systems Ltd., which we refer to as Ormat Systems, has received ‘‘Benefited Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959, with respect to two of its investment programs. As a Benefited Enterprise, our subsidiary was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period from July 1, 2004 to June 30, 2006, and thereafter such income is subject to a reduced Israeli income tax rate of 25% for an additional five years. Our subsidiary is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for the period from January 1, 2007 to December 31, 2008, and thereafter such income is subject to a reduced Israeli income tax rate of 25% for an additional five years. These benefits are subject to certain conditions, including among other things, a requirement that Ormat Systems comply with Israeli intellectual property law, that all transactions between Ormat Systems and our affiliates be at arms length, and that there will be no change in control of, on a cumulative basis, more than 49% of Ormat Systems’ capital stock (including by way of a public or private offering) without the prior written approval of the Income Tax Authorities. If Ormat Systems does not comply with these conditions, in whole or in part, it would be required to refund the amount of tax benefits (as adjusted by the Israeli consumer price index and for accrued interest) and would no longer benefit from the reduced Israeli tax rate, which could have an adverse effect on our business, financial condition, future results and cash flow. If Ormat Systems distributes dividends out of revenues derived during the tax exemption period from the benefited investment program, it will be subject, in the year in which such dividend is paid, to Israeli income tax on the distributed dividend.
If our parent defaults on its lease agreement with the Israel Land Administration, or is involved in a bankruptcy or similar proceeding, our rights and remedies under certain agreements pursuant to which we acquired our products business and pursuant to which we sublease our land and manufacturing facilities from our parent may be adversely affected.
We acquired our business relating to the manufacture and sale of products for electricity generation and related services from our parent, Ormat Industries. In connection with that acquisition, we entered into a sublease with Ormat Industries for the lease of the land and facilities in Yavne, Israel where our manufacturing and production operations are conducted and where our Israeli offices are located. Under the terms of our parent’s lease agreement with the Israel Land Administration, any sublease for a period of more than five years may require the prior approval of the Israel Land Administration. As a result, the initial term of our sublease with Ormat Industries is for a period of four years and eleven months beginning on July 1, 2004, extendable to twenty-five years less one day (which includes the initial term). The consent of the Israel Land Administration was obtained for a period of the shorter of (i) 25 years or (ii) the remaining period of the underlying lease agreement with the Israel Land Administration, which terminates between 2018 and 2047. On December 3, 2007, our board of directors approved a new lease transaction whereby we will enter into an additional lease agreement with Ormat Industries for the sublease of additional manufacturing facilities that will be built adjacent to the existing facilities. The agreement will expire on the same date as the abovementioned agreement. If our parent were to breach its obligations to the Israel Land Administration under its lease agreement, the Israel Land Administration could terminate the lease agreement and, consequently, our sublease would terminate as well.
As part of the acquisition described in the preceding paragraph, we also entered into a patent license agreement with Ormat Industries, pursuant to which we were granted an exclusive license for certain patents and trademarks relating to certain technologies that are used in our business. If a bankruptcy case were commenced by or against our parent, it is possible that performance of all or part of the agreements entered into in connection with such acquisition (including the lease of land and facilities described above) could be stayed by the bankruptcy court in Israel or rejected by a liquidator appointed pursuant to the Bankruptcy Ordinance in Israel and thus not be enforceable. Any of these events could have a material and adverse effect on our business, financial condition, future results and cash flow.
We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the projects they operate, most of which are subject to restrictions and taxation on dividends and distributions.
We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow.
The agreements pursuant to which most of our subsidiaries have incurred debt restrict the ability of these subsidiaries to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses, debt service and replenishment or maintenance of cash reserves. In the case of some of our projects, such as the Mammoth project, there may be certain additional restrictions on dividend distributions pursuant to our agreements with our partners. Further, if we elect to receive distributions of earnings from our foreign operations, we may incur United States taxes on account of such distributions, net of any available foreign tax credits. In all of the foreign countries where our existing projects are located, dividend payments to us are also subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of revenues we can receive from our subsidiaries.
Some of our directors and executive officers who also hold positions with our parent may have conflicts of interest with respect to matters involving both companies.
Three of our seven directors are directors and/or officers of Ormat Industries, namely Lucien Bronicki, Dita Bronicki and Yoram Bronicki. In addition, four of our executive officers are also executive officers of Ormat Industries. Specifically, our Chairman, Director and Chief Technology
Officer, Lucien Bronicki, is the Chairman of our parent; our Chief Executive Officer and Director, Dita Bronicki, is the Chief Executive Officer of our parent; our Chief Financial Officer, Joseph Tenne, is the Chief Financial Officer of our parent; and Etty Rosner our Senior Vice President - Contract Management and Corporate Secretary is the Corporate Secretary of our parent. These directors and officers owe fiduciary duties to both companies and may have conflicts of interest on matters affecting both us and our parent, and in some circumstances may have interests adverse to our interests.
Our controlling stockholders may take actions that conflict with your interests.
Ormat Industries Ltd. holds approximately 60.27% of our common stock. Bronicki Investments Ltd. holds approximately 35.22% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 28, 2008 (35.12% on a fully diluted basis). Bronicki Investments Ltd. is a privately held Israeli company and is controlled by Lucien and Dita Bronicki. Because of these holdings, our parent company will be able to exercise control over all matters requiring stockholder approval, including the election of directors, amendment of our certificate of incorporation and approval of significant corporate transactions, and they will have significant control over our management and policies. The directors elected by these stockholders will be able to significantly influence decisions affecting our capital structure. This control may have the effect of delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in their best interest. For example, our controlling stockholders will be able to control the sale or other disposition of our products business to another entity or the transfer of such business outside of the State of Israel; as such action requires the affirmative vote of at least 75% of our outstanding shares.
The price of our common stock may fluctuate substantially and your investment may decline in value.
The market price of our common stock is likely to be highly volatile and may fluctuate substantially due to many factors, including:
• actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-based revenues;
• variance in our financial performance from the expectations of market analysts;
• conditions and trends in the end markets we serve and changes in the estimation of the size and growth rate of these markets;
• announcements of significant contracts by us or our competitors;
• changes in our pricing policies or the pricing policies of our competitors;
• loss of one or more of our significant customers;
• legislation;
• changes in market valuation or earnings of our competitors;
• the trading volume of our common stock; and
• general economic conditions.
In addition, the stock market in general, and the New York Stock Exchange and the market for energy companies in particular, have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of particular companies affected. These broad market and industry factors may materially harm the market price of our common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted against that company. Such litigation, if instituted against us, could result in substantial costs and a diversion of management’s attention and resources, which could materially harm our business, financial condition, future results and cash flow.
Future sales of common stock by some of our existing stockholders could cause our stock price to decline.
As of the date of this report, our parent, Ormat Industries Ltd., holds approximately 60.3% of our outstanding common stock and some of our directors, officers and employees also hold shares of our
outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline. On November 10, 2004, we entered into a registration rights agreement with Ormat Industries whereby Ormat Industries may require us to register our common stock held by it or its directors, officers and employees with the Securities and Exchange Commission or to include our common stock held by it or its directors, officers and employees in an offering and sale by us.
Provisions in our charter documents and Delaware law may delay or prevent acquisition of us, which could adversely affect the value of our common stock.
Our restated certificate of incorporation and our bylaws contain provisions that could make it harder for a third party to acquire us without the consent of our Board of Directors. These provisions do not permit actions by our stockholders by written consent. In addition, these provisions include procedural requirements relating to stockholder meetings and stockholder proposals that could make stockholder actions more difficult. Our Board of Directors is classified into three classes of directors serving staggered, three-year terms and may be removed only for cause. Any vacancy on the Board of Directors may be filled only by the vote of the majority of directors then in office. Our Board of Directors has the right to issue preferred stock without stockholder approval, which could be used to institute a ‘‘poison pill’’ that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by our Board of Directors. Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Although we believe these provisions provide for an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders.
The Sarbanes-Oxley Act of 2002 imposes significant regulatory, corporate and operational requirements on the Company. Failure to comply with such provisions may have significant adverse consequences to the Company
As a public company, we are subject to the Sarbanes-Oxley Act of 2002 (the SOX Act). The SOX Act contains a variety of provisions affecting public companies, including but not limited to, corporate governance requirements, our relationship with our auditors, evaluation of our internal disclosure controls and procedures and evaluation of our internal control over financial reporting. See Management’s Report on Internal Control over Financial Reporting and Item 9A. - ‘‘Controls and Procedures’’.
Funds we have invested in certain auction rate securities may not be accessible for longer than 12 months and such auction rate securities may experience an other than temporary decline in value, which would adversely affect our income.
Our marketable securities portfolio, which totals $38.1 million at December 31, 2007, includes auction rate securities with a par value of $24.4 million. Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days, but with contractual maturities that can be well in excess of ten years. At the end of each reset period, which depending on the security can occur on a daily, weekly, or monthly basis, investors can sell or continue to hold the securities at par. In the fourth quarter of 2007, certain auction rate securities held by us with a par value of $11.2 million failed auction due to sell orders exceeding buy orders. As a result, we changed the way we determine the fair value of some of these investments in our financial statements for the year ended December 21, 2007, as described in Note 1 to our consolidated financial statements set forth in Part II Item 8 of this annual report. Among other things, these changes resulted in asset impairment charges and unrealized losses, which adversely affected our income and financial position for 2007.
The funds invested in auction rate securities that have experienced failed auctions will not be accessible until a successful auction occurs, a buyer is found outside of the auction process or the underlying securities have matured.
If the current market conditions deteriorate further, or the anticipated recovery in market values does not occur, we may be required to record additional unrealized losses in other comprehensive income or impairment charges in 2008.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We currently lease corporate offices at 6225 Neil Road, Reno, Nevada 89511-1136. We also occupy an approximately 66,000 square meter office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we sublease from Ormat Industries. See Item 13 - ‘‘Certain Relationships and Related Transactions’’. We also lease small offices in each of the countries in which we operate.
We believe that our current facilities 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 2007, other than as described below.
As a result of our acquisition of the Steamboat 1 and 1A plants, our subsidiary Steamboat Geothermal LLC became a party to litigation pending in the Second Judicial District Court in Washoe County, Nevada with Geothermal Development Associates (GDA) and Delphi Securities, Inc. In April 2002, these plaintiffs initiated a lawsuit against the former owner and operator of the Steamboat 1/1A project claiming amounts owed under certain operating agreements. On December 31, 2005 and January 9, 2006, Steamboat Geothermal LLC entered into a sales, settlement and release agreement and an assignment agreement, respectively, with Woodside Properties LLC, the assignee of 37% of Geothermal Development Associates’ right to net operating revenues, whereby Steamboat Geothermal LLC was assigned 37% of the net operating revenues of Steamboat 1 in partial settlement of the above mentioned dispute with GDA and Delphi Securities, Inc. On April 11, 2007, following a successful mediation, the parties reached a final settlement of the remaining claims. As a result of the settlement, we recorded an additional provision of $0.8 million as of March 31, 2007, and paid the total settlement amount to GDA in April 2007. The settlement agreement provides for a mutual release of any and all claims, demands and causes of action by and between the parties and stipulates that the settlement should not be construed as an admission of liability or fault by any party.
In connection with the power purchase agreements for the Ormesa project, Southern California Edison had expressed its intent not to pay the contract rate for power supplied by the GEM 2 and GEM 3 plants to the Ormesa project. Southern California Edison contended that California ISO real-time prices should apply, while management believed that SP-15 prices quoted by NYMEX should apply. Ormesa LLC, a wholly-owned subsidiary of the Company, and Southern California Edison signed an Interim Agreement in 2005 whereby Southern California Edison agreed to procure GEM 2 and GEM 3 power at the then-current energy rate under the July 18, 1984 Ormesa power purchase agreement of 5.37 cents per kWh until May 1, 2007. On April 23, 2007, the parties finalized an agreement with terms that are similar to the arrangement agreed to in the Interim Agreement, whereby 6.5 MW of power from GEM 2 and GEM 3 will be sold to Southern California Edison at the current energy rate of the July 18, 1984 Ormesa power purchase agreement. For the period
commencing May 1, 2007, the energy rate is 6.15 cents per kWh. The parties simultaneously entered into other agreements and agreed to release each other from any and all claims relating to the Ormesa projects. Pursuant to these agreements, Ormesa LLC paid Southern California Edison an immaterial amount to consolidate the June 13, 1984 and July 18, 1984 power purchase agreements. Combining these agreements will reduce scheduling fees over the term of the agreement and provide other operational benefits.
One of our subsidiaries, Ormat Inc., had been a party in a third-party complaint originally filed on November 15, 2005 by Lacy M. Henry and Judy B. Henry (the Henrys) in a bankruptcy proceeding in the United States Bankruptcy Court for the Eastern District of North Carolina. The Henrys are debtors in a Chapter 11 bankruptcy filed in the Bankruptcy Court. The Henrys were the sole shareholders of MPS Generation, Inc. (MPSG). We entered into a supply contract with MPSG dated as of December 29, 2003, under which we were retained as a subcontractor to produce four waste heat energy converters for a project for which MPSG had entered into a contract with Basin Electric Power Cooperative (Basin). Basin filed a lawsuit on February 24, 2005 against, among others, MPSG and the Henrys in the United States District Court for the District of North Dakota, alleging various causes of action including breach of contract, actual and constructive fraud, and conversion, and demanding the piercing of MPSG’s corporate veil to establish the personal liability of the Henrys for MPSG’s debts. On September 15, 2005, Basin filed a complaint commencing the bankruptcy adversary proceeding, seeking a determination that the claims which Basin alleged against the Henrys in the North Dakota lawsuit were not dischargeable. On November 15, 2005, the Henrys answered Basin’s complaint in the bankruptcy proceeding and also filed a third-party complaint against us, alleging that to the extent the Henrys are found personally liable to Basin for MPSG’s debts, the Henrys have claims against us for breach of contract/breach of warranty, tortious interference with contract, unfair or deceptive trade practices and fraud. The Henrys alleged damages in excess of $100 million. On December 15, 2005, we filed an answer denying the Henrys’ claims and asserting counterclaims against the Henrys. Our subsidiary filed a motion to dismiss the Henrys’ claims on January 31, 2006. On March 21, 2006, Basin filed an Amended Complaint in the bankruptcy proceeding, consolidating the causes of action it brought in the North Dakota lawsuit. In their answer to Basin’s Amended Complaint, the Henrys raised the same third party claims against our subsidiary. On May 11, 2006, the Bankruptcy Court entered an order denying our subsidiary’s motion to dismiss the Henrys’ claims against it, but staying the Henrys’ litigation against our subsidiary pending the resolution of Basin’s alter ego claims against the Henrys. On October 25, 2007, all of the parties entered into a settlement agreement, which provides for the release of any and all claims, demands, and causes of action by and among the parties, and stipulates that the settlement should not be construed as an admission of liability or wrongdoing by any party. Our subsidiary was not required to make any payment to any of the parties as part of the settlement agreement.
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
On December 18, 2007, we sent our shareholders an information statement regarding action taken by written consent of majority shareholders without a meeting. We requested stockholder consent to comply with NYSE requirements that an issuer of listed securities obtain prior stockholder approval of an issuance of shares of common stock to a related party in an aggregate amount greater than 1% of an issuer’s outstanding shares of common stock or one percent of the voting power outstanding before the issuance. This approval was required by the NYSE in connection with our proposed sale of 693,750 shares of common stock to our parent for an aggregate purchase price of
approximately $33.3 million, as described in 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 10 on February 28, 2008. On February 28, 2008, our stock’s closing price as reported on the New York Stock Exchange was $45.31 per share.
Dividends:
We have adopted a dividend policy pursuant to which we currently expect to distribute at least 20% of our annual profits available for distribution by way of quarterly dividends. In determining whether there are profits available for distribution, our Board of Directors will take into account our business plan and current and expected obligations, and no distribution will be made that in the judgment of our Board of Directors would prevent us from meeting such business plan or obligations.
Notwithstanding this policy, dividends will be paid only when, as and if approved by our Board of Directors out of funds legally available therefore. The actual amount and timing of dividend payments will depend upon our financial condition, results of operations, business prospects and such other matters as the board may deem relevant from time to time. Even if profits are available for the payment of dividends, the Board of Directors could determine that such profits should be retained for an extended period of time, used for working capital purposes, expansion or acquisition of businesses or any other appropriate purpose. As a holding company, we are dependent upon the earnings and cash flow of our subsidiaries in order to fund any dividend distributions and, as a result, we may not be able to pay dividends in accordance with our policy. Our Board of Directors may, from time to time, examine our dividend policy and may, in its absolute discretion, change such policy.
We have declared the following dividends over the past two years:
High/Low Stock Prices:
Ormat Technologies, Inc. (ORA) - High and Low Prices for the years ended December 31, 2006 and 2007, and from January 1 until February 28, 2008:
Stock Performance Graph:
The following performance graph represents the cumulative total shareholder return for the period November 11, 2004 (the date upon which trading of the Company’s common stock commenced) through December 31, 2007 for our common stock, as compared to the Standard and Poor’s Composite 500 Index, and a peer group.
* Independent Power Producer (IPP) Peers are The AES Corporation, NRG Energy Inc. and International Power PLC, Renewable Energy (Renewable) Peers are Acciona S.A., Evergreen Solar Inc., Energy Conversion Devices Inc., Nevada Geothermal Power Corp. and U.S. Geothermal Inc.
The above Stock Performance Graph shall not be deemed to be soliciting material or to be filed with the SEC under the Securities Act and the Exchange Act except to the extent that the Company specifically requests that such information be treated as soliciting material or specifically incorporates it by reference into a filing under the Securities Act or the Exchange Act.
Equity Compensation Plan Information
For information on our equity compensation plan, refer to Item 12 - ‘‘Security Ownership of Certain Beneficial Owners and Management’’.
Unregistered Sales of Equity Securities and Use of Proceeds from Registered Securities
On October 26, 2007, we completed an unregistered sale of 381,254 shares of common stock to our parent, Ormat Industries Ltd., at a price of $45.90 per share, or approximately $17.5 million. On January 8, 2008, we completed an unregistered sale of 693,750 shares of common stock to our parent, at a price of $48.02 per share of common stock, or approximately $33.3 million. We believe that these unregistered sales complied with the requirements of Regulation S under the Securities Act. Our parent is not a U.S. Person within the meaning of Regulation S. The sales were made in an offshore transaction, and no selling efforts were made in the U.S. Our parent agreed that the shares of common stock issued in the unregistered sales would not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act,
Available Financial Information
We make available our annual report, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 free of charge on our website at www.ormat.com, as soon as reasonably practicable after they are electronically filed or furnished to the SEC. Additionally, copies of materials filed by us with the SEC may be accessed at the SEC’s Public Reference Room at 100 F Street, N.E. Washington, D.C. 20549 or at http://www.sec.gov. For information about the SEC’s Public Reference Room, the public may contact 1-800-SEC-0330. The contents of our website are not incorporated into, or otherwise to be regarded as a part of, this annual report.
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, 2007, 2006 and 2005 and as of December 31, 2007 and 2006 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, 2004 and 2003, and as of December 31, 2005, 2004 and 2003 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 Item 1A - ‘‘Risk Factors’’ for a discussion of important factors that could cause actual results to differ materially from the results described herein or implied by such forward-looking statements.
General
Overview
We are a leading vertically integrated company engaged in the geothermal and recovered energy power business. We design, develop, build, own and operate clean, environmentally friendly geothermal and recovered energy-based power plants, in most cases using equipment that we design and manufacture.
Our geothermal power plants include both power plants that we have built and power plants that we have acquired, while all of our recovered energy-based plants have been constructed by us. We conduct our business activities in two business segments, which we refer to as our Electricity Segment and Products Segment. In our Electricity Segment, we develop, build, own and operate geothermal and recovered energy-based power plants in the United States and geothermal power plants in other countries around the world and sell the electricity they generate. In our Products Segment, we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation, remote power units and other power generating units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal and recovered energy power plants. Both our Electricity Segment and Products Segment operations are conducted in the United States and throughout the world. We currently own or control, as well as operate, geothermal projects in the United States, Guatemala, Kenya and Nicaragua, as well as recovered energy generation (REG) plants in the United States. During the years ended December 31, 2007 and 2006, our U.S. power plants generated 1,994,263 MWh and 1,789,794 MWh, respectively.
For the year ended December 31, 2007, our Electricity Segment represented approximately 73.0% of our total revenues, while our Products Segment represented approximately 27.0% of our total revenues during such year.
During the year ended December 31, 2007, our total revenues increased by 10.0% (from $268.9 million to $296.0 million) over the previous year. Revenues from the Electricity Segment increased by 10.5%, while revenues from the Products Segment increased by 8.8%.
For the year ended December 31, 2007, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $216.0 million. In addition, revenues from our 50% ownership of the Mammoth Project and from our 80% ownership of the Leyte Project were $17.6 million for the year ended December 31, 2007. This additional data is a Non-Generally Accepted Accounting Principles (Non-GAAP) financial measure as defined by the SEC. There is no comparable GAAP measure. Management believes that such Non-GAAP data is useful to the readers as it provides a more complete view on the scope of the activities of the power plants that we operate. Our Leyte project was transferred to PNOC-Energy Development Corporation on September 25, 2007 pursuant to the terms of a Build, Operate, and Transfer agreement under which we previously owned and operated that project. Our investments in the Mammoth and Leyte projects are accounted for in our consolidated financial statements under the equity method and the revenues are not included in our consolidated revenues for the year ended December 31, 2007.
During the year ended December 31, 2007, revenues attributable to our Products Segment were $80.0 million.
Recovered energy-based power generation continues to present opportunities for us in the United States and throughout the world. We expect that recovered energy generation projects will continue to contribute to our growth in both the Electricity Segment and the Products Segment. During the year ended December 31, 2007, we recognized revenues in our Products Segment of approximately $37.3 million from REG compared to $25.0 million during the year ended December 31, 2006.
Revenues from our Electricity Segment are relatively predictable, as they are derived from sales of electricity generated by our power plants pursuant to long-term power purchase agreements. The price for electricity under all but one of our power purchase agreements is effectively a fixed price at least through May 2012. The exception is the power purchase agreement of the Puna project. It has a variable energy rate based on the local utility’s short run avoided costs, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. In the year ended December 31, 2007, 82.0% of our electricity revenues were derived from contracts with fixed energy rates, and therefore such revenues were not affected by the fluctuations in energy commodity prices. However, electricity revenues are subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under the heading ‘‘Seasonality’’. Revenues attributable to our Products Segment are based on the sale of equipment and the provision of various services to our customers. These revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our execution of each project.
Our management assesses the performance of our two segments of operation differently. In the case of our Electricity Segment, when making decisions about potential acquisitions or the development of new projects, we typically focus on the internal rate of return of the relevant investment, relevant technical and geological matters and other relevant business considerations. We evaluate our operating projects based on revenues and expenses, and our projects that are under development based on costs attributable to each such project. By contrast, we evaluate 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.
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. This is partly due to increasing natural gas and oil prices and 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:
• In 2005, 2006 and 2007, our primary activity has been the implementation of our organic growth through the construction of new projects and enhancements of several of our existing projects, as discussed in Item 1 - ‘‘Business - Our Power Generation Business’’ in this
annual report. As a result, growth in revenues and overall generating capacity has been more moderate than in 2003 and 2004, in which we made significant acquisitions. Nevertheless, we expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment in 2008, as compared with 2007.
• We continue to experience increases in the cost of raw materials and labor and transportation costs required for our manufacturing activities and equipment used in our power plants, as well as for sale to third parties. We have experienced an increase in drilling costs and a shortage in drilling equipment. We believe this is the result of the high oil prices resulting in increased drilling activity in the marketplace. We also have experienced, and expect to continue to experience, an increase in construction costs, resulting from, among other things, increased labor costs. This is particularly true in the United States, where a significant increase in construction activities has caused higher prices. An increase in our raw materials, drilling, construction, labor, transportation and other costs may have an adverse effect on our financial condition and results of operations.
• We expect that the increased awareness of climate change may result in significant changes in the business and regulatory environment, which may create business opportunities for us going forward.
• In the United States, we expect to continue to benefit from the increasing demand for renewable energy. Twenty-nine states and the District of Colombia, including California, Nevada and Hawaii (where we have been most active in geothermal development and in which all of our U.S. geothermal projects are located) have adopted renewable portfolio standards, renewable portfolio goals or other similar laws. These laws require that an increasing percentage of the electricity supplied by electric utility companies operating in such states be derived from renewable energy resources until certain pre-established goals are met. We expect that the additional demand for renewable energy from utilities in such states will create additional opportunities for us to expand existing projects and build new power plants.
• In addition to renewable portfolio standards, several federal climate change proposals are being considered. For example, the Lieberman-Warner Climate Security Act (S. 2191) was approved by the United States Senate Environment and Public Works Committee on December 5, 2007. This bill would place a cap on greenhouse gas emissions and require increasing reductions in greenhouse gas emissions. In the absence of federal legislation, states are passing greenhouse gas legislation. For example, on September 27, 2006, the California Global Warming Solutions Act of 2006 (the Act) was signed into law. The Act regulates most sources of greenhouse gas emissions and is expected to result in a reduction of carbon emissions to 1990 levels by 2020, representing a twenty-five percent reduction in greenhouse gas emissions. To accomplish this, the Act provides a framework for greenhouse gas emissions reductions through the use of emissions control technologies and other cost-effective reduction strategies, one of which may involve the use of market-based trading of emissions rights. In addition to California, sixteen other states have set greenhouse gas emissions targets (Arizona, Connecticut, Florida, Hawaii, Illinois, Massachusetts, Maine, Minnesota, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington). Regional Initiatives are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. For example, many northeastern states are part of the Regional Greenhouse Gas Initiative (‘‘RGGI’’), a regional cap-and trade system to limit carbon dioxide. In addition to RGGI, other states have also established the Midwestern Regional Greenhouse Gas Reduction Accord and the Western Climate Initiative. Although individual and regional programs will take some time to develop, their requirements, particularly the creation of any market-based trading mechanism to achieve compliance with emissions caps, should be advantageous to in-state and in-region
(and, in some cases, such as RGGI and the state of California, inter-regional) energy generating sources that have low carbon emissions such as geothermal energy. Although it is currently hard to quantify the direct economic benefit of these efforts to reduce greenhouse gas emissions, we believe they will prove advantageous to us.
• Outside of the United States, we expect that a variety of governmental initiatives will create new opportunities for the development of new projects, as well as create additional markets for our remote power units and other products. These initiatives include the award of long -term contracts to independent power generators, the creation of competitive wholesale markets for selling and trading energy, capacity and related energy products and the adoption of programs designed to encourage ‘‘clean’’ renewable and sustainable energy sources.
• We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. All of our current revenues from the sale of electricity are derived from fully-contracted payments under long-term power purchase agreements (except as noted below for our Steamboat 1 project, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis). We also intend to continue to pursue growth in our recovered energy business.
• Over the last two years, competition from the wind and solar power generation industry has increased. While the current demand for renewable energy is large enough that this increased competition has not impacted our ability to obtain new power purchase agreements, it may contribute to a reduction in electricity prices.
• Despite increased competition from the wind and solar power generation industry, we believe that baseload electricity, such as geothermal-based energy, will emerge as the preferred source of renewable energy.
• Over the last year, new entrants to the geothermal industry, both in the power generation space and in the lease of geothermal resources, have increased competition in the industry. While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new power purchase agreements and new leases, increased competition in the power generation space may contribute to a reduction in electricity prices and increased competition in geothermal leasing may contribute to an increase in lease costs.
• The viability of our geothermal power plants depends on various factors such as the heat content of the geothermal reservoir, useful life of the reservoir (the term during which such geothermal reservoir has sufficient extractable fluids for our operations) and operational factors relating to the extraction of the geothermal fluids. Our geothermal power plants may experience an unexpected decline in the capacity of their respective geothermal wells. Such factors, together with the possibility that we may fail to find commercially viable geothermal resources in the future, represent significant uncertainties we face in connection with our operations.
• As our power plants age, they may require increased maintenance with a resulting decrease in their availability.
• Our foreign operations are subject to significant political, economic and financial risks, which vary by country. Those risks include the partial privatization of the electricity sector in Guatemala, labor unrest in Nicaragua and the political uncertainty currently prevailing in Kenya and other countries in which we operate. Although we maintain political risk insurance to mitigate such risks, insurance does not provide complete coverage with respect to all such risks.
• The United States extended a tax subsidy and increased the amount of the tax subsidy for companies that use geothermal steam or fluid to generate electricity as part of the Energy Policy Act of 2005 that became law on August 8, 2005. The tax subsidy is a ‘‘production tax credit’’, which in 2007 was 2.0 cents per kWh and is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008.
• The Energy Policy Act of 2005 authorizes FERC to revise PURPA so as to terminate the obligation of electric utilities to purchase the output of a Qualifying Facility if FERC finds that there is an accessible competitive market for energy and capacity from the Qualifying Facility. The legislation does not affect existing power purchase agreements. We do not expect this change in law to affect our U.S. projects significantly, as all except one of our current contracts (our Steamboat 1 project, which sells its electricity to Sierra Pacific Power Company on a year-by-year basis) are long-term. FERC issued a final rule that makes it easier to eliminate the utilities’ purchase obligation in four regions of the country. None of those regions includes a state in which our current projects operate. However, FERC has the authority under the Energy Policy Act of 2005 to act, on a case-by-case basis, to eliminate the mandatory purchase obligation in other regions. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from us upon termination of the existing power purchase agreement, which could have an adverse effect on our revenues.
Revenues
We generate our revenues from the sale of electricity from our geothermal and recovered energy-based power plants; the design, manufacture and sale of equipment for electricity generation; and the construction, installation and engineering of power plant equipment.
Revenues attributable to our Electricity Segment are relatively predictable as they are derived from the sale of electricity from our power plants generally pursuant to long-term power purchase agreements. However, such revenues are subject to seasonal variations, as more fully described below in the section entitled ‘‘Seasonality’’. Electricity Segment revenues may also be affected by higher-than-average ambient temperature, which could cause a decrease in the generating capacity of our power plants, and by unplanned major maintenance activities related to our power plants.
Our power purchase agreements generally provide for the payment of energy or energy and capacity payments. Generally, capacity payments are payments calculated based on the amount of time that our power plants are available to generate electricity. Some of our power purchase agreements provide for bonus payments in the event that we are able to exceed certain target levels and the potential forfeiture of payments if we fail to meet minimum target levels. Energy payments, on the other hand, are payments calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed (subject, in certain cases, to certain adjustments) or are based on the relevant power purchaser’s short run avoided costs (the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others). Our more recent power purchase agreements provide generally for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.
The lease income related to the Puna lease transactions, which are accounted for as operating leases, is included as a separate line item in our Electricity Segment revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes, we analyze such revenue on a combined basis with other revenues in our Electricity Segment.
As required by Emerging Issues Task Force (EITF) Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, we have assessed all of our power purchase agreements agreed to, modified or acquired in business combinations on or after July 1, 2003, and concluded that all such agreements contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the agreements is presented as ‘‘lease portion of energy and capacity’’ revenue, with the remaining revenue related to the production and delivery of the energy presented as ‘‘energy and capacity’’ revenue in our consolidated financial statements. As the lease revenue and the energy and capacity revenues are derived from the same arrangement and both fall within our Electricity Segment, we analyze such revenues, and related costs, on a combined basis for management purposes.
Revenues attributable to our Products Segment are generally less predictable than revenues from our Electricity Segment. This is 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
For the years ended December 31, 2007, 2006 and 2005, respectively, 83.3%, 83.3% and 87.8% of the revenues attributable to our Electricity Segment were generated in the United States. The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment for the years indicated:
In the years ended December 31, 2007 and 2006, 28.1% and 14.3%, respectively, of our revenues attributable to our Products Segments were generated in the United States. In the year ended December 31, 2005, we did not have material products sales in the United States.
Seasonality
The prices paid for the electricity generated by our domestic projects pursuant to our power purchase agreements are subject to seasonal variations. The prices paid for electricity under the power purchase agreements with Southern California Edison, for the Heber 1 and 2 projects, the Mammoth project and the Ormesa project and the prices that will be paid for the electricity under the power purchase agreement for the North Brawley project are higher in the months of June through September. As a result, we receive and will receive in the future higher revenues during such months. The prices paid for electricity pursuant to the power purchase agreements of our projects in Nevada have no significant changes during the year. In the winter, due principally to the lower ambient temperature, our power plants produce more energy and as a result we receive higher energy revenues. However, the higher capacity payments payable by Southern California Edison in California in the summer months have a more significant impact on our revenues than that of the higher energy revenues generally generated in winter due to increased efficiency. As a result, our revenues are generally higher in the summer than in the winter. The prices paid for electricity pursuant to the power purchase agreement of the Puna project are tied to the price of oil. Accordingly, our revenues for that project, which accounted for approximately 14.6% of our total revenues for the year ended December 31, 2007, may be volatile.
Breakdown of Cost of Revenues
Electricity Segment
The principal cost of revenues attributable to our operating projects include operation and maintenance expenses such as depreciation and amortization, salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes and insurance and, for the California projects, transmission charges, scheduling charges and purchases of sweet water for use in our plant cooling towers. Some of these expenses, such as parts, third-party services and major maintenance, are not incurred on a regular basis. This results in fluctuations in our expenses and our results of operations for individual projects from quarter to quarter. The lease expense related to the Puna lease transactions is included as a separate line item in our Electricity Segment cost of revenues (See ‘‘Liquidity and Capital Resources’’). For management purposes, we analyze such costs on a combined basis with other cost of revenues in our Electricity Segment.
Payments made to government agencies and private entities on account of site leases where plants are located are included in cost of revenues. Royalty payments, included in cost of revenues, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenues derived from the associated geothermal rights. For the year ended December 31, 2007, royalties constituted approximately 4.33% of the Electricity Segment revenues, compared to approximately 3.9% in the year ended December 31, 2006.
Products Segment
The principal cost of revenues attributable to our Products Segment include materials, salaries and related employee benefits, expenses related to subcontracting activities, transportation expenses, and sales commissions to sales representatives. Some of the principal expenses attributable to our Products Segment, such as a portion of the costs related to labor, utilities and other support services are fixed, while others, such as materials, construction, transportation and sales commissions, are variable and may fluctuate significantly, depending on market conditions. As a result, the cost of revenues attributable to our Products Segment, expressed as a percentage of total revenues, fluctuates. Another reason for such fluctuation is that in responding to bids for our products, we price our products and services in relation to existing competition and other prevailing market conditions, which may vary substantially from order to order.
Cash, Cash Equivalents and Short-Term Marketable Securities
Our cash, cash equivalents and short-term marketable securities as of December 31, 2007 decreased to $60.7 million from $116.7 million as of December 31, 2006. This decrease is principally due to our use during 2007 of $216.4 million of cash resources to fund capital expenditures and $131.8 million to repay long-term debt to our parent and to third parties (including the $50.7 million capital note on December 3, 2007). The decrease is also attributable to the classification of $2.8 of our marketable securities as non-current assets. This classification is due to failed auctions in the fourth quarter of 2007 of certain auction rate securities in our portfolio, as described below in the section entitled ‘‘Exposure to Market Risks’’. The decrease in our cash resources was partially offset by the $137.2 million net proceeds from our sale of 3,000,000 shares of common stock to Lehman Brothers in a block trade in October 2007 at a price of $45.90 per share (net of underwriting fees and commissions), the $17.5 million net proceeds from our sale of 381,254 shares to our parent at a price of $45.90 per share, the $69.2 million net proceeds from the OPC tax monetization transaction described below, and the $58.7 million derived from operating activities in the year ended December 31, 2007.
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 and, as a result, actual results could differ from our estimates. Our critical accounting policies include:
• Revenues and Cost of Revenues. Revenues related to the sale of electricity from our geothermal and recovered energy-based power plants and capacity payments paid in connection with such sales (electricity revenues) are recorded based upon output delivered and capacity provided by such power plants at rates specified pursuant to the relevant 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 and other equipment on behalf of third parties (products revenues) are recognized using the percentage of completion method. The percentage of completion method requires estimates of future costs over the full term of product delivery. Such cost estimates are made by management based on prior operations and specific project characteristics and designs. If management’s estimates of total estimated costs with respect to our Products Segment are inaccurate, then the percentage of completion is inaccurate resulting in an over or under-estimate of gross margins. As a result, we review and update our cost estimates on significant contracts on a quarterly basis, and no less than annually for all others, or when circumstances change and warrant a modification to a previous estimate. Changes in job performance, job conditions, and estimated profitability, including those arising from the application of penalty provisions in relevant contracts and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses relating to contracts are made in the period in which such losses are determined.
• Property, Plant and Equipment. All costs associated with the acquisition, development and construction of power plant facilities are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. We estimate the useful life of our power plants to range between 25 and 30 years. Such estimates are made by management based on factors such as prior operations, the terms of the underlying power purchase agreements, geothermal resources, the location of the assets and specific project characteristics and designs. Changes in such estimates could result in useful lives which are either longer or shorter than the depreciable lives of such assets. We periodically re-evaluate the estimated useful life of our power plants and revise the remaining depreciable life on a prospective basis.
We capitalize costs incurred in connection with the exploration and development of geothermal resources on an ‘‘area-of-interest’’ basis. All such costs, which include dry hole costs and the cost of drilling and equipping production wells and other directly attributable costs, are capitalized and amortized over their estimated useful lives when production commences. Although we do not commence exploration activities until feasibility studies have determined that the project is capable of commercial production, it is possible that economically recoverable reserves will not be found in an ‘‘area of interest’’ and exploration activities will be abandoned. In this case, capitalized exploration costs would be expensed. To date, we have not abandoned any exploration projects.
• Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. We evaluate long-lived assets, such as property, plant and equipment, power purchase agreements and unconsolidated investments for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Factors which could trigger an impairment include significant underperformance relative to historical or projected future operating results, significant changes in our use of acquired assets or our overall business strategy, negative industry or economic trends, a determination that a suspended project is not likely to be completed, legal factors relating to our business or when we conclude that it is more likely than not that an asset will be disposed of or sold. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated future net undiscounted cash flows expected to be generated by the asset. The significant assumptions that we use in estimating our undiscounted future cash flows include: (i) projected generating capacity of the project and rates to be received under the respective power purchase agreement, and (ii) projected operating expenses of the relevant project.
If our assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Estimates of the fair value of assets require estimating useful lives and selecting a discount rate that reflects the risk inherent in future cash flows. If actual results are not consistent with our assumptions used in estimating future cash flows and fair values, we may incur additional losses that could be material to our financial condition or results of operations.
• Obligations Associated with the Retirement of Long-Lived Assets. We record the fair market value of legal liabilities related to the retirement of our assets in the period in which such liabilities are incurred. Our liabilities related to the retirement of our assets include our obligation to plug 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, we will either settle the obligation for its recorded amount or will report either a gain or a loss with respect thereto. Estimates of the costs associated with asset retirement obligations are based on factors such as prior operations, the location of the assets and specific project characteristics. We review and update our cost estimates periodically and adjust our asset retirement obligations in the period in which the revisions are determined. If actual results are not consistent with our assumptions used in estimating our asset retirement obligations, we may incur additional losses that could be material to our financial condition or results of operations.
• Marketable Securities. Our marketable securities consist of debt securities (mainly auction rate securities and commercial paper). We account for such securities in accordance with SFAS No. 115, Accounting for Investments in Debt and Equity Securities. All of our investments in marketable securities (including marketable securities which are part of restricted cash accounts) are treated as ‘‘available-for-sale’’ under SFAS No. 115. We report marketable securities at fair value with the related unrealized gains and losses included in accumulated other comprehensive income (loss), a component of stockholders’ equity, net of tax. Net realized gains or losses are reported in other income (expense). We evaluate our investments periodically for possible other-than-temporary impairment by reviewing factors such as the length of time and extent to which fair value has been below cost basis, the financial condition of the issuer and our ability and intent to hold the investment for a period of time which may be sufficient for anticipated recovery of market value. An impairment charge is recorded to the extent that the carrying value of available-for-sale securities exceeds the estimated fair market value of the securities and the decline in value is determined to be other-than-temporary.
Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days but with contractual maturities that can be well in excess of ten years. At the end of each reset period, which in our case occurs every twenty-eight days, investors can sell or continue to hold the securities at par. These securities are subject to fluctuations in fair value depending on the supply and demand at each auction. In the fourth quarter of 2007, some of the auction rate securities we held failed to sell in the auctions that are held periodically to re-set the interest rate on those securities. As a result, consistent with our policies described above, we recorded asset impairment charges and unrealized losses for certain of the auction rate securities we held, and classified those securities with failed auctions as long-term assets in our consolidated balance as of December 31, 2007. These charges and the amounts involved are set forth in Note 1 to our consolidated financial statements for the year ended December 31, 2007 set forth in Item 8 of this annual report.
• Accounting for Income Taxes. Significant estimates are required to arrive at our consolidated income tax provision and other tax balances. This process requires us to estimate our actual current tax exposure and to make an assessment of temporary differences resulting from differing treatments of items for tax and accounting purposes. Such differences result in deferred tax assets and liabilities which are included in our consolidated balance sheets. For those jurisdictions where the projected operating results indicate that realization of our net deferred tax assets is not likely, a valuation allowance is recorded.
In assessing the need for a valuation allowance, we estimate future taxable income, considering the feasibility of ongoing tax planning strategies and the realization of tax loss carry-forwards. Valuation allowances related to deferred tax assets can be affected by changes in tax laws, statutory tax rates and future taxable income. Although realization is not assured, management believes it is more likely than not that the deferred tax asset as of December 31, 2007 will be realized. In the event we were to determine that we would not be able to realize all or a portion of our deferred tax assets in the future, we would reduce such amounts through a charge to income in the period in which that determination is made or when tax law changes are enacted.
In the ordinary course of business, there is inherent uncertainty in quantifying our income tax positions. We assess our income tax positions and record tax benefits for all years subject to examination based upon management’s evaluation of the facts, circumstances and information available at the reporting date. For those tax positions where it is more likely than not that a tax benefit will be sustained, we have recorded the largest amount of tax benefit with a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. For those income tax positions where it is not more likely than not that a tax benefit will be sustained, no tax benefit has been recognized in the consolidated financial statements. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations.
New Accounting Pronouncements
See Note 1 to our Consolidated Financial Statements set forth in Item 8 of this annual report for information regarding new accounting pronouncements.
Results of Operations
Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different years described below may be of limited utility due to the following: (i) our recent construction of new projects and enhancement of acquired projects; and (ii) fluctuation in revenues from our Products Segment. A number of operational issues in the first quarter of 2007 resulted in both reduced revenues and increased costs for the year ended December 31, 2007. Such operational issues are not expected to continue and are not, in our opinion, indicative of future trends.
Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006
Total Revenues
Total revenues for the year ended December 31, 2007 were $296.0 million, as compared with $268.9 million for the year ended December 31, 2006, which represented a 10.0% increase in total revenues. This increase is attributable both to our Electricity and Products Segments whose revenues increased by 10.5% and 8.8%, respectively, over the same period in 2006.
Electricity Segment
Revenues attributable to our Electricity Segment for the year ended December 31, 2007 were $216.0 million, as compared with $195.5 million for the year ended December 31, 2006, which represented a 10.5% increase in such revenues. This increase is mainly attributable to additional revenues of $17.1 million generated in the United States as a result of an increase in our generating capacity and energy generation in the United States from 1,789,794 MWh in the year ended December 31, 2006 to 1,994,263 MWh in the year ended December 31, 2007. This increase is mainly the result of additional generation from new power plants placed in service, the enhancements of
existing power plants and an increase in the energy rates in Standard Offer # 4 power purchase agreements payable by Southern California Edison. The increase also is partially attributable to a net increase of $3.4 million in revenues from our international plants as a result of revenues generated from our Amatitlan project in Guatemala, which started generating electricity in March 2007 and an increase in revenues generated from the Zunil project in Guatemala, which was consolidated as of March 13, 2006. The increase in revenues from our foreign projects was partially offset by a decrease of $3.6 million in revenues from our Momotombo project in Nicaragua as a result of a failure of turbines that we did not manufacture. The Momotombo power plant returned to full operation in November 2007.
Products Segment
Revenues attributable to our Products Segment for the year ended December 31, 2007 were $80.0 million, as compared with $73.5 million for the year ended December 31, 2006, which represented an 8.8% increase in such revenues. This increase of $6.5 million in the year ended December 31, 2007 is principally attributable to increased revenues of our recovered energy generation products.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2007 was $216.7 million, as compared with $175.6 million for the year ended December 31, 2006, which represented a 23.4% increase in total cost of revenues. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2007 was 73.2% compared with 65.3% for the year ended December 31, 2006. These increases are attributable to increased costs in both our Electricity and Products Segments, as discussed below, as well as the increase in revenues in both segments.
Electricity Segment
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2007 was $148.6 million, as compared with $124.4 million for the year ended December 31, 2006, which represented a 19.5% increase in total cost of revenues for such segment. This increase is primarily due to: (i) costs of $2.0 million related to a scheduled overhaul in the Heber 1 project (such an overhaul is performed once every four to five years); (ii) costs relating to new and enhanced projects placed into service; and (iii) an increase in labor and materials costs in existing plants. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2007 was 68.9% compared with 63.6% for the year ended December 31, 2006.
Products Segment
Total cost of revenues attributable to our Products Segment for the year ended December 31, 2007 was $68.0 million as compared with $51.2 million for the year ended December 31, 2006, which represented a 32.8% increase in total cost of revenues related to such segment. This increase is attributable to the increase in our Products Segment revenues, a different product mix, and an increase in labor, material, construction and transportation costs, which affected our margins in this segment. As a percentage of total Products Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2007 was 85.1% as compared with 69.7% for the year ended December 31, 2006.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2007 were $3.7 million, as compared with $3.0 million for the year ended December 31, 2006, which represented a 22.8% increase. Such $0.7 million increase reflects fluctuations in the timing in which actual expenses were incurred and is not indicative of a trend towards increased research and development expenses.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2007 were $10.6 million, as compared with $10.4 million for the year ended December 31, 2006, which represented a 2.7% increase. The increase was due primarily to an increase in salaries, offset partially by a decrease in selling and marketing costs relating to the Products Segment. Selling and marketing expenses for the year ended December 31, 2007 constituted 3.6% of total revenues for such period, as compared with 3.9% for the year ended December 31, 2006.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2007 were $21.4 million, as compared with $18.1 million for the year ended December 31, 2006, which represented an 18.4% increase. Such increase is attributable to an increase in personnel expenses and other administrative expenses as a result of hiring additional personnel in expectation of our future growth, and as a result of an increase in salaries. General and administrative expenses for the year ended December 31, 2007 increased to 7.2% of total revenues for such period, from 6.7% for the year ended December 31, 2006.
Operating Income
Operating income for the year ended December 31, 2007 was $43.5 million, as compared with $61.9 million for the year ended December 31, 2006. Such decrease in operating income was principally attributable to a $14.1 million decrease in gross margin primarily due to the increase in total cost of revenues as explained above, and an increase of $4.3 million in operating expenses. Operating income attributable to our Electricity Segment for the year ended December 31, 2007 was $43.7 million, as compared with operating income of $50.3 million for the year ended December 31, 2006. Operating loss attributable to our Products Segment for the year ended December 31, 2007 was $0.2 million, as compared with operating income of $11.6 million for the year ended December 31, 2006. The $11.8 million decrease in operating income in our Products Segment reflects the 32.8% increase in cost of revenues offsetting an 8.8% increase in revenues in that segment, both of which are explained above. We were unable to increase our revenues in the Products Segment enough to offset the increased costs because certain long-term supply agreements do not allow us to escalate project pricing to compensate for increased project costs.
Interest Expense
Interest expense for the year ended December 31, 2007 was $27.0 million, as compared with $31.0 million for the year ended December 31, 2006, which represented a 12.8% decrease. The $4.0 million decrease is primarily due to principal repayments. The decrease in interest expense was partially offset by a decrease of $1.2 million in interest capitalized to projects under construction.
Impairment of Auction Rate Securities
In the year ended December 31, 2007, we recorded $2.0 million of an impairment, as a result of an other-than-temporary decline in the value of certain auction rate securities.
Income Taxes
Income tax provision for the year ended December 31, 2007 was $1.8 million, as compared with $6.4 million for the year ended December 31, 2006. The effective tax rates for the years ended December 31, 2007 and 2006 were 8.9% and 17.1%, respectively. Our effective tax rate decreased in the year ended December 31, 2007 compared with the year ended December 31, 2006 due to the following: (i) an increase in production tax credits as a result of new power plants placed in service; (ii) a decrease of 2% in the tax rate in Israel commencing January 1, 2007; and (iii) a tax credit related to our subsidiaries in Guatemala.
Effective January 1, 2007, we adopted FIN No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. The impact on the income tax provision for the year ended December 31, 2007 resulting from the adoption of FIN No. 48 was $0.8 million.
Minority interest
Minority interest for the year ended December 31, 2007 includes income of $3.9 million from the sale of limited liability company interests in OPC LLC to institutional equity investors in June 2007. Minority interest for the year ended December 31, 2006 includes $0.8 million minority interest in earnings of the Zunil project.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2007 was $4.7 million, as compared with $4.1 million for the year ended December 31, 2006. On September 25, 2007, our equity investee, Ormat Leyte Co. Ltd. transferred its power plants to PNOC-Energy Development Corporation pursuant to a Build, Operate, and Transfer agreement. We did not incur any material financial loss as a result of such transfer, although going forward this will reduce our owned foreign generation capacity by 39 MW with a commensurate impact on equity in income of investees and net income.
Net Income
Net income for the year ended December 31, 2007 was $27.4 million, as compared with $34.4 million for the year ended December 31, 2006, a decrease of 20.5%. Such decrease in net income was principally attributable to an $18.5 million decrease in operating income as explained above. This was partially offset by a decrease in our income tax provision of $4.6 million, a $4.0 million decrease in interest expense, a $2.0 million impairment of auction rate securities and a $4.7 million increase in minority interest as described above. Net income for the year ended December 31, 2007 includes stock-based compensation related to stock options of $3.2 million as compared with $1.5 million for the year ended December 31, 2006.
Comparison of the Year Ended December 31, 2006 and the Year Ended December 31, 2005
Total Revenues
Total revenues for the year ended December 31, 2006 were $268.9 million, as compared with $238.0 million for the year ended December 31, 2005, which represented a 13.0% increase in total revenues. This increase is attributable both to our Electricity and Products Segments whose revenues increased by 10.2% and 21.2%, respectively, over the year ended December 31, 2005.
Electricity Segment
Revenues attributable to our Electricity Segment for the year ended December 31, 2006 were $195.5 million, as compared with $177.4 million for the year ended December 31, 2005, which represented a 10.2% increase in such revenues. This increase is primarily attributable to the following: (i) the consolidation of additional revenues in the amount of $10.3 million from the Zunil project, which was consolidated as of March 13, 2006; (ii) additional revenues of $5.9 million generated as a result of an increase in our generating capacity in the U.S. resulting in an increase in energy generation from 1,693,362 MWh in the year ended December 31, 2005 to 1,789,794 MWh in the year ended December 31 2006; and (iii) an increase of $1.3 million in lease income resulting from the Puna operating lease. We did not realize the aggregate generating capacity of our power plants in the year ended December 31, 2006 due to unexpected operational issues that we experienced in some of our plants, such as the Puna and Ormesa projects, and the delay in the commercial operation of the Desert Peak 2 plant.
Products Segment
Revenues attributable to our Products Segment for the year ended December 31, 2006 were $73.5 million, as compared with $60.6 million for the year ended December 31, 2005, which represented a 21.2% increase. This increase of $12.9 million in the year ended December 31, 2006 is
principally attributable to increased sales of our geothermal and recovered energy generation products, which amounted to $68.8 million in the year ended December 31, 2006 as compared to $31.6 million, while sales of our remote power units decreased in the year ended December 31, 2006 following the completion of the large order received from the company developing the Sakhalin project in Russia which amounted to $18.9 million.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2006 was $175.6 million, as compared with $148.9 million for the year ended December 31, 2005, which represented an 18.0% increase in total cost of revenues. The increase in cost of revenues is partially due to the increase in revenues and partially attributable to increased costs in our Electricity Segment during the year ended December 31, 2006, as discussed below. As a percentage of total revenues, our total cost of revenues for the years ended December 31, 2006 and 2005 were 65.3% and 62.5%, respectively. The increase in cost of revenues as a percentage of total revenues is principally attributable to the increased costs in our Electricity Segment during the year ended December 31, 2006, which was partially offset by an increase in the profitability of our Products Segment during the year ended December 31, 2006. Total cost of revenues for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.8 million.
Electricity Segment
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2006 was $124.4 million, as compared with $103.6 million for the year ended December 31, 2005, which represented a 20.0% increase in cost of revenues for such segment. This increase is primarily due to the following: (i) a $4.1 million cost of repairing two wells that experienced mechanical problems in the Puna project (we have incurred approximately $2.0 million in additional repair costs in the first quarter of 2007); (ii) an increase of $5.8 million in depreciation and royalties as a result of additional generating capacity; (iii) an increase of $2.7 million in cost of revenues attributable to the Zunil project which was consolidated as of March 13, 2006; (iv) an increase in lease expense of $2.2 million resulting from the Puna operating lease; and (v) additional insurance costs of $1.9 million due to higher insurance premiums and additional premiums as a result of coverage of our additional assets. The remaining $4.1 million of the increase in our cost of revenues is attributable primarily to increased labor and materials costs in existing plants. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2006 was 63.6% compared with 58.4% for the year ended December 31, 2005.
Products Segment
Total cost of revenues attributable to our Products Segment for the year ended December 31, 2006 was $51.2 million, as compared with $45.2 million for the year ended December 31, 2005, which represented a 13.2% increase in total cost of revenues related to such segment. Such $6.0 million increase in total cost of revenues during the year ended December 31, 2006 is attributable to the increase in our Products Segment revenues and a different product mix. As a percentage of total products revenues, our total cost of revenues attributable to our Products Segment for the year ended December 31, 2006 was 69.7% compared with 74.6% in the year ended December 31, 2005. Such 4.9% decrease was primarily attributable to the product mix.
Research and Development Expenses
Net research and development expenses for the year ended December 31, 2006 were $2.98 million, as compared with $3.04 million for the year ended December 31, 2005, which represented a 1.7% decrease in research and development expenses. Such decrease reflects fluctuations in the period in which actual expenses were incurred. Research and development expenses in the years ended December 31, 2006 and 2005 also include activity related to geothermal resource drillings. Grants received from the U.S. Department of Energy are offset against the related research and development expenses. Such grants amounted to $0.3 million and $1.3 million during the years ended December 31, 2006 and 2005, respectively.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2006 were $10.4 million, as compared with $7.9 million for the year ended December 31, 2005, which represented a 31.6% increase in selling and marketing expenses. The increase was due primarily to the increase in revenues in our Products Segment and an increase in personnel expenses and other administrative expenses as a result of the hiring of additional personnel to support our continued growth, and an increase in salaries. Selling and marketing expenses for the year ended December 31, 2006 constituted 3.9% of total revenues for such year, as compared with 3.3% for the year ended December 31, 2005. Such increase is principally attributable to an increase in personnel expenses and other administrative expenses, as described above, offset by the fixed cost nature of certain of our selling and marketing expenses against a larger total revenue base. Selling and marketing expenses for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.3 million.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2006 were $18.1 million, as compared with $14.3 million for the year ended December 31, 2005, which represented a 26.4% increase in general and administrative expenses. Such increase was primarily attributable to: (i) an increase in professional services fees, additional personnel expenses and other administrative expenses, all as a result of our initial implementation of internal controls and procedures required to comply with Section 404 of the Sarbanes-Oxley Act of 2002; (ii) an increase in personnel expenses and other administrative expenses as a result of the hiring of additional personnel to support our continued growth and as a result of an increase in salaries; and (iii) an increase in insurance expenses of $0.6 million mainly related to political risk coverage of the Amatitlan project, which was under construction. General and administrative expenses for the year ended December 31, 2006 increased to 6.7% of total revenues for such period, from 6.0% for the year ended December 31, 2005. General and administrative expenses for the year ended December 31, 2006 includes stock-based compensation related to stock options of $0.6 million.
Operating Income
Operating income for the year ended December 31, 2006 was $61.9 million, as compared with operating income of $63.9 million for the year ended December 31, 2005. Such decrease in operating income was principally attributable to an increase of $6.2 million in operating expenses, offset by a $4.2 million increase in gross margin. Operating income attributable to our Electricity Segment for the year ended December 31, 2006 was $50.3 million, as compared with $56.8 million for the year ended December 31, 2005. Operating income attributable to our Products Segment for the year ended December 31, 2006 was $11.6 million, as compared with $7.1 million for the year ended December 31, 2005.
Interest Expense
Interest expense for the year ended December 31, 2006 was $31.0 million, as compared with $55.3 million for the year ended December 31, 2005, which represented a 44.0% decrease in such interest expense. The net decrease of $24.3 million was primarily due to a $16.6 million one-time charge relating to the early repayment of the Beal Bank loan, following the issuance of the OrCal Senior Secured Notes on December 8, 2005. Without the impact of the one-time charge, interest expense decreased by $7.7 million, which resulted from: (i) an increase of $4.6 million in interest capitalized to projects due to the higher volume of construction in this year compared with last year; (ii) a decrease of $2.3 million in interest expense to our parent; (iii) a decrease of $2.9 million in interest expense due to the refinancing of the Beal Bank loan with the OrCal Senior Secured Notes at a lower interest rate as described above; and (iv) a decrease of $0.6 million in interest expense in respect of the OFC Senior Secured Notes due to principal repayments. The decrease in interest expense was partially offset by an increase of $1.8 million in interest expense for the year ended December 31, 2006 attributable to the consolidation of interest expense from the Zunil project, which
was consolidated as of March 13, 2006, and by a decrease of $0.6 million for the year ended December 31, 2006, in the fair value of interest rate caps, which as of December 8, 2005 are no longer qualified for hedge accounting due to the repayment of the Beal Bank loan.
Income Taxes
Income taxes for the year ended December 31, 2006 were $6.4 million, as compared with $4.7 million for the year ended December 31, 2005. The effective tax rates for the years ended December 31, 2006 and 2005 were 17.1% and 36.2%, respectively. Our effective tax rate decreased in the year ended December 31, 2006 compared with the year ended December 31, 2005 due to: (i) a production tax credit of $4.7 million in respect of our Burdette, Gould and Desert Peak 2 projects; (ii) the absence of income tax expense in respect of our Zunil project, due to our utilization of a tax credit in the amount of $1.1 million; (iii) a decrease of 3% in the tax rate in Israel commencing January 1, 2006, which decreased the tax provision by $0.5 million; and (iv) an Israeli Investment Law amendment and the resulting ruling from the Israeli Tax Authorities granted in April 2006 to Ormat Systems according to which Ormat Systems was subject to lower income tax rates effective as of January 1, 2004, which resulted in a tax benefit of $1.0 million.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2006 was $4.1 million, as compared with $6.9 million for the year ended December 31, 2005. Such decrease of $2.8 million was due to our 50% equity interest in the Mammoth project, whose revenues decreased because of lower generation as a result of temperatures higher than the average for the summer season and whose cost of revenues increased mainly as a result of unplanned major maintenance. In addition, the decrease in our equity in income of investees was attributable to the shutdown of the Zunil project in the first quarter of 2006, due to damage from a hurricane and the consolidation of Orzunil as of March 13, 2006, which decreased our equity income of investees by $0.7 million.
Net Income
Net income for the year ended December 31, 2006 was $34.4 million, as compared with $15.2 million for the year ended December 31, 2005, which represented an increase of 127.0% in our net income. Net income as a percentage of our total revenues for the year ended December 31, 2006 was 12.8%, as compared with 6.4% for the year ended December 31, 2005. Such increase in net income was principally attributable to: (i) a $16.6 million ($10.3 million after-tax) impact of the one-time charge from the repayment of the Beal Bank loan in the year ended December 31, 2005; (ii) a $4.2 million increase in gross margin primarily due to the increase in total revenues; and (iii) a decrease in our net interest expense of $10.0 million, offset by: (i) a decrease of $2.8 million in equity in income of investees; (ii) a $6.2 million increase in operating expenses; (iii) a $1.7 million increase in our income tax provision; and (iv) a $0.8 increase in minority interest in earnings of subsidiaries, due to the consolidation of the Zunil project. Net income for the year ended December 31, 2006 includes stock-based compensation related to stock options of $1.5 million.
Stock-based Compensation
Effective January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payments, (SFAS No. 123R), which establishes the accounting for employee stock-based awards. Under the provisions of SFAS No. 123R, stock-based compensation is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). We adopted SFAS No. 123R using the modified prospective method. Under this method, prior periods are not restated and the amount of compensation cost recognized includes (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation, and
(ii) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. Prior to January 1, 2006, we accounted for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25 (APB No. 25), Accounting for Stock Issued to Employees, and related interpretations. Under APB No. 25, compensation cost was recognized based on the difference, if any, on the date of grant between the fair value of our common stock and the amount an employee must pay to acquire the stock.
During the year ended December 31, 2007 and 2006, we recognized net stock-based compensation expenses related to stock options of $3.2 million and $1.5 million, respectively. As of December 31, 2007, the unrecorded deferred stock-based compensation balance related to stock options was $6.9 million and will be recognized over an estimated weighted average amortization period of 1.4 years.
Liquidity and Capital Resources
Our principal sources of liquidity have been derived from cash from operations, proceeds from parent company loans, third party debt in the form of borrowing under credit facilities, issuance by Ormat Funding and OrCal Geothermal of their Senior Secured Notes, project financing (including the Puna lease and the OPC Tax Monetization transaction described below) and the issuance of our common stock in public and private offerings. We have utilized this cash to fund our acquisitions, develop and construct power generation plants and meet our other cash and liquidity needs.
As of December 31, 2007, we have access to the following sources of funds: (i) $60.7 million in cash, cash equivalents and short-term marketable securities; and (ii) $110.0 million of corporate borrowing capacity under existing lines of credit with different commercial banks.
Our estimated capital needs for 2008 include approximately $447.0 million for capital expenditures on new projects in development or construction, exploration activity, operating projects, and machinery and equipment, as well as $65.8 million for debt repayment (including to our parent).
We expect to finance these requirements with the funds described above, $33.3 million of proceeds from the sale of common stock to our parent described below, additional proceeds of approximately $46.6 million which we will receive in the first half of 2008 from the second closing of the OPC Tax Monetization Transaction, and from cash flows from our operations, as well as with additional borrowing capacity under future line of credit with commercial banks that are under negotiations, future project financing and refinancing, and future tax monetization transactions. Our management believes that these sources will address our anticipated liquidity, capital expenditures and other investment requirements. Our shelf registration statement on Form S-3, which was declared effective on January 31, 2006, provides us with the ability to raise additional capital of up to $623 million through the issuance of securities.
As described in ‘‘Recent Developments’’, on October 26, 2007, we completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under our shelf registration statement filed in early 2006, and on the same date we completed an unregistered sale of 381,254 shares of common stock to our parent, Ormat Industries Ltd., at a price of $45.90 per share. Net proceeds from both sales to us, after deducting underwriting fees and commissions and estimated offering expenses associated with the offering, were approximately $154.7 million. A portion of the proceeds from the block trade and the unregistered sale of shares was used to repay a capital note owed to our parent in the amount of $50.7 million on December 3, 2007 (See ‘‘Loan Agreements with our Parent’’). As further described in ‘‘Recent Developments’’, on January 8, 2008, we completed an unregistered sale of an additional 693,750 shares of common stock to our parent at a price of $48.02 per share. The proceeds from this unregistered sale were approximately $33.3 million. The proceeds from this sale will be used for general corporate purposes, which may include construction of geothermal and recovered energy generation power plants and other investments and financing activities.
Loan Agreements with our Parent
In 2003, we entered into a loan agreement with Ormat Industries Ltd. (our parent company), which was further amended on September 20, 2004. Pursuant to this loan agreement, Ormat Industries agreed to make a loan to us in one or more advances not exceeding a total aggregate amount of $150.0 million. The proceeds of the loan are to be used to fund our general corporate activities and investments. We are required to repay the loan and accrued interest in full and in accordance with an agreed-upon repayment schedule and in any event on or prior to June 5, 2010. Interest on the loan is calculated on the balance from the date of the receipt of each advance until the date of payment thereof at a fixed rate of 7.5% per annum. All computations of interest shall be made by Ormat Industries on the basis of a year consisting of 360 days. As of December 31, 2007, the outstanding balance of the loan was approximately $57.8 million compared to $89.5 million as of December 31, 2006.
In addition to the above loan, pursuant to the terms of a capital note, as amended on September 20, 2004, Ormat Industries converted outstanding balances owed by us to Ormat Industries into a subordinated non-interest bearing loan in an amount equal to New Israeli Shekels (NIS) 240.0 million (equivalent to $50.7 million as of December 31, 2006). Since the note was payable upon demand at any time after November 30, 2007, it was presented in our consolidated balance sheet as of December 31, 2006 in current liabilities. On December 3, 2007, the loan was repaid (See ‘‘Recent Developments’’).
Third Party Debt
Our third-party debt is composed of two principal categories. The first category consists of project finance debt or acquisition financing that we or our subsidiaries have incurred for the purpose of developing and constructing, refinancing or acquiring our various projects, which are described under the heading ‘‘Non-Recourse and Limited-Recourse Third Party Debt’’. The second category consists of debt incurred by us or our subsidiaries for general corporate purposes, which are described under the heading ‘‘Full-Recourse Third Party Debt’’.
Non-Recourse and Limited-Recourse Third Party Debt
OrCal Geothermal Senior Secured Notes - Non-Recourse
On December 8, 2005, OrCal Geothermal Inc. (OrCal), one of our subsidiaries, issued $165.0 million, 6.21% Senior Secured Notes (OrCal Senior Secured Notes) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Heber projects. The OrCal Senior Secured Notes have been rated BBB− by Fitch. The OrCal Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments that commenced on June 30, 2006. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. As of December 31, 2007, we were in compliance with the covenants under the OrCal Senior Secured Notes. As of December 31, 2007, there were $134.5 million of OrCal Senior Secured Notes outstanding. The proceeds from this issuance were used to prepay in full OrCal’s previously outstanding loan with Beal Bank and to pay for transaction costs. As a result of the prepayment of the Beal Bank loan, we recorded in the fourth quarter of 2005 a net charge of approximately $10.3 million, net of related taxes of approximately $6.3 million.
Ormat Funding Senior Secured Notes - Non-Recourse
On February 13, 2004, Ormat Funding Corp. (OFC), one of our subsidiaries, issued $190.0 million, 8¼% Senior Secured Notes (OFC Senior Secured Notes) in an offering subject to Rule
144A and Regulation S of the Securities Act of 1933, as amended, for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1/1A projects, and the financing of the acquisition cost of the Steamboat 2/3 project. The OFC Senior Secured Notes have a final maturity date of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments which commenced on June 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. As of December 31, 2007, we were in compliance with the covenants under the OFC Senior Secured Notes. As of December 31, 2007, there were $164.9 million of OFC Senior Secured Notes outstanding.
On May 31, 2007, OFC successfully consummated a consent solicitation, which was launched on May 16, 2007, relating to the OFC Senior Secured Notes. The Consent Solicitation was conducted in order to amend and/or waive certain provisions of the indenture such that our shut down and decommissioning of the Desert Peak 1 plant and the related termination of the fluid supply agreement pursuant to which geothermal resource was supplied to that plant (both of which constituted assets pledged to the Noteholders to secure repayment of the OFC Senior Secured Notes) would not constitute defaults or events of default under the indenture.
Senior Loans from International Finance Corporation (IFC) and Commonwealth Development
Corporation (CDC) - Non-Recourse
Orzunil I de Electricidad, Limitada (Orzunil), a wholly owned subsidiary in Guatemala, has senior loan agreements with IFC and CDC. The first loan from IFC, under which $5.9 million was outstanding as of December 31, 2007, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. The second loan from IFC, under which $1.4 million was outstanding as of December 31, 2007, has a fixed annual interest rate of 11.730%, and matures on May 15, 2008. The loan from CDC, under which $6.6 million was outstanding as of December 31, 2007, has a fixed annual interest rate of 10.300%, and matures on August 15, 2010. There are various restrictive covenants under these senior loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of December 31, 2007, Orzunil was in compliance with the covenants under these senior loans.
Credit Facility Agreement (The Momotombo project) - Limited Recourse
Ormat Momotombo Power Company (Momotombo), a wholly owned subsidiary in Nicaragua, has a loan agreement with Bank Hapoalim, under which $8.4 million was outstanding as of December 31, 2007, bearing an interest rate of 3-month LIBOR plus 2.375% per annum on tranche one of the loan and 3-month LIBOR plus 3.0% per annum on tranche two of the loan. Tranche one of the loan matures on September 5, 2010, and is payable in 32 quarterly installments of $298,000 each, and tranche two of the loan matures on December 5, 2010, and is payable in 28 quarterly installments of $424,000 each. There are various restrictive covenants under this loan, which include limitations on Momotombo’s ability to make distributions to its shareholders.
Due to a failure of a turbine that was not manufactured by Ormat, the Momotombo Project had not been in full operation from June 2007 through October 2007. As a result, Momotombo did not meet the ‘‘debt service coverage ratio’’ required at December 31, 2007, and therefore, distributions from the Project are restricted. The turbine has been repaired and the power plant returned to full operation in November 2007.
In October 2007, Momotombo reached an agreement with Bank Hapoalim, pursuant to which Bank Hapoalim allowed Momotombo to use the funds in the ‘‘Debt Service Reserve Account’’ for the repair of the damaged turbine. As a result, Momotombo does not comply with the required ‘‘Debt Service Reserve Account’’. In accordance with the terms of the credit facility, Momotombo has a 180-day period to replenish the ‘‘Debt Service Reserve Account’’. On February 24, 2008, Bank Hapoalim granted Momotombo an extension to replenish the ‘‘Debt Service Reserve Account’’ until August 31, 2009. As the power plant recently returned to full operation, we believe that Momotombo will comply with the ‘‘Debt Service Reserve Account’’ covenant before August 31, 2009.
New Financing of our Projects
Financing of the Amatitlan Project
We intend to refinance our equity investment in the construction cost of the Amatitlan project. We terminated the exclusivity of the mandate letter with the local bank in Guatemala and are currently in discussions with other financial institutions.
Financing of Phase II of Olkaria III Project
We have engaged a financial institution that is leading a syndicate for the purpose of arranging long-term financing for the Olkaria III project. The syndicate is in the process of conducting due diligence related to the potential financing. We expect negotiations and preparation of loan documentation to follow shortly.
Full-Recourse Third Party Debt
Our full-recourse third party debt includes an $8.0 million medium term loan from Bank Hapoalim, under which $1.0 million was outstanding as of December 31, 2007, bearing an interest rate of 12-month LIBOR plus 1.7% per annum.
In connection with our acquisition through our Israeli subsidiary, Ormat Systems Ltd. (Ormat Systems) of the power generation business from our parent and in connection with obtaining lines of credit, we entered into certain agreements with various commercial banks. 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 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 have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. We do not expect that these covenants or ratios, which apply to us on a consolidated basis, will materially limit our ability to execute our future business plans or our operations. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.
We do not expect that any third party debt that we, or any of our subsidiaries, will incur in the future will be guaranteed by our parent.
Most of the loan agreements to which we or our subsidiaries are a party contain cross-default provisions with respect to other material indebtedness owed by us to any third party.
On February 15, 2006, our subsidiary, Ormat Nevada Inc. (Ormat Nevada), entered into a $25.0 million credit agreement with Union Bank of California (UBOC). Under the credit agreement, Ormat Nevada can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. UBOC is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, we have entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which we agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets.
Loans and draws under the letters of credit (if any) under the credit agreement will bear interest at the floating rate based on the Eurodollar plus a margin. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios.
As of December 31, 2007, three letters of credit, with an aggregate stated amount of $12.3 million, have been issued and are outstanding under this credit agreement with UBOC.
In 2007, we entered into credit agreements with three commercial banks in the aggregate amount of $110 million. Under these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Each of the credit agreements has a term of three years.
Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin. Our (or Ormat Systems’) obligations under the credit agreements are unsecured, but we are subject to a negative pledge in favor of the banks and certain other customary restrictive covenants.
As of December 31, 2007 and as of the date of this report, no loans or letters of credits were outstanding under such credit agreements.
Our management believes that we are currently in compliance with our covenants with respect to our third-party debt, except as described above regarding the Bank Hapoalim loan.
Letters of Credit
As described above under ‘‘Full Recourse Third Party Debt’’, on February 15, 2006, our subsidiary Ormat Nevada entered into a credit agreement with Union Bank of California and in September 2007 and November 2007 we entered into credit agreements with three commercial banks.
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 Leumi and Bank Hapoalim have issued such performance letters of credit in favor of our customers from time to time. As of December 31, 2007, Bank Leumi and Bank Hapoalim have agreed to make available to us letters of credit totaling $8.5 million and $22.9 million, respectively. As of such date, Bank Leumi and Bank Hapoalim have issued letters of credit in the amount of $8.5 million and $13.0 million, respectively.
As of the date hereof, we have not had a draw presented against any letter of credit issued or provided on our behalf.
Puna Project Lease Transactions
On May 19, 2005, our subsidiary in Hawaii, Puna Geothermal Ventures (PGV), entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii. The transaction was concluded with financing parties by means of a leveraged lease transaction. A secondary stage of the lease transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005. Pursuant to a 31-year head lease, PGV leased its geothermal power plant to the abovementioned financing parties in return for a deferred lease income in the amount of $83.0 million.
OPC Tax Monetization Transaction
On June 7, 2007, a wholly owned subsidiary of the Company, Ormat Nevada, concluded a transaction to monetize production tax credits and other favorable tax attributes, such as accelerated depreciation, generated from certain of its geothermal power projects. Pursuant to the transaction, affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. became institutional equity investors in a newly formed subsidiary of Ormat Nevada. The projects involved in the transaction include Desert Peak 2, Steamboat Hills, and Galena 2, all located in Nevada.
Under the transaction structure, Ormat Nevada transferred the aforementioned geothermal power projects to the newly formed subsidiary, OPC LLC (OPC), and sold limited liability company interests in OPC to the institutional equity investors for $71.8 million. Ormat Nevada will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until it recovers the capital that it has invested in the projects, while the institutional equity investors will receive substantially all of the production tax credits and the taxable income or loss, and the distributable cash flow after Ormat Nevada has recovered its capital. The institutional equity investor’s return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the Flip Date), Ormat Nevada will receive 95% of both distributable cash and taxable income and the investors will receive 5% of both distributable cash and taxable income on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the projects. The transaction provides for a second closing whereby Ormat Nevada would contribute another geothermal plant currently under construction and receive an additional amount of $46.6 million.
Liquidity Impact of Uncertain Tax positions
As discussed in Note 15 to our Consolidated Financial Statements set forth in Item 8 of this annual report, we have a liability associated with unrecognized tax benefits and related interest and penalties in the amount of $5.3 million as of December 31, 2007. This liability is included in long-term liabilities in our consolidated balance sheet, because we generally do not anticipate that settlement of the liability will require payment of cash within the next twelve months. We are not able to reasonably estimate when we will make any cash payments required to settle this liability, but do not believe that the ultimate settlement of our obligations will materially effect our liquidity.
Dividend
The following are the dividends we declared during the past two years:
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, 2007
Net cash provided by operating activities for the year ended December 31, 2007 was $58.7 million, as compared with $73.0 million for the year ended December 31, 2006. Such net decrease of $14.3 million resulted primarily from the decrease in net income from $34.4 million in the year ended December 31, 2006 to $27.4 million in the year ended December 31, 2007, mainly as a result of the decrease in gross margin, as described above and a decrease of $12.2 million in accounts payable as compared to an increase of $12.1 million in the year ended December 31, 2006.
Net cash used in investing activities for the year ended December 31, 2007 was $116.3 million, as compared with $249.1 million for the year ended December 31, 2006. The principal factors that affected our cash flows used in investing activities during the year ended December 31, 2007 were capital expenditures of $216.4 million primarily for our facilities under construction, offset by a $79.7 million decrease in marketable securities.
Net cash provided by financing activities for the year ended December 31, 2007 was $84.6 million, as compared with $169.4 million for the year ended December 31, 2006. The principal factors that affected the cash flows provided by financing activities during the year ended December 31, 2007 were the receipt of net proceeds of $137.2 million from our sale of shares in a block trade, the $17.5 million net proceeds from our sale of 381,254 shares to our parent, and the net proceeds of $69.2 million from the sale of OPC interests, net of transaction costs, relating to the OPC Tax Monetization transaction, offset by: (i) the repayment of short-term and long-term debt in the amount of $49.5 million; (ii) the repayment of debt to our parent (including the $50.7 million capital note on December 3, 2007, as described above) in the total amount of $82.3 million; and (iii) the payment of a dividend to our shareholders in the amount of $8.6 million.
For the Year Ended December 31, 2006
Net cash provided by operating activities for the year ended December 31, 2006 was $73.0 million, as compared with net cash provided by operating activities of $134.9 million for the year ended December 31, 2005. Such net decrease of $61.9 million resulted primarily from: (i) the increase in net income from $15.2 million to $34.4 million as a result of additional revenues being generated from the increase of our generating capacity in the United States and from the Zunil project which was consolidated as of March 13, 2006; (ii) the prepaid lease payment of $83.0 million in the year ended December 31, 2005 pursuant to the leverage lease transaction of the Puna project (less $3.3 million deferred costs related to such lease transaction); and (iii) an increase of $12.1 million in accounts payable and accrued expenses for the year ended December 31, 2006 as compared with an increase of $7.2 million for the year ended December 31, 2005 mainly due to interest accrued on the OFC and OrCal Senior Secured Notes (which was paid on January 2, 2007), offset by a decrease in trade payables as a result of the timing of payments to suppliers and service providers.
Net cash used in investing activities for the year ended December 31, 2006 was $249.1 million, as compared with $83.4 million used in investing activities for the year ended December 31, 2005. The principal factors that affected our cash flow used in investing activities during the year ended December 31, 2006 were: (i) capital expenditures of $159.5 million utilized primarily for our power facilities under construction; (ii) $22.8 million used in the acquisition of an additional 79% of the Zunil project in Guatemala; and (iii) a net increase of $52.7 million in our investment of excess cash in marketable securities.
Net cash provided by financing activities for the year ended December 31, 2006 was $169.4 million, as compared with $61.3 million used in financing activities for the year ended December 31, 2005. The principal factors that affected the cash flow used in financing activities during the year ended December 31, 2006 were the receipt of proceeds from the follow-on offering of $135.1 million and the $92.4 million net proceeds from our sale of shares in a block trade, offset by: (i) the repayment of short-term and long-term debt in the amount of $20.7 million, (ii) the repayment of debt to our parent in the amount of $31.6 million; and (iii) the payment of a dividend to our shareholders in the amount of $5.2 million.
Capital Expenditures
Our capital expenditures primarily relate to two principal components: the enhancement of our existing power plants and the construction and development of new power plants. We expect that the following enhancements of our existing power plants and the construction of new power plants will be funded initially from internally generated cash or other available corporate resources, which we expect to subsequently refinance with limited or non-recourse debt at the project level. We currently do not contemplate obtaining any new loans from our parent company.
Phase II of Olkaria III Project. In connection with Phase II of the Olkaria III 35 MW project, we have completed the drilling of the wells and the majority of the power plant equipment is on site.
Puna Project. An enhancement program for the Puna project is currently planned and is intended to increase the output of the project by an estimated 8 MW through the construction of OEC units. We expect that such enhancement program will be completed in 2009. We have not yet entered into a power purchase agreement for the supply of energy from this planned addition.
Heber South Project. We completed the construction of the 10 MW Heber South project, which is located in the Heber known geothermal resource area. This project is now in the commissioning phase. The construction activity included the drilling of production and injection wells and the construction of an OEC unit. We expect to declare commercial operation in the first quarter of 2008.
North Brawley Project. The construction of the North Brawley project is currently under way. Once completed, it will deliver approximately 50 MW of power generation under an existing power purchase agreement with Southern California Edison. Drilling started in February 2007. Construction work is at an advanced stage and the key power plant equipment has arrived at the site. We expect the construction to be completed by the end of 2008.
OREG 2 Project. In connection with the OREG 2 recovered energy project, we plan to construct four power plants along the Northern Border natural gas pipeline. Each of the four facilities will have a net capacity of 5.5 MW. These facilities are scheduled to be completed during 2009.
Peetz Project. In connection with the Peetz recovered energy project, we are currently manufacturing the equipment required for use in the 4 MW power plant along a natural gas pipeline near Denver, Colorado. The facility is scheduled to be commissioned in mid-2009.
GDL project. We are constructing a 10 MW power plant, located in the Kawerau, New Zealand. We have a 49% ownership interest in the project and have an option to acquire the remaining 51% before the completion of construction. Completion of this project is expected for late 2008 or early 2009.
East Brawley. We plan to construct and have begun manufacturing equipment for an additional 50 MW power plant, in the Brawley known geothermal resource area in Imperial County, California, adjacent to the North Brawley project. Completion of the project is projected for the end of 2009.
We have budgeted approximately $641 million for the above-described projects and have invested approximately $151 million of such budget as of December 31, 2007 and expect to invest approximately $345 million in 2008.
In addition to the above projects, our operating projects have capital expenditure requirements for 2008 of approximately $31 million. We plan to start other construction and enhancement of additional projects, including exploration work, for a total investment amount of approximately $61 million for 2008 and 2009, and we also plan to invest approximately $17 million in machinery and equipment, including drilling equipment in 2008.
We do not anticipate material capital expenditures in the near term for any of our operating projects, other than those described above and other than new projects beyond 2008.
Exposure to Market Risks
One market risk to which power plants are typically exposed is the volatility of electricity prices. However, our exposure to such market risk is currently limited because our long-term power purchase
agreements have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. However, beginning in May 2012, the energy payments under the power purchase agreements of the Heber 1 and 2 projects, the Ormesa project and the Mammoth project will be determined by reference to the relevant power purchaser’s short run avoided costs. The Puna project is currently benefiting from energy prices which are higher than the floor under the Puna power purchase agreement, as a result of the high fuel costs that impact Hawaii Electric Light Company’s avoided costs. In addition, under certain of the power purchase agreements for our projects in Nevada, the price that Sierra Pacific Power Company pays for energy and capacity is based upon California-Oregon border power market pricing.
As of December 31, 2007, 97.5% of our consolidated long-term debt (including amounts owed to our parent) was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 2.5% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of December 31, 2007, $9.4 million of our debt remained subject to some floating rate risk. As such, our exposure to changes in interest rates with respect to our long-term obligations is immaterial.
We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities, commercial paper and auction rate securities (with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services).
We account for our investment in marketable securities in accordance with SFAS No. 115, Accounting for Investments in Debt and Equity Securities. All of our investments in marketable securities (including marketable securities which are part of restricted cash accounts) are treated as ‘‘available-for-sale’’ under SFAS No.115. Our marketable securities include auction rate securities and commercial paper.
Our cash equivalents and our portfolio of marketable securities are subject to market risk due to changes in interest rates. Fixed rate securities may have their market value adversely impacted due to a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. Due in part to these factors, our future investment income may fall short of expectation due to changes in interest rates or we may suffer losses in principal if we are forced to sell securities that decline in market value due to changes in interest rates. However because we classify our debt securities as ‘‘available-for-sale’’, no gains or losses are recognized due to changes in interest rates unless such securities are sold prior to maturity or declines in fair value are determined to be other-than-temporary. Should interest rates fluctuate by 10 percent, the value of our marketable securities as of December 31, 2007 would not have changed significantly, since most of our investment in marketable securities are short-term or bearing variable interest rates, but our interest income would have changed by approximately $0.2 million for the year ended December 31, 2007.
Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days but with contractual maturities that can be well in excess of ten years. At the end of each reset period, which depending on the security can occur on a daily, weekly, or monthly basis, investors can sell or continue to hold the securities at par. These securities are subject to fluctuations in fair value depending on the supply and demand at each auction.
In the fourth quarter of 2007, certain auction rate securities failed auction due to sell orders exceeding buy orders. While we continue to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximates par value. We concluded that the fair value of these auction rate securities at December 31, 2007 was $8.4 million, a decline of $2.8 million from par value of $11.2 million. Of this amount $0.8 million was deemed temporary as we believe the decline in market value is due to general market conditions. Based upon our evaluation of available information, we believe these investments generally are of high credit quality, as substantially all of the investments carry a AA credit rating and higher. In addition, we currently have the intent and ability to hold these investments until anticipated recovery in market value occurs. Accordingly, we have recorded an unrealized loss on these securities of $0.8 million in other comprehensive loss. We concluded that $2.0 million of the decline was
other-than-temporary and recorded an impairment charge. Our conclusion for the other than temporary impairment is based on the significant decline in fair value indicated for a certain investment.
Another market risk to which we are exposed is primarily related to potential adverse changes in foreign currency exchange rates, in particular the fluctuation of the U.S. dollar versus the New Israeli Shekel (NIS). Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrows funds or incurs operating or other expenses in one type of currency but receives revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary, or increase such subsidiary’s overall expenses. Risks attributable to fluctuations in foreign currency exchange rates can also arise when the currency denomination of a particular contract is not the U.S. dollar. All of our power purchase agreements in the international markets are either U.S. dollar-denominated or linked to the U.S. dollar. Our construction contracts from time to time contemplate costs which are incurred in local currencies. The way we often mitigate such risk is to receive part of the proceeds from the sale contract in the currency in which the expenses are incurred. In the past, we have not used any material foreign currency exchange contracts or other derivative instruments to reduce our exposure to this risk. In the future, we may use such foreign currency exchange contracts and other derivative instruments to reduce our foreign currency exposure to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.
Effects of Inflation
We do not expect that the low inflation environment of recent years in most of the countries in which we operate will continue. To address rising inflation, some of our contracts include certain mitigating factors against any inflation risk. In connection with the Electricity Segment, inflation may directly impact an expense incurred for the operation of our projects, hence increasing the overall operating cost to us. The negative impact of inflation may be partially offset by price adjustments built into some of our power purchase agreements that could be triggered upon such occurrences. Energy payments pursuant to the power purchase agreements for the Mammoth project (after April 2012), Ormesa project (after April 2012), Heber 1 and 2 projects (after April 2012) and Steamboat 1/1A project will change because of our power purchasers’ underlying short run avoided costs. To the extent that inflation causes an increase in those short run avoided costs, higher energy payments could have an offsetting impact to any inflation-driven increase in our expenses. Similarly, the energy payments pursuant to the power purchase agreements for the Brady project, Steamboat 2/3 project, the Steamboat Hills project and the Burdette project increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation.
Overall, we believe that the impact of inflation on our business will not be significant.
Contractual Obligations and Commercial Commitments
The following table sets forth our material contractual obligations as of December 31, 2007, excluding interest (in thousands):
The following table sets forth our interest payments payable in connection with our contractual obligations as of December 31, 2007 (in thousands):
Interest on the OFC Senior Secured Notes due in 2020 is fixed at a rate of 8.25%. Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the Orzunil Senior Loans due in 2008, 2010 and 2011 is fixed at rates of 11.730%, 10.300% and 11.775%, respectively. Interest on the Ormat Industries notes is fixed at the rate of 7.50%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates). Accordingly, for purposes of the above calculation of interest payments pertaining to variable rate debt, the methodology used to determine future LIBOR rates was the use of Constant Maturity Swaps.
The following table sets forth our future minimum lease payments under the Puna project’s lease, as of December 31, 2007 (in thousands):
The following table sets forth our future payment of benefits to our employees in Israel upon their reaching normal retirement age, as of December 31, 2007 (in thousands):
The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with us before reaching their normal retirement age.
We purchase raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, we enter into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by us, or that establish parameters defining the our requirements. At December 31, 2007, total obligations related to such supplier agreements were approximately $131.9 million (out of which approximately $118.8 million relate to construction-in-process). All such obligations are payable in 2008.
The above tables do not reflect unrecognized tax benefits of $5,330,000, the timing of which is uncertain. Refer to Note 15 to our Consolidated Financial Statements set forth in Item 8 of this annual report for additional discussion of unrecognized tax benefits.
Concentration of Credit Risk
Our credit risk is currently concentrated with a limited number of major customers: Sierra Pacific Power Company, Southern California Edison and Hawaii Electric Light Company. If any of these electric utilities fails to make payments under its power purchase agreements with us, such failure would have a material adverse impact on our financial condition.
Southern California Edison accounted for 31.9%, 30.0% and 36.1% of our total revenues for the three years ended December 31, 2007, 2006 and 2005, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we account for separately under the equity method of accounting.
Hawaii Electric Light Company accounted for 14.6%, 15.1% and15.2% of our total revenues for the three years ended December 31, 2007, 2006 and 2005, respectively.
Sierra Pacific Power Company accounted for 9.7%, 12.8%, and 14.1% of our total revenues for the three years ended December 31, 2007, 2006 and 2005, respectively.
Government Grants and Tax Benefits
The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies. We are permitted to claim approximately 10% of the cost of each new geothermal power plant in the United States as an investment tax credit against our federal income taxes. Alternatively, we are permitted to claim a ‘‘production tax credit,’’ which in 2007 was 2.0 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed on the electricity output of new geothermal power plants put into service by December 31, 2008. Credit may be claimed for ten years on the output from any new geothermal power plants put into service prior to December 31, 2008. The owner of the project must choose between the production tax credit and the 10% investment tax credit described above. In either case, under current tax rules, any unused tax credit has a 1-year carry back and a 20-year carry forward. Whether we claim the production tax credit or the investment credit, we are also permitted to depreciate most of the plant for tax purposes over five years on an accelerated basis, meaning that more of the cost maybe deducted in the first few years than during the remainder of the depreciation period. If we claim the investment credit, our ‘‘tax base’’ in the plant that we can recover through depreciation must be reduced by half of the tax credit; if we claim a production tax credit; there is no reduction in the tax basis for depreciation.
Our subsidiary, Ormat Systems, received ‘‘Benefited Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959 (the Investment Law), with respect to two of its investment programs. As a Benefited Enterprise, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for the period from July 1, 2004 to June 30, 2006, and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. Ormat Systems is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for the period from January 1, 2007 to December 31, 2008, and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and our affiliates are at arms length, and
that the management and control of Ormat Systems will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, Ormat Systems is entitled to accelerated depreciation on equipment used for its industrial activities. Under the provisions of certain tax regulations published in Israel in 2005, industrial companies whose operations are mostly ‘‘Eligible Operations’’ are entitled to claim accelerated depreciation at the rate of 100% on machinery and equipment acquired from July 1, 2005 to December 31, 2006. Accelerated depreciation is to be claimed over two years. In the year in which the equipment was acquired, the regular depreciation rate is to be claimed with the remainder to be claimed in the second year.
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
Index to Consolidated Financial Statements of Ormat Technologies, Inc. and Subsidiaries
(1) As the Company’s 80% ownership interest in Ormat Leyte Co. Ltd. is accounted for by the equity method, separate financial statements of Ormat Leyte Co. Ltd. have been included pursuant to Rule 3-09 of Regulation S-X.
Financial statements of one 50% owned entity have been omitted because the registrant’s proportionate share of the income from continuing operations before income taxes is less than 20% of the respective consolidated amount, and the investment in and advances to this entity are less than 20% of consolidated total assets.
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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for share-based compensation in 2006. As discussed in Note 15 to the consolidated financial statements, the Company changed the manner in which it accounts for income taxes in 2007.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
San Francisco, California
March 5, 2008
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 power plants for projects owned by the Company or for third parties. The Company owns and operates geothermal and recovered energy-based power plants in various countries, including the United States of America (‘‘U.S.’’), Kenya, Nicaragua and Guatemala. The Company’s equipment manufacturing operations are located in Israel.
Most of the Company’s domestic power plant facilities are Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978 (‘‘PURPA’’). The power purchase agreements (‘‘PPAs’’) for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities were in compliance with Qualifying Facility status as of December 31, 2007.
Cash dividends
During the years ended December 31, 2007, 2006 and 2005, the Company’s Board of Directors declared, approved and authorized the payment of cash dividends in the aggregate amount of $8.6 million ($0.22 per share), $5.2 million ($0.15 per share) and $3.8 million ($0.12 per share), respectively. Such dividends were paid in the years declared.
Shelf registration statement and issuance of stock
On January 17, 2006, the Company filed a universal shelf registration statement on Form S-3, which was declared effective by the SEC on January 31, 2006. The shelf registration statement provides the Company with the opportunity to issue various types of securities, including debt securities, common stock, warrants and units of the Company, from time to time, in one or more offerings up to a total dollar amount of $1 billion. Pursuant to the shelf registration statement, the Company may periodically offer one or more of the registered securities in amounts, at prices, and on terms to be announced when, and if, the securities are offered. At the time any offering is made under the shelf registration statement, the offering specifics will be set out in a prospectus supplement.
On April 10, 2006, the Company completed a follow-on public offering of 3,500,000 shares of common stock at a price of $35.50 per share, under the shelf registration statement mentioned above. In addition, on April 17, 2006, 525,000 additional shares of common stock were sold at the abovementioned price pursuant to the exercise of the underwriters’ over-allotment option. Net proceeds to the Company after deducting underwriting fees and commissions and offering expenses associated with the offering were approximately $135.1 million.
On December 19, 2006, the Company completed a sale of 2,500,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $37.07 per share (net of underwriting fees and commissions), under the shelf registration statement mentioned above. Net proceeds to the Company after deducting underwriting fees and commissions and offering expenses associated with the offering were approximately $92.4 million.
On October 26, 2007, the Company completed a sale of 3,000,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $45.90 per share (net of underwriting fees and commissions), under the shelf registration statement mentioned above. Net proceeds to the Company after deducting underwriting fees and commissions and offering expenses associated with the offering were approximately $137.2 million.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 26, 2007, the Company completed an unregistered sale of 381,254 shares of common stock to the Parent at a price of $45.90 per share. The proceeds from the unregistered sale were approximately $17.5 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.
A portion of the proceeds from the October 26, 2007 block trade and the unregistered sale of shares was used to repay a capital note owed to the Parent in the amount of $50.7 million on December 3, 2007.
On January 8, 2008, the Company completed an additional unregistered sale of 693,750 shares of common stock to the Parent (see Note 21).
Rounding
Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000, unless otherwise indicated.
Reclassification
Certain comparative figures have been reclassified to conform to the current year presentation.
Basis of presentation
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and of all majority-owned subsidiaries in which the Company exercises control over operating and financial policies, and variable interest entities in which the Company has an interest and is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation.
Investments in less-than-majority-owned entities or other entities in which the Company exercises significant influence over operating and financial policies are accounted for using the equity method of accounting. Under the equity method, original investments are recorded at cost and adjusted by the Company’s share of undistributed earnings or losses of such companies. The Company’s earnings in investments accounted for under the equity method have been reflected as ‘‘Equity in income of investees’’ on the Company’s consolidated statements of operations and comprehensive income.
Cash and cash equivalents
The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.
Marketable securities
Marketable securities consist of debt securities (mainly auction rate securities and commercial paper). The Company accounts for such securities in accordance with Statement of Financial Accounting Standards (‘‘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, 2007 and 2006, all of the Company’s investments in marketable securities were classified as available-for-sale securities and as a result, were reported at their fair value based upon the quoted market prices of such securities at year end, except for auction rate securities whose fair value was determined based on the factors discussed below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unrealized gains and losses are included in accumulated other comprehensive income (loss), a component of stockholders’ equity, net of tax. Net realized gains or losses are reported in other income (expense). The Company evaluates its investments periodically for possible other-than-temporary impairment by reviewing factors such as the length of time and extent to which fair value has been below cost basis, the financial condition of the issuer and the Company’s ability and intent to hold the investment for a period of time which may be sufficient for anticipated recovery of market value. An impairment charge is recorded to the extent that the carrying value of available-for-sale securities exceeds the estimated fair market value of the securities and the decline in value is determined to be other-than-temporary.
Auction rate securities are securities that are structured with short-term interest rate reset dates of generally less than ninety days but with contractual maturities that can be well in excess of ten years. At the end of each reset period, which in the Company’s case occurs every twenty-eight days, investors can sell or continue to hold the securities at par. In the fourth quarter of 2007, certain auction rate securities failed auction due to sell orders exceeding buy orders. As of December 31, 2007, the Company held auction rate securities totaling $24.4 million at par value of which $11.2 million at par value are currently associated with failed auctions, all of which have been in a loss position for less than 12 months. Historically, the carrying value of auction rate securities approximated fair value due to the frequent resetting of the interest rates. While the Company continues to earn interest on these investments at the contractual rates, the estimated market value of these auction rate securities no longer approximates par value. Given the complexity of auction rate securities, the Company engaged an investment advisor to assist in determining the fair values of its investments. The Company, with the assistance of its advisor, estimated the fair value of these auction rate securities based, among other things, on the following: (i) the underlying structure of each security; (ii) the present value of future principal and interest payments discounted at rates considered to reflect current market conditions; (iii) consideration of the probabilities of default, auction failure, or repurchase at par for each period; and (iv) estimates of the recovery rates in the event of default for each security. These estimated fair values could change significantly based on future market conditions.
Based on available information, the Company concluded that the fair market value of these failed auction rate securities at December 31, 2007 was $8.4 million, a decline of $2.8 million from par value. Of this amount $0.8 million was deemed temporary as the Company believes the decline in market value is due to general market conditions. Based upon the Company’s evaluation of available information, the Company believes these investments generally are of high credit quality, as substantially all of the investments carry a AA credit rating and higher. In addition, the Company currently has the intent and ability to hold these investments until anticipated recovery in market value occurs. Accordingly, the Company has recorded an unrealized loss on these securities of $0.8 million in other comprehensive loss. The Company concluded that $2.0 million of the decline was other-than-temporary and recorded an impairment charge in other non operating income (loss). The Company’s conclusion for the other than temporary impairment is based on the significant decline in fair value indicated for a certain investment.
The funds invested in auction rate securities that have experienced failed auctions will not be accessible until a successful auction occurs, a buyer is found outside of the auction process or the underlying securities have matured. All securities continue to pay interest in accordance with their stated terms. As a result, the Company has classified those securities with failed auctions as long-term assets in the consolidated balance sheet as of December 31, 2007.
The Company continues to monitor the market for auction rate securities and consider its impact (if any) on the fair market value of its investments. If the current market conditions deteriorate further, or the anticipated recovery in market values does not occur, the Company may be required to record additional unrealized losses in other comprehensive income or impairment charges in 2008.
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The marketable securities are included in the consolidated balance sheets as follows:
The cost of the marketable securities at December 31, 2007 and 2006 was $40,685,000 and $113,232,000, respectively.
Restricted cash, cash equivalents and marketable securities
Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserve, cash collateral and operating fund accounts that have been classified as restricted cash, cash equivalents and marketable securities. Funds that will be used to satisfy obligations due during the next twelve months and are not auction rate securities which experienced failed auction due to sell orders exceeding buy orders (see ‘‘marketable securities’’ above) are classified as current restricted cash, cash equivalents and marketable securities, with the remainder classified as non-current restricted cash, cash equivalents and marketable securities. Such amounts are invested primarily in money market accounts, auction rate securities and commercial paper with a minimum investment grade of ‘‘AA’’. Auction rate securities are classified as available-for-sale.
Certain of the restricted cash accounts can be replaced by a letter of credit. As further described in Note 19, as of December 31, 2007, a letter of credit in the amount of $11.5 million was issued by the Company to release restrictions on funds that were used as collateral for OFC’s 8¼% Senior Secured Notes.
Concentration of credit risk
Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments, marketable securities and accounts receivable.
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, 2007 and 2006, the Company had deposits totaling $21,322,000 and $13,068,000, respectively, in six U.S. financial institutions that were federally insured up to $100,000 per account. At December 31, 2007 and 2006, the Company’s deposits in foreign countries of approximately $13,248,000 and $15,321,000, respectively, were not insured.
At December 31, 2007 and 2006, accounts receivable related to operations in foreign countries amounted to approximately $17,140,000 and $16,957,000, respectively. At December 31, 2007 and 2006, accounts receivable from the Company’s major customers that have generated 10% or more of its revenues (see Note 16) amounted to approximately 39% and 49%, respectively, of the Company’s accounts receivable.
Southern California Edison Company (‘‘SCE’’) accounted for 31.9%, 30.0% and 36.1% of the Company’s total revenues for the years ended December 31, 2007, 2006 and 2005, respectively. SCE is
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also the power purchaser and revenue source for the Mammoth project, which is accounted for separately under the equity method.
Hawaii Electric Light Company accounted for 14.6%, 15.1% and 15.2% of the Company’s total revenues for the years ended December 31, 2007, 2006 and 2005, respectively.
Sierra Pacific Power Company accounted for 9.7%, 12.8% and 14.1% of the Company’s total revenues for the years ended December 31, 2007, 2006 and 2005, respectively.
The Company performs ongoing credit evaluations of its customers’ financial condition. The Company has historically been able to collect on substantially all of its receivable balances, and accordingly, no provision for doubtful accounts has been made.
Inventories
Inventories consist primarily of raw material parts and sub assemblies for power units, and are stated at the lower of cost or market value, using the moving-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories, which amount was not significant at December 31, 2007 and 2006.
Deposits and other
Deposits and other consist primarily of performance bonds for construction projects, a long-term insurance contract and derivative instruments.
Property, plant and equipment
Property, plant and equipment are stated at cost. All costs associated with the acquisition, development and construction of power plants operated by the Company are capitalized. Major improvements are capitalized and repairs and maintenance (including major maintenance) costs are expensed. Power plants operated by the Company are depreciated using the straight-line method over their estimated useful lives, which range from 25 to 30 years (see below). The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plant is operated by the Company. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
During the second quarter of 2007, the Company revised the estimated useful life of certain of its power plants from 20 or 25 years to 30 years to reflect the expected period these plants will be utilized. The change in estimated useful life has been accounted for on a prospective basis effective April 1, 2007. The impact of this change in estimated useful life was an increase in net income and earnings per share of $771,000 and $0.02, respectively, in the year ended December 31, 2007. 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 $6,835,000, $8,080,000 and $3,504,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
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Exploration and drilling costs
The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources on an ‘‘area-of-interest’’ basis. All such costs, which include dry hole costs and the cost of drilling and equipping production wells and other directly attributable costs, are capitalized and amortized over their estimated useful lives when production commences. Exploration and drilling costs related to uncompleted projects are included as construction-in-process in the consolidated balance sheets and totaled $16,677,000 and $844,000 at December 31, 2007 and 2006, respectively.
Asset retirement obligation
The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. The Company’s legal liabilities include plugging wells and post-closure costs of geothermal power producing sites. When a new liability for asset retirement obligations is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. At retirement, the obligation is settled for its recorded amount at a gain or loss.
Deferred financing and lease transaction costs
Deferred financing costs are amortized over the term of the related obligation using the effective interest method. Amortization of deferred financing costs is presented as interest expense in the consolidated statements of operations and comprehensive income. Accumulated amortization related to deferred financing costs amounted to $6,060,000 and $4,342,000 at December 31, 2007 and 2006, respectively. Amortization expense for the years ended December 31, 2007, 2006 and 2005 amounted to $1,718,000, $1,920,000 and $6,087,000, respectively. Amortization expense for the year ended December 31, 2005 includes $4,180,000 relating to the write-off of the remaining deferred financing costs when the Beal Bank loan was repaid (see Note 9).
Deferred transaction costs relating to the Puna operating leases (see Note 10) in the amount of $4,333,000 are amortized using the straight-line method over the 23-year term of the lease. Amortization of deferred transaction costs is presented in cost of revenues in the consolidated statements of operations and comprehensive income. Accumulated amortization related to deferred lease costs amounted to $485,000 and $301,000 at December 31, 2007 and 2006, respectively. Amortization expense for the years ended December 31, 2007, 2006 and 2005 amounted to $184,000, $184,000 and $117,000, respectively.
Intangible assets
Intangible assets consist of allocated acquisition costs of PPAs, which are amortized using the straight-line method over the 13 to 25-year terms of the agreements.
Impairment of long-lived assets and long-lived assets to be disposed of
Long-lived assets which consist of property, plant and equipment, exploration and drilling costs, PPAs and unconsolidated investments are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net undiscounted cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Management believes that no impairment exists for long-lived assets; however, future estimates as to the recoverability of such assets may change based on revised circumstances.
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Derivative instruments
Derivative instruments (including certain derivative instruments embedded in other contracts) are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
The Company maintains a risk management strategy that incorporates the use of interest rate swaps and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by interest rate volatility. Gains or losses on contracts that initially qualify for cash flow hedge accounting, net of related taxes, are included as a component of other comprehensive income or loss and are subsequently reclassified into earnings when interest on the related debt is paid. Gains or losses on contracts that are not designated to qualify as a cash flow hedge are included as a component of interest expense.
Foreign currency translation
The functional currency of all foreign entities is the reporting currency (U.S. dollar). For these entities, monetary assets and liabilities are translated at the current exchange rate, while non-monetary items are translated at historical rates. Income and expense items are translated at the average exchange rate for the year, except for depreciation expense, which is translated at historical rates. Translation adjustments and transaction gains or losses are included in results of operations.
Comprehensive income reporting
Comprehensive income includes net income plus other comprehensive income, which for the Company consists of unrealized gain or loss on marketable securities available-for-sale and the mark-to-market gains or losses on derivative instruments designated as a cash flow hedge.
Revenues and cost of revenues
Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy power plants owned and operated by the Company; and (ii) geothermal and recovered energy power plant equipment engineering, sale, construction and installation and operating services.
Revenues related to the sale of electricity from geothermal and recovered energy power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified or acquired in business combinations on or after July 1, 2003 (effective date of Emerging Issues Task Force Issue (‘‘EITF’’) No. 01-08, Determining whether an Arrangement Contains a Lease), revenues related to the lease element of the PPAs are included as ‘‘lease portion of energy and capacity’’ revenues on the consolidated statements of operations and comprehensive income, with the remaining revenues related to the production and delivery of energy presented as ‘‘energy and capacity’’. Lease income and expense are recognized ratably over the lease periods.
Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts. Revenues from the supply and/or construction of geothermal and recovered energy power plant equipment and other equipment to third parties are recognized using the percentage completion method. Revenue is recognized based on the percentage relationship that incurred costs bear to total estimated costs. Costs include direct material, labor, and indirect costs. Selling, marketing, general, and administrative costs are charged to expense as incurred. Provisions for estimated losses on uncompleted contracts are made in the period
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in which such losses are determined. Changes in job performance, job conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined.
Warranty on products sold
The Company generally provides a one-year warranty against defects in workmanship and materials related to the sale of products for electricity generation. Estimated future warranty obligations are included in operating expenses in the period in which the related revenue is recognized. Such charges are immaterial for the years ended December 31, 2007, 2006 and 2005.
Research and development
Research and development costs incurred by the Company for the development of existing and new geothermal, recovered energy and remote power technologies are expensed as incurred. Grants received from the U.S. Department of Energy are offset against the related research and development expenses. Such grants amounted to $0, $252,000 and $1,275,000 for the years ended December 31, 2007, 2006, and 2005, respectively.
Stock-based compensation
Effective January 1, 2006, the Company adopted SFAS No. 123(R), Share-Based Payments (‘‘SFAS No. 123R’’) which establishes the accounting for employee stock-based awards. Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with Accounting Principles Board Opinion No. 25 (‘‘APB No. 25’’), Accounting for Stock Issued to Employees, and related interpretations. Under APB No. 25 compensation cost was recognized based on the difference, if any, on the date of grant between the fair value of the Company’s stock and the amount an employee must pay to acquire the stock (see Note 13). Under SFAS No. 123R, compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant).
Income taxes
Income taxes are accounted for using the asset and liability approach, which requires the recognition of taxes payable or refundable for the current year and deferred tax assets and liabilities for the future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The measurement of current and deferred tax assets and liabilities are based on provisions of the enacted tax law. The effects of future changes in tax laws or rates are not anticipated. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are more likely than not expected to be realized. Tax benefits from uncertain tax positions are recognized only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position (see FIN No. 48 - Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109, below and Note 15).
Earnings per share
Basic earnings per share is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding for the year. The Company does not have any equity instruments that are dilutive, except for employee stock options. The stock options granted to employees of the Company in the Parent’s stock are not dilutive to the Company’s earnings per share in any year.
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Fair value of financial instruments
The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments. Marketable securities are presented at fair value. The fair value of long-term debt is estimated based on the current borrowing rates for similar issues, which approximates its carrying amount, except for the following:
Use of estimates in preparation of financial statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of such financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. The most significant estimates with regard to the Company’s consolidated financial statements relate to the useful lives of property, plant and equipment, revenue recognition of products sales using the percentage completion method, asset retirement obligation, impairment of long-lived assets and assets to be disposed of, valuation of auction rate securities and the provision for income taxes.
New accounting pronouncements
New accounting pronouncements effective in the year ended December 31, 2007
SFAS No. 155 - Accounting for Certain Hybrid Financial Instruments
Effective January 1, 2007, the Company adopted SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. SFAS No. 155 replaces certain provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities and SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. SFAS No. 155 permits fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. It clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS No. 133. SFAS No. 155 also establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation. It also clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives and amends SFAS No. 140 to eliminate the prohibition on a qualifying special-purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after January 1, 2007. The adoption by the Company of SFAS No. 155, effective January 1, 2007, did not have any impact on its results of operations or financial position.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FIN No. 48 - Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109
Effective January 1, 2007, the Company adopted Financial Accounting Standards Board (‘‘FASB’’) Interpretation (‘‘FIN’’) No. 48, Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109. FIN No. 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN No. 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification and disclosure of tax positions, as well as the accounting for interest and penalties. As a result of the implementation of FIN No. 48, on January 1, 2007, the Company recognized as a cumulative effect of change in accounting principle, a $328,000 increase in the liability for unrecognized tax benefits and a corresponding decrease in beginning retained earnings. See Note 15 for additional information about the Company’s unrecognized tax benefits.
EITF Issue No. 06-3 - How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation)
Effective January 1, 2007, the Company adopted Emerging Issues Task Force (‘‘EITF’’) Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That is, Gross versus Net Presentation). The requirements of EITF Issue No. 06-3 apply to any tax assessed by a governmental authority that is imposed concurrently on a specific revenue-producing transaction between a seller and a customer. Examples of taxes subject to Issue No. 06-3 include sales, use, value added, and some excise taxes. EITF Issue No. 06-3 excludes taxes that are assessed on gross receipts or that are imposed during the process of obtaining inventory. Companies will be required to disclose their accounting policy regarding the presentation of taxes subject to EITF Issue No. 06-3, and the amounts of such taxes that are included in income on a gross basis, if those amounts are significant. The adoption by the Company of EITF Issue No. 06-3, effective January 1, 2007, did not have any impact on its financial statements.
New accounting pronouncements effective in future years
SFAS No. 157 - Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and accordingly, does not require any new fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 (January 1, 2008 for the Company) for financial assets and liabilities and for fiscal years beginning after November 15, 2008 (January 1, 2009 for the Company) for non-financial assets and liabilities. The Company does not anticipate that the adoption of this statement will have a material impact on its consolidated financial statements.
SFAS No. 159 - The Fair Value Option for Financial Assets and Financial Liabilities
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No.159 permits entities to choose to measure certain financial assets and liabilities and other eligible items at fair value, which are not otherwise currently required to be
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measured at fair value. Under SFAS No. 159, the decision to measure items at fair value is made at specified election dates on an irrevocable instrument-by-instrument basis. Entities electing the fair value option would be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. Entities electing the fair value option are required to distinguish on the face of the statement of financial position, the fair value of assets and liabilities for which the fair value option has been elected and similar assets and liabilities measured using another measurement attribute. If elected, SFAS No. 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007 (January 1, 2008 for the Company) with earlier adoption permitted provided that the entity also early adopts all of the requirements of SFAS No. 159. The Company is currently evaluating whether to elect the option provided for in this standard.
SFAS No. 160 - Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51. SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS No. 160 shall be applied prospectively. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 160 on its consolidated financial statements.
SFAS No. 141 (revised 2007) - Business Combinations
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (‘‘SFAS No. 141R’’). SFAS No. 141R establishes principles and requirements for how the acquirer of a business recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. SFAS No. 141R also provides guidance for recognizing and measuring the goodwill acquired in the business combination and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Company is currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on its consolidated financial statements.
SAB No. 110
In December 2007, the SEC issued Staff Accounting Bulletin (‘‘SAB’’) No. 110 relating to the use of a ‘‘simplified’’ method in developing an estimate of the expected term of ‘‘plain vanilla’’ share options. SAB No. 107, which was applied by the Company for estimating the expected term of employee’s stock options, previously allowed the use of the simplified method until December 31, 2007. SAB No. 110 allows, under certain circumstances, to continue to accept the use of the simplified method beyond December 31, 2007. The Company does not expect that the adoption of SAB No. 110 will have a material impact on its consolidated financial statements.
NOTE 2 - BUSINESS ACQUISITION
The Zunil Project
Prior to March 13, 2006, the Company had a 21.0% ownership interest in Orzunil I de Electricidad, Limitada (‘‘Orzunil’’), a limited responsibility company incorporated in Guatemala and established for the purpose of generating power by means of a geothermal power plant in the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Province of Quetzaltenango in Guatemala. The Company operates and maintains the geothermal power plant and the power purchaser supplies geothermal fluid to the power plant.
On March 13, 2006, the Company acquired a 50.8% ownership interest in Orzunil and increased its then existing 21.0% ownership interest to 71.8%. The purchase price of this acquisition was $15.4 million, including acquisition costs of approximately $0.6 million.
The Company’s 21.0% ownership interest in Orzunil prior to the abovementioned acquisition was accounted for under the equity method of accounting as the Company had the ability to exercise significant influence, but not control, over Orzunil. As a result of the acquisition of the additional 50.8% interest in Orzunil, the financial statements of Orzunil were consolidated with the Company’s financial statements effective March 13, 2006.
On August 16, 2006, the Company completed the acquisition from each of CDC Group plc (‘‘CDC’’) and International Finance Corporation (‘‘IFC’’), both of which are the Zunil Project’s senior lenders, a 14.1% ownership interest in Orzunil (for a total of 28.2%), thereby increasing the Company’s then existing 71.8% ownership interest to 100%. The total purchase price of both acquisitions was $7.4 million, including acquisition costs of approximately $0.9 million.
The abovementioned acquisitions have been accounted for under the purchase method of accounting and the acquired assets are being depreciated over their estimated useful lives of 13.5 years. The purchase prices of all the abovementioned acquisitions ($22.8 million) have been allocated to the fair value of assets and liabilities based on an independent valuation and management’s estimates as follows:
The revenues of Orzunil and the Company’s share in the net income of Orzunil were $10,343,000 and $3,018,000, respectively, for the period from March 13, 2006 to December 31, 2006.
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The Company’s equity in income of Orzunil was not significant for each of the years presented in these 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 consolidated 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.
NOTE 5 - UNCONSOLIDATED INVESTMENTS
Unconsolidated investments in power plant projects consist of the following:
From time to time, the unconsolidated power plants make distributions to their owners. Such distributions are deducted from the investments in such power plants.
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The Mammoth Project
The Company has a 50% interest in the Mammoth project (‘‘Mammoth’’), which is comprised of three geothermal power plants located near the city of Mammoth, California. The purchase price was less than the underlying net equity of Mammoth by approximately $9.3 million. As such, the basis difference will be amortized over the remaining useful life of the property, plant and equipment and the PPAs, which range from 12 to 17 years. The Company operates and maintains the geothermal power plants under an operating and maintenance (‘‘O&M’’) agreement. The Company’s 50% ownership interest in Mammoth is accounted for under the equity method of accounting as the Company has the ability to exercise significant influence, but not control, over Mammoth.
The unaudited condensed financial position and results of operations of Mammoth are summarized below:
The Mammoth project sells its electrical output to SCE under three separate PPAs. Under the G-1 power purchase agreement, in certain circumstances, SCE or its affiliates has a right of first refusal to acquire the plant.
The Leyte Project
The Company holds an 80% interest in Ormat Leyte Co. Ltd. (‘‘OLCL’’). OLCL is a limited partnership established for the purpose of developing, financing, operating, and maintaining a geothermal power plant in Leyte Provina, the Philippines. Upon the adoption of FIN No. 46R, Consolidation of Variable Interest Entities (revised December 2003) - an interpretation of ARB No. 51, on March 31, 2004, the Company concluded that OLCL should not be consolidated. As a result of such conclusion, the Company’s 80% ownership interest in OLCL is accounted for under the equity method of accounting.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The unaudited condensed financial position and results of operations of OLCL are summarized below:
In 1996, OLCL entered into a Build, Operate, and Transfer (‘‘BOT’’) agreement with PNOC-Energy Development Corporation (‘‘PNOC’’) in connection with the four geothermal power generation plants, with a total capacity of 49 MW, located in Leyte, Philippines. During 1997, the power plants started commercial operations and began selling power to PNOC under a ten year power purchase agreement (tolling arrangement). OLCL received capacity and energy fees from PNOC established by the BOT agreement. Fees were paid each month through the term of the BOT agreement and varied based on plant performance. OLCL owned the plants for a ten-year period which ended September 25, 2007, at which time they were transferred to PNOC for no further consideration. The Company did not incur any material financial loss as a result of such transfer, although going forward this will reduce the Company’s owned foreign generation capacity by 39 MW with a commensurate impact on equity in income of investees and net income.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 - PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, net, consist of the following:
Depreciation expense for the years ended December 31, 2007, 2006 and 2005 amounted to $45,607,000, $38,659,000 and $31,210,000, respectively.
U.S. operations:
The net book value of the property, plant and equipment, including construction in process, located in the United States was approximately $783,518,000 and $636,332,000 as of December 31, 2007 and 2006, respectively.
Foreign operations:
The net book value of the property, plant and equipment, including construction in process, located outside of the United States was approximately $193,882,000 and $156,832,000 as of December 31, 2007 and 2006, respectively.
Pursuant to a 20-year PPA with Kenya Power and Lighting Co. Ltd. (‘‘KPLC’’), the Company agreed to design, construct and operate geothermal power plants in Kenya in several phases. The net book value of assets associated with Phase I was $26,987,000 and $28,813,000 as of December 31, 2007 and 2006, respectively. The Company has incurred approximately $58,119,000 and $21,556,000 (included in construction-in-process) at December 31, 2007 and 2006, respectively, in connection with the construction of Phase II of the power plant. Pursuant to the amended and restated PPA, the parties agreed to shorten the construction period for Phase II to approximately twenty-one months from February 7, 2007, and to reduce the tariff payable by KPLC on the total capacity of the plant upon completion of Phase II. Management believes that the project will be completed in the required timeframe. If the Company does not complete the construction of Phase II by the required date, the Company may lose some or all of its investment in the construction-in-process relating to Phase II.
Pursuant to an agreement with Empresa Nicaraguense de Electricitdad (‘‘ENEL’’), a Nicaraguan power utility, the Company rehabilitated existing wells, drilled new wells, and is operating the geothermal facilities. The Company owns the plants for a fifteen-year period ending in 2014, at which time they will be transferred to ENEL at no cost. The net book value of the assets related to the plant and wells was $18,199,000 and $21,019,000 at December 31, 2007 and 2006, respectively.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company, through its wholly-owned subsidiary, Orzunil, owns a power plant in Guatemala. The geothermal resources used by the power plant are owned by Instituto Nacional de Elecrification (‘‘INDE’’), a Guatemalan power utility, who granted the use of these resources to Orzunil for the period of the PPA. The net book value of the assets related to the power plant was $37,770,000 and $40,258,000 at December 31, 2007 and 2006, respectively.
The Company, through its wholly-owned subsidiary, Ortitlan, Limitada, owns a power plant in Guatemala (the ‘‘Amatitlan Project’’). The net book value of the assets related to the power plant was $35,835,000 at December 31, 2007. As of December 31, 2006 the plant was under construction and its book value in the amount of $34,669,000 was included in construction-in-process.
The Company is engaged in the construction of several geothermal power plants in other foreign countries. At December 31, 2007 and 2006, such projects were in the various stages of construction and the related costs totaling approximately $9,701,000 and $36,368,000 (including $34,669,000 for the Amatitlan Project), respectively, are included in construction-in-process.
NOTE 7 - INTANGIBLE ASSETS
Intangible assets consist mainly of all of the Company’s PPAs acquired in business combinations and amounted to $47,989,000 and $50,086,000, net of accumulated amortization of $12,574,000 and $9,327,000, as of December 31, 2007 and 2006, respectively. Amortization expense for the years ended December 31, 2007, 2006 and 2005 amounted to $3,247,000, $3,079,000 and $2,815,000, respectively.
Estimated future amortization expense for the intangible assets as of December 31, 2007 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:
Senior Loans
International Finance Corporation (‘‘IFC’’) Loan A and Loan B
Orzunil, a wholly owned subsidiary of the Company, has a senior loan agreement with IFC (‘‘Loan A’’). The loan matures on November 15, 2011, and is payable in 47 quarterly installments. The loan has a fixed annual interest rate of 11.775%.
Orzunil has another senior loan agreement with IFC (‘‘Loan B’’). The loan matures on May 15, 2008, and is payable in 32 quarterly installments. The loan has a fixed annual interest rate of 11.730%.
Commonwealth Development Corporation (‘‘CDC’’) Loan
Orzunil has a senior loan agreement with CDC. The loan matures on August 15, 2010, and is payable in 42 quarterly installments. The loan has a fixed annual interest rate of 10.300%.
There are various restrictive covenants under these Senior Loans, which include limitations on Orzunil’s ability to make distributions to its shareholders. Management believes that as of December 31, 2007, Orzunil was in compliance with the covenants under the Senior Loans.
Credit Facility Agreement (the Momotombo Project)
Ormat Momotombo Power Company (‘‘OMPC’’), a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. Principal and interest payments on the Phase I Loan are payable in 32 equal quarterly payments that commenced upon completion of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Phase I of the project in December 2001. Interest on the Phase I Loan is variable based on 3-month LIBOR plus 2.375%. Principal and interest payments on the Phase II Loan are payable in equal 28 quarterly payments that commenced in March 2004. Interest on the Phase II Loan is variable based on 3-month LIBOR plus 3.0%, and is added to the outstanding balances of the Phase II Loan until the commencement of the principal and interest payments. At December 31, 2007 and 2006, $3,285,000 and $4,476,000, respectively, was outstanding under the Phase I Loan and $5,080,000 and $6,777,000, 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.
Due to a failure of a turbine, the Momotombo project was not in full operation from June 2007 to October 2007. As a result, OMPC did not meet the ‘‘debt service coverage ratio’’ required at December 31, 2007, and therefore, distributions from the project are restricted. The power plant recently returned to full operation.
In October 2007, OPMPC reached an agreement with Bank Hapoalim B.M., pursuant to which Bank Hapoalim B.M. allowed OMPC to use the funds in the ‘‘debt service reserve account’’ for the repair of the damaged turbine. As a result, OMPC does not comply with the required ‘‘debt service reserve account’’. In accordance with the terms of the credit facility, Momotombo has a 180-day period to replenish the ‘‘debt service reserve account’’. On February 24, 2008, Bank Hapoalim granted OMPC an extension to replenish the ‘‘Debt Service Reserve Account’’ until August 31, 2009. As the power plant recently returned to full operation, management believes that OMPC will comply with the ‘‘debt service reserve account’’ covenant before August 31, 2009.
Management believes that except as described above, OMPC was in compliance with all other covenants under the Credit Facility Agreement as of December 31, 2007.
Future minimum payments
Future minimum payments under long-term obligations, excluding the senior secured notes and notes payable to Parent, as of December 31, 2007 are as follows:
OFC Senior Secured Notes
On February 13, 2004, Ormat Funding Corp. (‘‘OFC’’), a wholly owned subsidiary, issued $190.0 million, 8¼% Senior Secured Notes (‘‘OFC Senior Secured Notes’’) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, and received net cash proceeds of approximately $179.7 million, after deduction of issuance costs of approximately $10.3 million, which have been included in deferred financing costs in the consolidated balance sheet. The OFC Senior Secured Notes have a final maturity of December 30, 2020. Principal and interest on the OFC Senior Secured Notes are payable in semi-annual payments that commenced on June 30, 2004. The OFC Senior Secured Notes are collateralized by substantially all of the assets of
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OFC and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. There are various restrictive covenants under the OFC Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends.
On May 31, 2007, OFC successfully consummated a consent solicitation relating to the OFC Senior Secured Notes. The Consent Solicitation was conducted in order to amend and/or waive certain provisions of the indenture such that the shut down and decommissioning of the Desert Peak 1 plant and the related termination of the fluid supply agreement pursuant to which geothermal resource was supplied to that plant (both of which constituted assets pledged to the Noteholders to secure repayment of the OFC Senior Secured Notes) would not constitute defaults or events of default under the indenture.
Management believes that as of December 31, 2007, OFC was in compliance with the covenants contained in the indenture governing the OFC Senior Secured Notes.
OFC may redeem the OFC Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OFC Senior Secured Notes to be redeemed plus accrued interest, premium and liquidated damages, if any, plus a ‘‘make-whole’’ premium. Upon certain events, as defined in the indenture governing the OFC Senior Secured Notes, OFC may be required to redeem a portion of the OFC Senior Secured Notes at a redemption price ranging from 100% to 101% of the principal amount of the OFC Senior Secured Notes being redeemed plus accrued interest, premium and liquidated damages, if any.
Debt service reserve
As required under the terms of the OFC Senior Secured Notes, OFC maintains an account which may be funded by cash or backed by letters of credit (see below) in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OFC Senior Secured Notes in the following six months. This restricted cash account is classified as current on the consolidated balance sheet. As of December 31, 2007 and 2006, the balance of such account was $0.1 million and $13.3 million, respectively. In addition, as of December 31, 2007 and 2006, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $11.5 million and two letters of credit in the total amount of approximately $12.2 million, respectively (see Note 19).
Future minimum payments under the OFC Senior Secured Notes, as of December 31, 2007 are as follows:
OrCal Senior Secured Notes
On December 8, 2005, OrCal Geothermal Inc. (‘‘OrCal’’), a wholly owned subsidiary, issued $165.0 million, 6.21% Senior Secured Notes (‘‘OrCal Senior Secured Notes’’) in an offering subject to Rule 144A and Regulation S of the Securities Act of 1933, as amended, and received net cash proceeds of approximately $161.1 million, after deduction of issuance costs of approximately
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$3.9 million, which have been included in deferred financing costs in the consolidated balance sheet. The OrCal Senior Secured Notes have been rated BBB− by Fitch. The OrCal Senior Secured Notes have a final maturity of December 30, 2020. Principal and interest on the OrCal Senior Secured Notes are payable in semi-annual payments which commenced on June 30, 2006. The OrCal Senior Secured Notes are collateralized by substantially all of the assets of OrCal, and those of its subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OrCal. There are various restrictive covenants under the OrCal Senior Secured Notes, which include limitations on additional indebtedness and payment of dividends. Management believes that as of December 31, 2007, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes.
OrCal may redeem the OrCal Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OrCal Senior Secured Notes to be redeemed plus accrued interest, and a ‘‘make-whole’’ premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal may be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of 100% of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest.
Debt service reserve
As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account with a required minimum balance, which may be funded by cash or backed by letters of credit in an amount sufficient to pay scheduled debt service amounts, including principal and interest, due under the terms of the OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current on the consolidated balance sheet. As of December 31, 2007 and 2006, the balance of such account was $11.9 million and $14.8 million, respectively. In addition, as of December 31, 2006, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $9.7 million (see Note 19).
Future minimum payments under the OrCal Senior Secured Notes, as of December 31, 2007 are as follows:
In anticipation of the OrCal Offering, on September 9, 2005, the Company entered into a rate lock agreement with a financial institution (the ‘‘counterparty’’), at a locked-in rate of 4.047%, with a notional amount of $175.0 million, which terminated on December 5, 2005. The rate lock was based on a 7-year treasury security that matures in November 2012. On December 5, 2005, the Company received from the counterparty to the rate lock agreement an amount of $4,488,000. A gain of $2,624,000, net of related taxes of $1,608,000, was recorded as ‘‘Gain in respect of derivative instruments designated for cash flow hedge, net of related taxes’’ under ‘‘Other comprehensive income (loss)’’ and is amortized over the term of the OrCal Senior Secured Notes using the effective interest method. The remaining gain of $159,000, net of related taxes of $97,000, has been charged to the consolidated statement of operations and comprehensive income ($256,000 was recorded as interest income and $97,000 was recorded as income tax expense) in the year ended December 31, 2005.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In December 2003, in connection with the acquisition of the Heber power plants, OrCal entered into a loan agreement with Beal Bank to provide a loan in the amount of $154.5 million. On December 8, 2005, in connection with the issuance of the OrCal Senior Secured Notes, OrCal repaid the loan in its entirety. This repayment resulted in a one-time charge to interest expense of approximately $16.6 million, comprised of: (i) prepayment premium of $11.5 million associated with payment of the Beal Bank loan, (ii) write-off of certain deferred financing costs amounting to $4.2 million associated with the incurrence of the Beal Bank loan, and (iii) loss of $0.9 million associated with interest rate cap transactions which were intended to mitigate the interest rate risk in respect of such loan agreement. The tax effect of such one time charge was $6.3 million, bringing the net effect of it to $10.3 million.
NOTE 10 - PUNA PROJECT LEASE TRANSACTIONS
On May 19, 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (‘‘PGV’’) entered into a transaction involving the Puna geothermal power plant located on the Big Island of Hawaii (the ‘‘Puna Project’’), which was acquired in June 2004. A similar transaction relating to two new geothermal wells that PGV drilled in the second half of 2005 (for production and injection) was completed on December 30, 2005.
Pursuant to a 31-year head lease (the ‘‘Head Lease’’). PGV leased its geothermal power plant to an unrelated company in return for prepaid lease payments in the total amount of $83.0 million (the ‘‘Deferred Lease Income’’). The carrying value of the leased assets as of December 31, 2007 and 2006 amounted to $53.3 million and $56.0 million, net of accumulated depreciation of $9.1 million and $6.4 million, respectively. The unrelated company (the ‘‘Lessor’’) simultaneously leased back the Puna Project to PGV under a 23-year lease (the ‘‘Project Lease’’). PGV’s rent obligations under the Project Lease will be paid solely from revenues generated by the Puna Project under a PPA that PGV has with Hawaii Electric Light Company (‘‘HELCO’’). The Head Lease and the Project Lease are non-recourse lease obligations to the Company. PGV’s rights in the geothermal resource and the related PPA have not been leased to the Lessor as part of the Head Lease but are part of the Lessor’s security package.
The Head Lease and the Project Lease are being accounted for separately. Each was classified as an operating lease in accordance with SFAS No. 13, Accounting for Leases. The Deferred Lease Income is amortized into revenue, using the straight-line method, over the 31-year term of the Head Lease. Deferred transaction costs amounting to $4.3 million are being amortized, using the straight-line method, over the 23-year term of the Project Lease.
Future minimum lease payments under the Project Lease, as of December 31, 2007, are as follows:
Depository accounts
As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
funds amounted to $7.6 million and $9.6 million as of December 31, 2007 and 2006, respectively, and were included in restricted cash accounts in the consolidated balance sheets. As of December 31, 2007, $5.6 million of such accounts were classified as non-current, since they are invested in auction rate securities which experienced multiple failed auctions due to a lack of liquidity in the market for these securities, as explained in Note 1, and the remaining $2.0 million were classified as current as they are used for current payments. As of December 31, 2006, such accounts were classified as current as they were used for current payments.
Distribution account
PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada Inc. The distributions are allowed only if PGV maintains various restrictive covenants under the lease agreements, which include limitations on additional indebtedness. As of December 31, 2007 and 2006, the balance of such account was $10.4 million and $11.3 million, respectively. This amount can be distributed to Ormat Nevada Inc. currently and has been classified as current restricted assets.
In anticipation of the above lease transactions, on February 25, 2005, the Company entered into a treasury rate lock agreement with a financial institution, at a locked-in treasury rate of 4.31%, with a notional amount of $52.0 million, which terminated on March 31, 2005. The rate lock was based on a 10-year treasury security that matures on February 15, 2015. On March 31, 2005, the Company received from the counterparty to the rate lock agreement an amount of $658,000. This amount, net of related taxes of $250,000, is recorded as ‘‘Gain in respect of derivative instruments designated for cash flow hedge, net of related taxes’’ under ‘‘Other comprehensive income (loss)’’ and is amortized over the 23-year term of the Project Lease.
On April 20, 2005, the Company entered into a new treasury rate lock agreement with the same financial institution, at a locked-in treasury rate of 4.22%, with a notional amount of $52.0 million and originally scheduled to terminate on May 2, 2005. The new rate lock agreement’s termination date was extended until May 18, 2005 at a new locked-in treasury rate of 4.25%. The rate lock was based on a 10-year treasury security that matures on February 15, 2015. There was no consideration paid by either party as a result of the extension. On May 18, 2005, the Company paid the counterparty to the new rate lock agreement the amount of $762,000. This amount, net of related taxes of $290,000, is recorded in ‘‘Other comprehensive income (loss)’’ and is amortized over the 23-year term of the Project Lease.
NOTE 11 - OPC TAX MONETIZATION TRANSACTION
On June 7, 2007, a wholly owned subsidiary of the Company, Ormat Nevada Inc. (‘‘Ormat Nevada’’), concluded a transaction to monetize production tax credits and other favorable tax attributes, such as accelerated depreciation, generated from certain of its geothermal power projects. Pursuant to the transaction, affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. became institutional equity investors in a newly formed subsidiary of Ormat Nevada. The projects involved in the transaction include Desert Peak 2, Steamboat Hills, and Galena 2, all located in Nevada.
Under the transaction structure, Ormat Nevada transferred the aforementioned geothermal power projects to the newly formed subsidiary, OPC LLC (‘‘OPC’’), and sold limited liability company interests in OPC to the institutional equity investors for $71.8 million. Ormat Nevada will continue to operate and maintain the projects and will receive initially all of the distributable cash flow generated by the projects until it recovers the capital that it has invested in the projects, while the institutional equity investors will receive substantially all of the production tax credits and the taxable income or
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
loss (together, the ‘‘Economic Benefits’’), and the distributable cash flow after Ormat Nevada has recovered its capital. The institutional equity investors’ return is limited by the term of the transaction. Once the investors reach a target after-tax yield on their investment in OPC (the ‘‘Flip Date’’), Ormat Nevada will receive 95% of both distributable cash and taxable income and the investors will receive 5% of both distributable cash and taxable income on a going forward basis. Following the Flip Date, Ormat Nevada also has the option to buy out the investors’ remaining interest in OPC at the then-current fair market value or, if greater, the investors’ capital account balances in OPC. Should Ormat Nevada exercise this purchase option, it would thereupon revert to being sole owner of the projects. The transaction provides for a second closing whereby Ormat Nevada would contribute another geothermal plant currently under construction and receive an additional amount of $46.6 million.
Under the transaction, Ormat Nevada retains the controlling voting interest in the subsidiary and therefore will continue to consolidate OPC. This transaction has been accounted for as a financing with the payments received for the equity interest recorded in minority interest on the consolidated balance sheets. As the Economic Benefits flow to the institutional equity investors, they are recognized by the Company in minority interest on the consolidated statements of operations and comprehensive income. Interest expense, representing the institutional equity investors’ targeted yield on the balance of the amount paid by the investors, is charged to minority interest.
Transaction costs amounting to $2.6 million as of September 30, 2007 have been reflected as a component of minority interest on the consolidated balance sheets and will be amortized to minority interest in the consolidated statements of operations and comprehensive income through the Flip Date.
NOTE 12 - ASSET RETIREMENT OBLIGATION
The following table presents a reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:
During 2007, the Company decreased the aggregate carrying amount of its asset retirement obligation by $5,473,000 due to decreased costs associated with drilling rigs as a result of the purchase of drilling rigs by the Company and the change in estimated useful life of part of the Company’s power plants (See Note 1). During 2006, the Company increased the aggregate carrying amount of its asset retirement obligation by $3,372,000 due to costs associated with drilling rigs, cement and cement services, general manpower, engineering fees and other outside services.
NOTE 13 - STOCK-BASED COMPENSATION
Effective January 1, 2006, the Company adopted SFAS No. 123R which establishes the accounting for employee stock-based awards. Under the provisions of SFAS No. 123R, stock-based compensation is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite employee service period (generally the vesting period of the grant). The
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Company adopted SFAS No. 123R using the modified prospective method. Under this method, prior periods are not restated and the amount of compensation cost recognized includes (i) compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation, and (ii) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123R. SFAS No. 123R requires unrecognized cost, based on the amounts previously disclosed in the Company’s pro forma footnote disclosure, related to options vesting after the date of initial adoption to be recognized in the financial statements over the remaining requisite service period. The provisions of SFAS No. 123R apply to new stock awards and stock awards outstanding, but not yet vested, on the effective date. The Company has applied the provisions of SAB No. 107 in its adoption.
Impact of the adoption of SFAS No. 123R
Upon adoption of SFAS No. 123R, the Company recognizes share-based compensation expenses associated with share awards on a straight-line basis over the requisite service period using the fair value method. The incremental share-based compensation expense recognized due to the adoption of SFAS 123R was $1.7 million for the year ended December 31, 2006.
As required by SFAS No. 123R, the Company made an estimate of expected forfeitures and is recognizing compensation costs only for those equity awards expected to vest. The cumulative effect of initially adopting SFAS No. 123R was not material. As of December 31, 2007, the total future compensation cost related to unvested stock options that are expected to vest is $6,893,000 which will be recognized over a weighted average period of 1.4 years.
During the years ended December 31, 2007 and 2006, the Company recorded stock-based compensation related to stock options as follows:
Pro forma information for periods prior to the adoption of SFAS No. 123R
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with the provisions of APB No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under APB No. 25, compensation cost was recognized based on the difference, if any, on the date of grant between the fair value of the Company’s stock and the amount an employee must pay to acquire the stock.
SFAS No. 123R requires disclosure of pro forma information for periods prior to the adoption. The pro forma disclosures are based on the fair value of awards at the grant date, amortized to expense over the service period. The following table illustrates the effect on net income and earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123 for the period prior to the adoption of SFAS No. 123R and the actual effect on net income and earnings per share for the period after the adoption of SFAS No. 123R.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Valuation assumptions
The fair value of each option grant is estimated using the Black-Scholes valuation model and the assumptions noted in the following table. The Company’s expected term represents the period that the Company’s stock-based awards are expected to be outstanding. In the absence of enough historical information, the expected term was determined using the simplified method defined in SAB No. 107, giving consideration to the contractual term and vesting schedule. Since the Company does not have any traded stock options and was listed for trading on the New York Stock Exchange beginning in November 2004, the Company’s expected volatility was calculated based on the Company’s historical volatility and for the period of time prior to the Company’s listing, the historical volatility of the Parent. There is a high correlation between the stock behavior of the Company and its Parent. The dividend yield forecast is expected to be 20% of the Company’s yearly net profit, which is equivalent to a 0.52% yearly weighted average dividend rate in the year ended December 31, 2007. The risk free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate of 5% is based on trends in actual option forfeitures.
The Company calculated the fair value of each option on the date of grant based on the following assumptions:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Option Plans
The 2004 Incentive Compensation Plan
On October 21, 2004, the Company’s Board of Directors adopted the 2004 Incentive Compensation Plan (‘‘2004 Incentive Plan’’), which provides for the grant of the following types of awards: incentive stock options, non-qualified stock options, restricted stock, stock appreciation rights, stock units, performance awards, phantom stock, incentive bonuses and other possible related dividend equivalents to employees of the Company, directors and independent contractors. Under the 2004 Incentive Plan, a total of 3,750,000 shares of the Company’s common stock have been reserved for issuance, all of which could be issued as options or as other forms of awards. Options granted to employees under the 2004 Incentive Plan cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Options granted to non-employee directors under the 2004 Incentive Plan cliff vest and are exercisable one year after the grant date. Vested shares may be exercised for up to ten years from the date of grant. The shares of common stock will be issued upon exercise of options from the Company’s authorized share capital.
The following table summarizes the status of the 2004 Incentive Plan as of and for the periods presented below (shares in thousands):
As of December 31, 2007, 2,872,323 shares of the Company’s common stock are available for future grants.
The following table summarizes information about stock options outstanding at December 31, 2007 (shares in thousands):
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock options outstanding at December 31, 2006 (shares in thousands):
The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Company’s stock price of $55.01 and $36.82 as of December 31, 2007 and 2006, respectively, which would have potentially been received by the option holders had all option holders exercised their options as of those dates. The total number of in-the-money options exercisable as of December 31, 2007 was 81,518.
The total pretax intrinsic value of options exercised during the years ended December 31, 2007 and 2006 was $1,395,000 and $331,000, respectively, based on the Company’s average stock price of $45.49 and $38.12 during the year ended December 31, 2007 and 2006, respectively.
The Parent’s Stock Option Plans
The Parent has four stock option plans: the 2001 Employee Stock Option Plan, the 2002 Employee Stock Option Plan, the 2003 Employee Stock Option Plan, and the 2004 Employee Stock Option Plan (collectively ‘‘the Parent’s Plans’’). Options under the 2004 Employee Stock Option Plan were granted in April 2004. Under the Parent’s Plans, employees of the Company were granted options in the Parent’s ordinary shares, which are registered and traded on the Tel-Aviv Stock Exchange. Options under the Parent’s Plans cliff vest and are exercisable from the grant date as follows: 25% after 24 months, 25% after 36 months, and the remaining 50% after 48 months. Vested shares may be exercised for up to five years from the date of grant. The maximum aggregate number of shares that may be optioned and sold under the Parent’s Plans is determined each year by the board of directors of the Parent, and is equal to the number of options granted during each plan year. None of the options are exercisable or convertible into shares of the Company.
As of December 31, 2007, no shares of the Parent’s ordinary shares are available for future grants.
The following table summarizes the status of the Parent’s Plans as of and for the periods presented below (shares in thousands):
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock options outstanding at December 31, 2007 (shares in thousands):
The following table summarizes information about stock options outstanding at December 31, 2006 (shares in thousands):
The aggregate intrinsic value in the above tables represents the total pretax intrinsic value, based on the Parent’s stock price of $14.96 and $11.37 as of December 31, 2007 and 2006, respectively, which would have potentially been received by the option holders had all option holders exercised their options as of those dates. The total number of in-the-money options exercisable as of December 31, 2007 and 2006 was 128,238 and 322,179, respectively.
The total pretax intrinsic value of options exercised during the year ended December 31, 2007 and 2006 was $7,217,000 and $4,328,000 based on the Parent’s average stock price of $13.03 and $9.48 during the year ended December 31, 2007 and 2006, respectively.
NOTE 14 - POWER PURCHASE AGREEMENTS
Substantially all of the Company’s electricity revenues are recognized pursuant to PPAs in the U.S. and in various foreign countries, including Kenya, Nicaragua and Guatemala. These PPAs generally provide for the payment of energy payments or both energy and capacity payments through their respective terms which expire in varying periods from 2014 to 2026. Generally, capacity payments are payments calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are payments calculated based on the amount of electrical energy delivered at a designated delivery point. The price terms are customary in the industry and include, among others, a fixed price, short-run avoided cost (‘‘SRAC’’) (the incremental cost that the power purchaser avoid by not having to generate such electrical energy itself or purchase it from others), and a fixed price with an escalation clause that includes the value for environmental attributes, known as renewable energy credits. Certain of the PPAs provide for bonus payments in the event that the Company is able to exceed certain target levels and potential payments by the Company if it fails to meet minimum target levels. One PPA gives the power purchaser or its designee the right of first refusal to acquire the geothermal power plants at fair market value. Upon satisfaction of certain conditions specified in this PPA and subject to receipt of requisite approvals and negotiations between
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the parties, the Company has the right to demand that the power purchaser acquire the power plant at fair market value. The Company’s subsidiaries in Nicaragua and Guatemala sell power at an agreed upon price subject to terms of a ‘‘take or pay’’ PPA.
Pursuant to the terms of certain of the PPAs, the Company may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall on delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined. The amount of payment required is dependent upon the level of shortfall on delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if the Company does not meet certain minimum performance requirements, the capacity of the project may be permanently reduced. The Company has not been obligated to make any material payments under its PPAs and has not had its capacity permanently reduced.
As required by EITF Issue No. 01-8 (see Note 1), the Company assessed all PPAs agreed to, modified or acquired in business combinations on or after July 1, 2003, and concluded that all such PPAs contained a lease element requiring lease accounting. Accordingly, revenue related to the lease element of the PPA is presented as ‘‘lease portion of energy and capacity’’ revenue, with the remaining revenue related to the production and delivery of the energy being presented as ‘‘energy and capacity’’ revenue in the consolidated statements of operations and comprehensive income. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2007 were as follows:
NOTE 15 - INCOME TAXES
Income before provision for income taxes, minority interest, and equity in income of investees consisted of:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of income tax expense are as follows:
The significant components of the deferred income tax benefit are as follows:
The difference between the U.S. federal statutory tax rate and the Company’s effective rate are as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The net deferred tax assets and liabilities consist of the following:
Deferred taxes are included in the consolidated balance sheets as follows:
Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income prior to expiration of the net operating loss (‘‘NOL’’) carryforwards and tax credits. Although realization is not assured, management believes it is more likely than not that the deferred tax asset at December 31, 2007 will be realized.
At December 31, 2007, the Company had U.S. federal NOL carryforwards of approximately $83.9 million and state NOL carryforwards of approximately $44.3 million, available to reduce future taxable income, which expire between 2021 and 2027 for federal NOLs and between 2014 and 2017 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2007 are available for a 20-year period and expire in 2022 and 2023. The production tax credits in the amount of $12.7 million at December 31, 2007 are available for a 20-year period and expire between 2026 and 2027.
The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $100.6 million at December 31, 2007. 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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Adoption of FIN No. 48
As disclosed in Note 1, the Company adopted the provisions of FIN No. 48 on January 1, 2007. As a result of the adoption of FIN No. 48, the Company recognized as a cumulative effect of change in accounting principle, a $328,000 increase in the liability for unrecognized tax benefits and a corresponding decrease in beginning retained earnings. This amount consists of interest and penalties related to uncertain tax positions. In addition, on January 1, 2007, the Company reclassified its liability for uncertain tax positions in the amount of $3,426,000 from long-term deferred income tax liabilities to liability for unrecognized tax benefits. During the year ended December 31, 2007, the Company increased its liability for unrecognized tax benefits by $1,576,000. The liability for unrecognized tax benefits of $5,330,000 at December 31, 2007 would impact the Company’s effective tax rate, if recognized. Interest and penalties assessed by taxing authorities on an underpayment of income taxes are included as a component of income tax provision in the consolidated statements of operations and comprehensive income.
A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:
The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2007, the Company has not been subject to U.S. federal or state income tax examinations. The Company remains open to examination by the Internal Revenue Service for the years 2000-2006 and by local state jurisdictions for the years 2002-2006.
The Company’s foreign subsidiaries remain open to examination by the local income tax authorities in the following countries for the years indicated:
Management believes that the liability for unrecognized tax benefits is adequate for all open tax years based on its assessment of many factors, including among others, past experience and interpretations of local income tax regulations. This assessment relies on estimates and assumptions and may involve a series of complex judgments about future events. As a result, it is possible that federal, state and foreign tax examinations will result in assessments in future periods. To the extent any such assessments occur, the Company will adjust its liability for unrecognized tax benefits.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Tax benefits in the U.S.
The U.S. federal government encourages production of electricity from geothermal resources through certain tax subsidies. The Company is permitted to claim in its consolidated federal tax returns either an investment tax credit for approximately 10% of the cost of each new geothermal power plant or ‘‘production tax credits’’, which in 2007 were 2.0 cents per kWh and is adjusted annually for inflation, on the first ten years of electricity output, under the Energy Policy Act of 2005 that became law on August 8, 2005. (Production tax credits can only be claimed on new plants put into service between October 23, 2004 and December 31, 2008.) The Company, as the owner of any project that would be put in service during the period ending December 31, 2008, has to choose between the production tax credit and the investment tax credit.
Certain of the Company’s PPAs that were in effect as of December 31, 2007 provide that all or a portion of the production tax credits are to be shared with the utility once they are monetized from the federal government. The Company had the ability to elect investment tax credits rather than production tax credits in its federal tax returns. In light of the terms of the original PPAs, the Company would be economically compelled to elect investment tax credits for certain facilities, thereby eliminating any amounts that would be due to the utilities under the production tax credit sharing arrangement. As such, the Company has not deferred revenue for such arrangements. In 2007, the Company reached agreements with the utilities under which the Company eliminated the production tax credit sharing provisions in exchange for a prospective reduction in the energy rate. Several of these amendments have not yet been approved by the Public Utilities Commission of Nevada (‘‘PUCN’’). The Company believes it is likely that the PUCN will approve such amendments and therefore the Company claimed the applicable production tax credits in its 2006 tax return and expects to claim the tax credits in its 2007 tax return.
On June 7, 2007, a wholly-owned subsidiary, Ormat Nevada, concluded a transaction to monetize production tax credits and other favorable tax attributes (see Note 11).
Income taxes related to foreign operations
Guatemala - The enacted tax rate is 31%. Orzunil, a wholly owned subsidiary was granted a benefit under a law which promotes development of renewable power sources. The law allows Orzunil to reduce the investment made in its geothermal project from income tax payable, which reduce the effective tax rate to zero.
Israel - The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (‘‘OSL’’), are taxed at the regular corporate tax rate of 34% in 2005, 31% in 2006, 29% in 2007, 27% in 2008, 26% in 2009 and 25% in 2010 and thereafter. OSL is entitled to ‘‘Benefited Enterprise’’ status under Israel’s Law for Encouragement of Capital Investments, 1959 (the ‘‘Investment Law’’), with respect to two of its investment programs. As a Benefited Enterprise OSL was exempt from Israeli income taxes with respect to income derived from the first benefited investment for the period from July 1, 2004 to June 30, 2006, and thereafter such income is subject to reduced Israeli income tax rates of 25% for an additional five years. OSL is also exempt from Israeli income taxes with respect to income derived from the second benefited investment for the period from January 1, 2007 to December 31, 2008 and thereafter such income will be subject to reduced Israeli income tax rates of 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between OSL and its affiliates are at arms length, and that the management and control of OSL will be from Israel during the whole period of the tax benefits. A change in control should be reported to the Israeli Tax Authorities in order to maintain the tax benefits. In addition, as an industrial company, OSL is entitled to accelerated depreciation on equipment used for its industrial activities. Under the provisions of certain tax regulations published in Israel in 2005, industrial companies whose operations are mostly ‘‘Eligible
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Operations’’ are entitled to claim accelerated depreciation at the rate of 100% on machinery and equipment acquired from July 1, 2005 to December 31, 2006. Accelerated depreciation is to be claimed over two years. In the year in which the equipment was acquired, the regular depreciation rate is to be claimed with the remainder to be claimed in the second year.
Other significant foreign countries - The Company’s operations in Nicaragua and Kenya are taxed at the rates of 25% and 37.5%, respectively.
NOTE 16 - 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 PPAs. 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.
Summarized financial information concerning the Company’s reportable segments is shown in the following tables:
* Segment assets of the Electricity Segment include unconsolidated investments.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:
The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:
(1) Revenues as reported in the geographic area in which they originate.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents revenues from major customers:
(1) Revenues reported in Electricity Segment.
NOTE 17 - 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, 2007, 2006 and 2005, fees under the agreement totaled approximately $0, $29,000 and $204,000, respectively.
The current liability due from Parent at December 31, 2007 and 2006 of $253,000 and $1,459,000, respectively, represents the net obligation resulting from ongoing operations and transactions with the Parent and is payable from available cash flow. Interest is computed on balances greater than 60 days at LIBOR plus 1% (but not less than the change in the Israeli Consumer Price Index plus 4%) compounded quarterly, and is accrued and paid to the Parent annually.
Notes payable to Parent
The Company has a loan agreement with the Parent (‘‘Parent Loan Agreement’’) pursuant to which the Company may borrow from the Parent up to $150 million in one or more advances. Interest accrues on the unpaid principal of the loan amount at a rate per annum of the Parent’s average effective interest plus 0.3% (7.5% 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, 2007 and 2006 was $57,841,000 (including current portion of $31,641,000) and $89,488,000 (including current portion of $31,647,000), respectively.
The Company also had a New Israeli Shekels (NIS) 240.0 million (equivalent to $50,665,000 as of December 31, 2006) non-interest bearing note agreement with the Parent. Since the note was payable upon demand at any time after November 30, 2007, it was presented in the consolidated balance sheet as of December 31, 2006 in current liabilities. On December 3, 2007, the note was repaid.
Future minimum payments under the notes payable to Parent as of December 31, 2007 are as follows:
Corporate and administrative services agreement with the Parent
OSL and the Parent have an agreement whereby OSL will provide to the Parent, for a monthly fee of $10,000 (adjusted annually, partially for changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, OSL agreed to provide the Parent with services of certain skilled engineers at OSL’s cost plus 10%. Such agreements may be terminated by either party after the initial term which ends in 2009.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Lease agreements with the Parent
OSL has 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 taxes and other costs to maintain the properties. The initial term of the rental agreement was 59 months expiring in June 2009. The term has been extended with the consent of the Israeli Land Administration for a period ending the earlier of: (i) 25 years (including the initial term) or (ii) the remaining period of the underlying lease agreement between the Parent and the Israel Land Administration (which terminates between 2018 and 2047).
On December 3, 2007, the Company’s Board of Directors approved a new lease transaction whereby OSL will enter into a rental agreement with the Parent for the sublease of additional manufacturing facilities that will be built adjacent to the current manufacturing facilities in Yavne, Israel. The proposed new lease transaction will end on the same day as the previous lease agreement entered into in July 2004, subject to approval by the Israel Land Administration. Pursuant to the new lease, OSL will pay a monthly rent that will result in an annual yield to the Parent of 8.5% of the Parent’s total cost with regard to the property. Payment will be adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties. The actual monthly rent payments will be set based on the actual costs incurred by the Parent with regard to the property.
Reimbursement agreement with the Parent
The Company has 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. 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 18 - EMPLOYEE BENEFIT PLAN
401(k) Plan
The Company has a 401(k) Plan (the ‘‘Plan’’) for the benefit of its U.S. employees. Employees of the Company and its U.S. subsidiaries who have completed one year of service or who had one year of service upon establishment of the Plan are eligible to participate in the Plan. Contributions are made by employees through pretax deductions up to 60% of their annual salary. Contributions made by the Company are matched up to a maximum of 2% of the employee’s annual salary. The Company’s contributions to the Plan were $264,000, $249,000 and $228,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
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 the 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 consolidated balance sheets as ‘‘Liabilities for severance pay’’. The Company has an obligation to partially fund the liabilities through regular deposits in pension funds and severance pay funds. The amounts funded amounted to $13,526,000 and $12,534,000 at December 31, 2007 and 2006, respectively, of which $11,765,000 and $10,981,000, respectively, were restricted, and have been presented on the consolidated balance sheets as part of ‘‘Deposits and other’’. The severance pay liability covered by the pension funds is not reflected in the financial statements as the severance pay risks have been irrevocably transferred to the pension funds. Under the Israeli severance pay law, restricted funds may not be withdrawn or pledged until the respective severance pay obligations have been met. As allowed under the program, earnings from the investment are used to offset severance pay costs. Severance pay expenses for the years ended December 31, 2007, 2006 and 2005 were $2,734,000, $2,454,000 and $771,000, respectively, which includes income (loss) amounting to $722,000 $1,095,000 and $(302,000), respectively, generated from the regular deposits and amounts accrued in severance funds.
The Company expects the severance pay contributions in 2008 to be approximately $1.3 million.
The Company expects to pay the following future benefits to its employees upon their reaching normal retirement age:
The above amounts were determined based on the employees’ current salary rates and the number of years’ service that will have been accumulated at their retirement date. These amounts do not include amounts that might be paid to employees that will cease working with the Company before reaching their normal retirement age.
NOTE 19 - 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
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
lessors as defined in the respective agreements. Royalties’ expense under the geothermal resource agreements were $8,370,000, $7,567,000 and $6,910,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
Letters of credit
In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling $21.5 million and $17.4 million at December 31, 2007 and 2006, respectively. Management does not expect any material losses to result from these letters of credit because performance is not expected to be required, and, therefore, is of the opinion that the fair value of these instruments is zero.
Credit agreements
On February 15, 2006, a subsidiary of the Company entered into a $25.0 million credit agreement (‘‘UBOC Credit Agreement’’) with Union Bank of California (‘‘UBOC’’). Under the UBOC Credit Agreement, the Company can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. UBOC is currently the sole lender and issuing bank under the UBOC Credit Agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the UBOC Credit Agreement as parties thereto. In connection with this transaction, the Company has entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee the subsidiary’s obligations under the UBOC Credit Agreement. The subsidiary’s obligations under the UBOC Credit Agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets. There are various restrictive covenants under the UBOC Credit Agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios. Management believes that as of December 31, 2007, the Company was in compliance with the covenants under the UBOC Credit Agreement. As of December 31, 2007, three letters of credit with an aggregated stated amount of $12.3 million were issued and outstanding under the UBOC Credit Agreement.
In September 2007, the Company entered into two separate credit agreements with two commercial banks, each for $30.0 million. In November 2007, the Company entered into an additional credit agreement with a third commercial bank for $50.0 million. Under these credit agreements, the Company or its Israeli subsidiary, OSL, can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Each of the credit agreements has a term of three years.
Loans and draws under the credit agreements or under any letters of credit will bear interest at the respective bank’s cost of funds plus a margin. The Company’s or OSL’s obligations under the credit agreements are unsecured, but both entities are subject to a negative pledge in favor of the banks and certain other customary restrictive covenants.
As of December 31, 2007 and as of the date of this annual report, no loans or letters of credits were outstanding under such credit agreements.
Restrictive covenants
The Company entered into certain agreements with Israeli Banks under which the Company and its Israeli subsidiary, OSL., have agreed to certain negative covenants, including, but not limited to, a prohibition on: (i) creating any floating charge or any permanent pledge, charge or lien over the Company’s assets without obtaining the prior written approval of the lender; (ii) guaranteeing the liabilities of any third party without obtaining the prior written approval of the lender; and
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(iii) selling, assigning, transferring, conveying or disposing of all or substantially all of the Company’s assets. In some cases, the Company and OSL have agreed to maintain certain financial ratios such as a debt service coverage ratio and a debt to equity ratio. The Company does not expect that these covenants or ratios, which apply to the Company on a consolidated basis, will materially limit its ability to execute its future business plans or operations. The failure to perform or observe any of the covenants set forth in such agreements, subject to various cure periods, would result in the occurrence of an event of default and would enable the lenders to accelerate all amounts due under each such agreement.
Purchase commitments
The Company purchases raw materials for inventories, construction-in-process and services from a variety of vendors. During the normal course of business, in order to manage manufacturing lead times and help assure adequate supply, the Company enters into agreements with contract manufacturers and suppliers that either allow them to procure goods and services based upon specifications defined by the Company, or that establish parameters defining the Company’s requirements.
At December 31, 2007, total obligations related to such supplier agreements were approximately $131.9 million (out of which approximately 118.8 million relate to construction-in-process). All such obligations are payable in 2008.
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 these grants. Such royalties amounted to $1,342,000 for the year ended December 31, 2005 (none in the years ended December 31, 2007 and 2006). The Company is not liable for royalties if the Company does not sell the respective products. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2007 and 2006, amounted to $1,175,000 and $1,138,000, respectively, of which approximately $234,000 and $277,000 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 a rate of 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 three of its senior executive officers, the terms of which expire on June 2008, with automatic extensions for successive two years in the case of the Company’s President/COO, and for one additional four-year period in the case of the Company’s CEO and the Company’s CTO. 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, 2007, excluding bonuses and benefits, was approximately $0.2 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
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2007 approximated $0.9 million.
Contingencies
During 2007, the Company’s wholly-owned subsidiary, Steamboat Geothermal LLC (‘‘SG’’), entered into a settlement agreement relating to a dispute over amounts owed to the plaintiffs under certain operating agreements. The Company paid the total settlement during 2007 and recorded additional expenses of $0.8 million.
During 2007, one of the Company’s subsidiaries entered into a settlement agreement associated with a supply contract under which the subsidiary was retained as a subcontractor to produce four waste heat energy converters. The settlement agreement provided for the release of any and all claims, demands and causes of action by and among the parties. The subsidiary was not required to make a payment to any of the parties as a result of the settlement agreement.
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 these matters cannot be predicted at this time.
The Company is a defendant in various other legal and regulatory proceedings in the ordinary course of business. It is the opinion of the Company’s management that the expected outcome of these matters, individually or in the aggregate, will not have a material effect on the financial position, results of operations and cash flows of the Company.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 20 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
* Included in interest expense for the three month period ended December 31, 2007 is an out-of-period adjustment of $394,000 related to capitalized interest that reduced interest expense. Such adjustment relates to capitalized interest costs associated with construction-in-process activities during the three month periods ended March 31, 2007, June 30, 2007 and September 30, 2007.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 21 - SUBSEQUENT EVENTS
On January 8, 2008, the Company completed an unregistered sale of 693,750 shares of common stock to the Parent, at a price of $48.08 per share. The proceeds from the unregistered sale were approximately $33.3 million. The shares of common stock issued in the unregistered sale have not been and will not be registered under the Securities Act of 1933, as amended, or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933, as amended.
On February 26, 2008, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.1 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 14, 2008, payable on March 27, 2008.
Ormat Leyte Co. Ltd.
A Limited Partnership
Financial Statements
December 31, 2005
(With Comparative Unaudited Figures
for 2007 and 2006)
(In United States Dollars)
and
Report of Independent Registered Public Accounting Firm
December 31, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Ormat Leyte Co. Ltd.
We have audited the statements of income, changes in partners’ equity and cash flows of Ormat Leyte Co. Ltd. (a Philippine limited partnership) (the Partnership) for the year ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations of Ormat Leyte Co. Ltd. and its cash flows for the year ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.
Makati City, Philippines
March 27, 2006
SGV & Co is a member practice of Ernst & Young Global
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
UNAUDITED BALANCE SHEETS
See accompanying Notes to Financial Statements.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
STATEMENTS OF INCOME
See accompanying Notes to Financial Statements.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
STATEMENTS OF CHANGES IN PARTNERS’ EQUITY
See accompanying Notes to Financial Statements.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
STATEMENTS OF CASH FLOWS
See accompanying Notes to Financial Statements.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
1. Company Information
Ormat Leyte Co. Ltd. (OLCL), a Philippine limited partnership (the Partnership), was registered with the Philippine Securities and Exchange Commission (SEC) to engage in power production. Prior to September 25, 2007, the termination date of the Build-Operate-and-Transfer (BOT) Agreement with Philippine National Oil Company-Energy Development Corporation (PNOC-EDC), it owned and operated geothermal electricity-generating facilities in Leyte Province, Philippines for the production and sale of electricity from geothermal resources (see Note 2).
The partners in this Partnership are:
The net income of the Partnership is allocated to the partners based on each partner’s respective percentage of ownership.
OLCL is registered with the Philippine Board of Investments as an operator of power generating plants on a pioneer status under the Omnibus Investments Code of 1987 (otherwise known as Executive Order No. 226). As a registered enterprise, OLCL is entitled to certain tax and nontax incentives under the provisions of the Code subject to certain requirements under the terms of its registration. No incentive was availed by the Partnership in 2007, 2006 and 2005.
2. BOT Agreement and Status of Operation
BOT Agreement
On February 15, 1996, OLCL entered into an Accession Undertaking in connection with the BOT Agreement between Ormat, Inc., an affiliate company, and PNOC-EDC, a wholly-owned subsidiary of Philippine National Oil Company, whereby Ormat, Inc. assigned to OLCL all its rights and benefits under the BOT Agreement. The undertaking provides that OLCL shall design, construct, own and operate four geothermal electricity-generating plants with a total contracted capacity of 50 megawatts (MW) through the utilization of the geothermal resources of the Leyte Geothermal Power Optimization Project Area (Project).
The BOT Agreement provided that OLCL shall own, operate and maintain the power plants for the purpose of converting the steam delivered by PNOC-EDC into electric energy required by the National Power Corporation (NPC) in accordance with the power purchase agreement between NPC and PNOC-EDC during the cooperation period. OLCL billed PNOC-EDC for the delivery of electric power and energy the amount of Capacity Fee which is the sum of the Fixed Operating Cost Recovery (the peso portion is payable in Philippine peso and the United States (U.S.) dollar portion is payable in U.S. dollar), Service Fee for Return on Investment (stated in U.S. dollar and payable either in U.S. dollar or Philippine peso) and Capital Cost Recovery (stated and payable in U.S. dollar); and Energy Fee computed based on an agreed formula (stated and payable in Philippine peso), until the termination of the BOT Agreement in September 2007. The day following the end of the cooperation period, title to the power plants were transferred to PNOC-EDC, after PNOC-EDC has made all payments required pursuant to the BOT Agreement.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
There were four power plants in the Leyte facility namely: Mahanagdong A, Mahanagdong B, Tongonan and Malitbog. The total costs to construct the power plants amounted to
$56.67 million.
Status of Operation
On July 30, 2007, OLCL made its last amortization payment for its long-term loan (see Note 7). Upon the termination of the BOT Agreement on September 25, 2007, OLCL collected all its receivables from PNOC-EDC, except for the disputed energy fees amounting to $0.72 million which was fully covered by allowance for doubtful debts. Accordingly, the amount was written-off against allowance.
Also on September 25, 2007, OLCL and PNOC-EDC executed a Deed of Transfer whereby OLCL transfers to PNOC-EDC on an ‘‘as is’’ basis, all its rights, title and interest in and to the power plants and all its fixtures, fittings, equipment, spare parts, appurtenances and improvements, free from all liens and encumbrances created by OLCL.
OLCL also separated its employees, disposed of most of its remaining fixed assets and assigned the existing lease agreement of the office space in Ormoc to Ormat Inc. - Manila Branch (OMB), a related party.
As of December 31, 2007, OLCL’s current assets exceeded its current liabilities by $309,335. It also has a net partners’ equity of $680,362. The remaining assets of OLCL consist mainly of cash, receivables from related parties and input value-added tax (VAT) receivables, while liabilities consist of accrued expenses, due to related parties and income tax payables. OLCL has sufficient cash to settle the remaining obligations.
As of December 31, 2007 or twelve months thereafter, Management has no plans to liquidate or dissolve the partnership. It is still in the process of evaluating viability of entering into future new projects.
3. Summary of Significant Accounting Policies
Basis of Preparation
The financial statements include the financial position, results of operations and cash flows of OLCL. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles and presented in U.S. dollars, the functional currency of OLCL.
Use of Estimates
The preparation of the financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities at the date of the financial statements and the reported amount of revenue and expenses during the reporting period. Actual results could differ from such estimates.
Adoption of New Accounting Standard
Effective January 1, 2007, OLCL adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes. This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This Interpretation also improves financial reporting since it increases relevance and comparability in financial reporting of income taxes because all tax positions accounted for in accordance with SFAS No. 109 is evaluated for recognition, derecognition, and measurement using consistent criteria. Finally, the disclosure provisions of this Interpretation provide more information about the uncertainty in income tax assets and liabilities.
The adoption of FIN 48 did not result in any adjustments to the beginning balance of the accumulated net income nor did it have any impact on OLCL’s financial statements for the year ended December 31, 2007. Additional disclosures, where applicable, are included in Note 15 to the financial statements.
Cash and Cash Equivalents
Cash includes cash on hand and in banks. OLCL considers all highly liquid investments with original maturity of three months or less at the time of purchase to be cash and cash equivalents.
Accounts Receivable
Accounts receivable are recognized and carried at original invoice amount less an allowance for any uncollectible amounts. An estimate for doubtful debts is made when collection of the full amount is no longer probable.
Property, Plant and Equipment
Property, plant and equipment are carried at cost less accumulated depreciation and any impairment in value. The cost of power plants consists of expenditures incurred in connection with the design and construction of the power plants. Cost also includes capitalized interests on borrowed funds used to finance the construction of the power plants during the construction period.
For the years ended December 31, 2007, 2006 and 2005, no interest was capitalized.
Depreciation of the power plants is computed on the straight-line method over a period of
10 years, which is the cooperation period stipulated in the BOT Agreement. Depreciation of the other property and equipment is computed on the straight-line method over the estimated useful lives of the assets as follows:
Transportation equipment
5 years
Furniture, fixtures and equipment
3 years
The cost of routine repairs and maintenance is charged to income as incurred; major enhancements and improvements are capitalized. When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation and impairment losses, if any, are removed from the accounts and any resulting gain or loss is credited to or charged against current operations.
Impairment of Long-lived Assets
Long-lived assets are accounted for in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-lived Assets. OLCL periodically evaluates its long-lived assets for events or changes in circumstances that might indicate that the carrying amount of the assets may not be recoverable. OLCL assesses the recoverability of the assets by determining whether the amortization of such long-lived assets over their estimated useful lives can be recovered through projected undiscounted future cash flows. The amount of impairment, if any, is measured based on the fair value of the assets. Based on OLCL’s review, as of December 31, 2007, 2006 and 2005, no impairment of assets has occurred.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
Deferred Costs
Credit exposure fees paid in relation to the term loan, included under the Other noncurrent assets account in the balance sheets, are deferred and amortized over the term of the loan up to
July 2007 using the effective interest rate method.
Prepaid Input Value-Added Taxes
Prepaid input VAT represent VAT imposed on OLCL by its suppliers for the acquisition of goods and services required under Philippine tax laws and regulations.
The input VAT is recognized as an asset and will be claimed as tax credits/refunds. Input taxes are stated at their estimated net realizable values.
Revenue Recognition
Pursuant to Emerging Issues Task Force Issue No. 01-8, Determining Whether an Arrangement Contains a Lease, and SFAS No. 13, Accounting for Leases, the arrangements of the BOT Agreement should be accounted for as an operating lease. The BOT Agreement does not provide for any minimum payments.
Operating revenue consists of Capacity and Energy Fees for the energy and services supplied by OLCL to PNOC-EDC as provided for in the BOT Agreement and revenue is recognized to the extent that it is probable that the economic benefits associated with the transaction will flow to OLCL and the amount of revenue can be reliably measured. Capacity Fee is the sum of the Fixed Operating Cost Recovery, Service Fee for Return on Investment and Capital Cost Recovery (see Note 2). The Capacity Fee component in OLCL’s BOT Agreement with PNOC-EDC is recognized based on the generation of electricity using the agreed formula in the BOT Agreement which takes into account, among other factors, the nominated capacity, contracted capacity, outage hours and an agreed fixed rate per kilowatt hour. Energy Fee is recognized based on the actual delivery of electricity generated and made available to PNOC-EDC in excess of the agreed efficiency rate in converting the steam delivered by PNOC-EDC into electric energy.
Interest on cash and restricted cash is recognized as the interest accrues computed using the effective interest rate method.
Separation Benefits
OLCL accrues the cost of separation benefits that the employees are entitled to receive at the termination of the BOT Agreement computed using the projected unit credit method. These benefits are unfunded. Starting December 31, 2006, actuarial gains and losses are charged to or credited against ‘‘Other comprehensive income’’ in the statement of partners’ equity. Previously, actuarial gains and losses were taken to income. Upon settlement of the separation benefits in September 2007, the actuarial gains amounting to $18,997 (and the related $6,961 in taxes) included in ‘‘Other comprehensive income’’ were reclassified to the 2007 statement of income.
Borrowing Costs
Borrowing costs are generally expensed as incurred. Borrowing costs are capitalized if directly attributable to the acquisition, construction or production of a qualifying asset. Capitalization of borrowing costs commences when the activities to prepare the asset are in progress and expenditures and borrowing costs are being incurred. Borrowing costs are capitalized until the assets are ready for their intended use. If the resulting carrying amount of the asset exceeds its recoverable amount, an impairment loss is recorded. Borrowing costs eligible for capitalization are the interest costs recognized on borrowings and other obligations.
Income Taxes
OLCL follows the liability method in accounting for income taxes. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to the temporary
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
differences between the financial reporting bases of assets and liabilities and their related tax bases. Deferred income tax assets and liabilities are measured using the enacted tax rate expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is provided when based on the weight of available evidence, it is more likely than not that a portion or all of the deferred income tax assets will not be realized in the future.
Foreign Currency Transactions
Transactions in foreign currencies are initially recorded in U.S. dollars based on the exchange rates prevailing at the transaction dates. Foreign currency-denominated monetary assets and liabilities are translated to U.S. dollars at exchange rates prevailing at the balance sheet dates. Exchange gains or losses arising from the translation or settlement of foreign currency denominated monetary assets and liabilities at exchange rates different from those at which the assets and liabilities are initially recorded, are credited to or charged against current operations.
Impact of Recently Issued Accounting Standards
In September 2006, FASB issued SFAS No. 157, Fair Value Measurement, which provides guidance for using fair value to measure assets and liabilities. It also responds to investors’ request for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value and the effect of fair value measurements on earnings. It applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. It does not expand the use of fair value in any new circumstances. This Statement shall be effective for financial statements issued for fiscal years beginning after November 15, 2007.
In February 2007, the FASB also issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This Statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement is expected to expand the use of fair value measurement, which is consistent with the FASB’s long-term measurement objectives for accounting for financial instruments. This Statement shall be effective as of the beginning of each reporting entity’s first fiscal year that begins after November 15, 2007. This Statement should not be applied retrospectively to fiscal years beginning prior to the effective date, except as permitted in paragraph 30 of this Statement for early adoption.
Adoption of these standards is not expected to be material for OLCL.
In December 2007, the FASB issued the following new and revised SFAS which are not yet effective as of December 31, 2007:
• SFAS No. 141 (R), Business Combinations, which replaces SFAS No. 141, Business Combinations. This Statement retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. This Statement shall be effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. This Statement is not applicable to OLCL as it does not have any business combination transactions.
• SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements, which aims to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This Statement shall be effective for annual periods beginning after December 15, 2008. This Statement is not applicable to OLCL and will have no impact on the financial statements.
4. Cash and Restricted Cash
Restricted cash totalling $3.57 million as of December 31, 2006, represents the cash reserves under the Credit Agreement which was used to pay the loan amortizations for the two quarters of 2007 (see Note 7).
Upon payment by OLCL of the last quarterly amortization of the term loan with Export-Import Bank of the United States (Eximbank) in July 2007, the restricted cash was released and transferred to OLCL’s unrestricted cash account.
5. Other Noncurrent Assets
6. Property, Plant and Equipment
The power plants, which were depreciated over the 10-year cooperation period, were turned over to PNOC-EDC on September 25, 2007, the end of the cooperation period stipulated in the BOT Agreement. The carrying amounts of the power plants as of December 31, 2006 were $4.19 million.
Total depreciation charged to operations amounted to $4.22 million in 2007 and $5.73 million both in 2006 and 2005.
Interest expense capitalized up to the completion of the power plants in 1997, net of accumulated depreciation of $1.73 million and $1.55 million, amounted to $0.15 million and $0.33 million as of December 31, 2006 and 2005, respectively. The carrying value of capitalized interest as of December 31, 2006 of $0.15 million was charged to depreciation expense in the 2007 statement of income.
Upon full payment of the long-term loan in July 2007, the mortgage on all power plants pledged to secure the payment of the long-term loan payable was released (see Note 7).
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
7. Long-term Loan Payable
The outstanding long-term loan payable amounting to $3.81 million as of December 31, 2006 was paid in full on July 30, 2007.
In 1998, the loan payable pertained to the construction credit facility extended by a syndicate of lenders to partially finance the cost of construction of 50 MW power plants in Leyte, Philippines.
The Eximbank provided a guarantee and agreed to re-finance the loan (i.e., conversion of this construction loan into a term loan upon completion of the reliability tests on the power plants) made by the lenders under the Credit Agreement.
The construction loan was converted into a term loan with Eximbank on January 21, 1999. The loan’s principal balance is payable in 35 equal, successive quarterly installments of $1.27 million starting February 1, 1999 plus interest at 6.54% a year. The principal balance was exclusive of credit exposure fees which amounted to $0.23 million (net of accumulated amortization of $3.65 million) as of December 31, 2006. The unamortized balance of credit exposure fees as of December 31, 2006 was included under the Other noncurrent assets account in the 2006 balance sheet (see Note 5). The credit exposure fee was fully amortized in July 2007, the end of the term loan with Eximbank.
The loan was collateralized by a mortgage on OLCL’s power plants, assignment of revenues and pledge of partnership interests of OPI and OC in OLCL.
The loan agreement provided, among other terms and conditions, that, for as long as the loan remains outstanding, OLCL is subject to certain negative covenants requiring prior written bank approval for specified partnership acts which include, but are not limited to mortgage of properties; consolidation, merger and sale of assets; declaration or payment of partnership distributions, return of capital or redemption, retirement, purchase or acquisition of partnership interests; entering into lease-purchase and guarantee agreements; contracting indebtedness; forming or having any subsidiaries; granting of loans or advances; entering into any new management contracts; amendment of Articles of Partnership and other organization documents, i.e., changing its fiscal year and materially changing the nature of its present business; and abandonment of the Project. In addition, the agreement provides that OLCL’s equity-to-debt ratio should not be less than 25:75 at any time. OLCL was in compliance with all the negative covenants throughout the term of the loan.
8. Accrued Expenses
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
9. Related Party Transactions
Transactions with related parties are as follows:
a. Technical and managerial support services agreement with Ormat Systems Ltd. (OSL), an affiliate company, for one year starting October 1997, renewable yearly, until 2007, for a monthly fee of $10,000, escalated using the indexes as defined in the agreement (see Note 11). After the termination of the BOT Agreement in September 2007, no billing for technical and managerial support services was received from OSL.
b. Operation, maintenance, general and administration support services agreement with Ormat, Inc. - Manila Branch (OMB), an affiliate company, for a monthly service fee of $16,500 both in 2007 and 2006 and $14,545 in 2005 with the same terms as the agreement with OI (see Notes 11 and 12). After the termination of the BOT Agreement in September 2007, no billing for operation and maintenance support services was received from OMB.
c. OLCL has noninterest-bearing short-term cash advances to (from) related companies, with no fixed repayment terms, and reimbursement of expenses to related parties.
Amounts due from (to) related parties follow:
10. Partners’ Equity
a. OLCL returned equity to partners distributed in proportion to their respective contribution as follows:
There was no equity distribution to partners in 2007.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
b. OLCL distributed income to partners as follows:
11. Costs of Power Plants Operations
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
12. General and Administrative Expenses
13. Separation Benefits
OLCL had a separation benefits policy that entitles its employees to a separation pay upon the termination of the BOT Agreement, equivalent to one month of the employee’s basic salary for every year of service for employees or a minimum of one and one fourth (1-1/4) month’s salary for every year of service for certain qualified employees. The separation benefits were unfunded.
On September 25, 2007, upon the termination of the BOT Agreement, OLCL transferred 13 of its employees to OMB and separated all other employees. OLCL paid the separation benefits of all employees either directly to the employees or to OMB (for those employees transferred to OMB).
Following is the movement of OLCL’s separation benefits liabilities included under the Accrued expenses account in the balance sheets:
In 2006, upon adoption of SFAS 158, the unrecognized actuarial gains were credited to ‘‘Other comprehensive income.’’ In 2007, the unrecognized actuarial gains in 2006 which amounted to $18,997 was reclassified to ‘‘Other income’’ in the 2007 statement of income.
The principal assumptions used in determining the separation benefits liabilities follow:
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
14. Other Income
Other income for the years ended December 31, 2007 and 2006 consists of:
15. Income Taxes
a. Deferred income tax assets relate to the following:
b. The provision for income tax - deferred consists of the following:
In 2004, based on the then position of the tax authorities on the tax treatment of foreign exchange differentials by taxpayers adopting the use of functional currency other than the Philippine peso financial statements, it was considered unlikely that the related temporary difference would be deductible against future taxable income. Thus, a valuation allowance amounting to $1,369,898 was provided on the deferred income tax asset relating to unrealized foreign exchange loss on the long-term loan in 2004. However, in 2005, the tax authorities
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
changed their earlier position which rendered the temporary difference to be deductible against future taxable profits. Consequently, the valuation allowance on the deferred income tax asset in 2004 was reversed in 2005.
c. The reconciliations of the income tax expense computed by applying the statutory income tax rates to the income before income tax and the income tax expense as shown in the statements of income is summarized as follows:
The statutory income tax rates stood at 32% during the period up to October 31, 2005 and was increased to 35% from November 1, 2005 (Note d).
Computation of income tax expense is based on the books of accounts expressed in Philippine peso in accordance with Philippine tax laws. Prior to January 1, 2005, the carrying value of OLCL’s power plants in its books expressed in Philippine peso included undepreciated capitalized unrealized foreign exchange losses; the related depreciation charged to income was not considered a deductible tax item and was added back to ‘‘income tax at statutory income tax rates’’ in the reconciliation of income tax expense. Starting on January 1, 2005, OLCL reversed in its books of accounts expressed in Philippine peso the balance of undepreciated capitalized unrealized foreign exchange losses.
d. On May 24, 2005, the new Expanded Value-Added Tax (E-VAT) law was signed as Republic Act No. 9337 or the E-VAT Act of 2005. The E-VAT law took effect on November 1, 2005 following the approval on October 19, 2005 of Revenue Regulations 16-2005 which provides for the implementation of the rules and regulations of the new E-VAT law. This provides for the change in corporate income tax rate from 32% to 35% for the next three years effective on November 1, 2005, and 30% starting January 1, 2009 and thereafter, among others. OLCL’s deferred income tax assets in 2005 were measured using tax rates expected to apply for the years when the deferred income tax assets are expected to be realized.
The E-VAT law also provides for the increase in the VAT rate from 10% to 12%, subject to certain conditions. The increase in VAT rate to 12% became effective on February 1, 2006.
On October 9, 2006, RA No. 9361 ‘‘An Act Amending Section 110(B) of the National Internal Revenue Code of 1997, as Amended, for Other Purposes’’ was passed by the House of Senate, removing the 70% cap on input VAT.
e. OLCL’s tax years 2004, 2005, and 2006 remain open to examination by the tax authorities.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
16. Insurance Recovery of the Tongonan and Malitbog Plants
a. On July 11, 2004, the main step-up transformer of the Tongonan topping plant sustained damage, putting this plant into outage condition. Upon the insurance company’s instruction, OLCL procured a temporary unit located in the Philippines and on September 19, 2004, the plant’s normal operation was restored.
OLCL filed with its insurer claim for material damage on the costs incurred related to the damaged transformer in excess of $50,000 and for business interruption cover in excess of 30 days. OLCL did not recognize a receivable from the insurer as of December 31, 2004 since the insurer did not confirm the claim as of that date.
On May 26, 2005, OLCL recovered its insurance claims and credited $850,000 to the Recovery from insurance account in the 2005 statement of income.
In 2005, OLCL accrued $100,000 for the repair of the transformer and debited the recovery from insurance account for the same amount in the 2005 statement of income. In 2007, PNOC-EDC accepted the transformer at its current state and OLCL reversed the accrued repair cost to income in the 2007 statement of income (Notes 8 and 14).
b. On August 19, 2004, the generator at the Malitbog plant tripped placing the plant under the outage condition beginning that date. On January 8, 2005, the plant’s normal operation resumed after the generator rotor was repaired.
OLCL filed for material damage claim on the cost of the generator repair in excess of $50,000 and for business interruption cover in excess of 30 days. OLCL recognized a receivable of $1,200,000 as of December 31, 2004 since the insurer confirmed the claim and made an interim payment in January 2005. On April 13, 2005, OLCL recovered from the insurer $1,327,841 of which $1,200,000 was applied against the receivable set up in 2004 and the excess amount of $127,841 was credited to the Recovery from insurance account in the 2005 statement of income.
17. Fair Values of Financial Instruments
The following table sets forth the carrying values and estimated fair values of OLCL’s financial instruments (unaudited) recognized as of December 31, 2007 and 2006:
The carrying amount of cash and restricted cash approximates their fair values since these are available for working capital and debt service requirements. The carrying amount of accounts receivable subject to normal credit terms, approximates its fair value. The carrying amounts of due from related parties, accrued expenses, and due to related parties approximate fair values due to the short-term nature of these accounts.
ORMAT LEYTE CO. LTD.
(A LIMITED PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
The fair value of long-term debt as of December 31, 2006 already approximated its carrying value since the loan was already currently payable on such date.
18. Other Matters
a. Electric Power Industry Reform Act
Philippine Republic Act No. 9136, the Electric Power Industry Reform Act of 2001 (EPIRA), and the covering Implementing Rules and Regulations (IRR) provide for significant changes in the power sector, which include among others:
i. The unbundling of the generation, transmission, distribution and supply, and other disposable assets of a company, including its contracts with independent power producers, and electricity rates;
ii. Creation of a Wholesale Electricity Spot Market; and
iii. Open and non-discriminatory access to transmission and distribution systems.
The law also requires public listing of not less than 15% of common shares of generation and distribution companies within five years from the effectivity of the EPIRA. It provides cross ownership restrictions between transmission and generation companies and between transmission and distribution companies, and a cap of 50% of its demand that a distribution utility is allowed to source from an associated company engaged in generation, except for contracts entered into prior to the effectivity of the EPIRA.
There are also certain sections of the EPIRA, specifically relating to generation companies, which provide for: (a) cap on the concentration of ownership to only 30% of the installed capacity of the grid and/or 25% of the national installed generating capacity; and (b) value-added tax zero-rating of sale of generated power (see Note 15).
Based on the assessment of OLCL, it has complied with the applicable provisions of the EPIRA and its IRR.
b. Clean Air Act
The Clean Air Act and the related IRR contain provisions that have an impact on the industry as a whole, and on OLCL in particular, that need to be complied with within 44 months from the effectivity date or by July 2004. Based on the initial assessment made on its power plants’ existing facilities, OLCL believes it complies with the provisions of the Clean Air Act and the related IRR.
c. Real Property Tax Assessment
On July 9, 2007, the Local Board of Assessment Appeals of the Leyte Province issued an order dismissing the real property tax assessment it issued to OLCL amounting to $233,548 since it became moot and academic in view of the Compromise Agreement between the Sanggunian Panlalawigan of the Province of Leyte and PNOC-EDC.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. DISCLOSURE CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Company’s management, including its Chief Executive Officer and Chief Financial Officer, have conducted an evaluation of the effectiveness of disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’), as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2007, that the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this Annual Report on Form 10-K has been recorded, processed, summarized and reported when required and the information is accumulated and communicated, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
No changes in the Company’s internal control over financial reporting, as defined in Rules 13a-15(f) under the Exchange Act, have been identified during the Company’s fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined under Rule 13a-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Management, under the supervision and participation of the Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 using criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and concluded that the Company maintained effective internal control over financial reporting as of December 31, 2007.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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 2007 Proxy Statement.
Directors and Executive Officers Information
The following table sets forth the name, age and positions of our directors, executive officers and persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:
Name
Age
Position
Lucien Bronicki
Chairman of the Board of Directors;
Chief Technology Officer(3)
Yehudit ‘‘Dita’’ Bronicki
Chief Executive Officer; Director(2)
Yoram Bronicki
President; Chief Operating Officer;
Director(1)
Joseph Tenne
Chief Financial Officer*
Nadav Amir
Executive Vice President - Engineering*
Zvi Reiss
Executive Vice President - Project Management*
Joseph Shiloah
Executive Vice President - Marketing and Sales, Rest of the World*
Aaron Choresh
Vice President - Operations Rest of the World and Product Support*
Zvi Krieger
Senior Vice President - Geothermal Engineering*
Shimon Hatzir
Senior Vice President - Electrical and Conceptual Engineering, Ormat Systems*
Etty Rosner
Senior Vice President - Contract Management;
Corporate Secretary*
Independent Directors:
Dan Falk
Independent Director(3)
Jacob J. Worenklein
Independent Director(2)
Roger W. Gale
Independent Director(1)
Robert F. Clarke
Independent Director(2)
* Performs the functions described in the table, but is employed by Ormat Systems.
(1) Denotes Class I Director - Term expiring at 2008 Annual Shareholders Meeting.
(2) Denotes Class II Director - Term expiring at 2009 Annual Shareholders Meeting.
(3) Denotes Class III Director - Term expiring at 2010 Annual Shareholders Meeting.
Lucien Bronicki. Lucien Bronicki is the Chairman of our Board of Directors, a position he has held since our inception in 1994, and has also been our Chief Technology Officer since July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the Board of Directors of Ormat Industries Ltd., the publicly-traded successor to Ormat Turbines Ltd., and several of its subsidiaries. From 1999 to April 2006, Mr. Bronicki served as the Chairman of the Board of Directors of OPTI Canada Inc., a company engaged in the oil sands industry in Canada in which our parent owns an approximately 5% interest. From 1992 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Engines, a manufacturer of jet engines, and from 1997 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Holdings. Mr. Bronicki was also the Chairman of the Board of Directors of Orad Hi-Tec Systems Ltd., a manufacturer of image processing systems, until the end of 2005, and was the Co-Chairman of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit
boards and display panels. Mr. Bronicki has worked in the power industry since 1958. He is a member of the Executive Council of the Weizmann Institute of Science and was the Chairman of the Israeli Committee of the World Energy Council. Yehudit Bronicki and Lucien Bronicki are married and are the parents of Yoram Bronicki. Mr. Bronicki obtained a postgraduate degree in Nuclear Engineering from Conservatoire National des Arts et Metiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from Ecole Nationale Superieure d’Ingenieurs Arts et Metiers. In the year 2005, he received a Ph.D. Honoris Causa from the Ben-Gurion University, and in 2006 from the Weizmann Institute of Science.
Yehudit ‘‘Dita’’ Bronicki. Yehudit Bronicki has been our Chief Executive Officer since July 1, 2004, and is also a member of our Board of Directors. From July 1, 2004 to September 20, 2007 she was also our President. Mrs. Bronicki was also a co-founder of Ormat Turbines Ltd. and is a member of the Board of Directors and the General Manager (a CEO-equivalent position) of Ormat Industries Ltd., the publicly traded successor to Ormat Turbines Ltd., and several of its subsidiaries. From 1992 to June 2005, Mrs. Bronicki was a director of Bet Shemesh Engines, a manufacturer of jet engines. In addition, Mrs. Bronicki was a member of the Board of Directors of OPTI Canada Inc. until May 2005 and is a member of the Board of Orbotech Ltd., a NASDAQ-listed manufacturer of equipment for inspecting and imaging circuit boards and display panels. From 1994 to 2001, Mrs. Bronicki was on the Advisory Board of the Bank of Israel. Mrs. Bronicki has worked in the power industry since 1965. Yehudit Bronicki and Lucien Bronicki are married and are the parents of Yoram Bronicki. Mrs. Bronicki obtained a Bachelor of Arts in Social Sciences from Hebrew University in 1965.
Yoram Bronicki. Yoram Bronicki has been a member of our Board of Directors since November 12, 2004, and has been our President and Chief Operating Officer since September 20, 2007. From July 1, 2004 to September 20, 2007, Mr. Bronicki was our Chief Operating Officer, North America. Mr. Bronicki is also a member of the Board of Directors of Ormat Industries Ltd., a position he has held since 2001, and a member of the Board of Directors of OPTI Canada Inc. From 2001 to 2004, Mr. Bronicki was Vice President of OPTI Canada Inc.; from 1999 to 2001, he was Project Manager of Ormat Industries Ltd. and Ormat International; from 1996 to 1999, he was Project Manager of Ormat Industries Ltd.; and from 1995 to 1996, he was Project Engineer of Ormat Industries Ltd. Mr. Bronicki is the son of Lucien and Yehudit Bronicki. Mr. Bronicki obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1989 and a Certificate from the Technion Institute of Management Senior Executives Program.
Joseph Tenne. Joseph Tenne has served as our Chief Financial Officer since March 9, 2005. From 2003 to 2004, Mr. Tenne was the Chief Financial Officer of Treofan Germany GmbH & Co. KG, a German company. From 1997 until 2003, Mr. Tenne was a partner in Kesselman & Kesselman, Certified Public Accountants in Israel (a member firm of PricewaterhouseCoopers International Limited). Since January 8, 2006, Mr. Tenne has also been the Chief Financial Officer of Ormat Industries Ltd. Mr. Tenne is a member of the board of directors of AudioCodes Ltd., a NASDAQ-listed company. Mr. Tenne obtained a Master of Business Administration from Tel Aviv University in 1987 and a Bachelor of Arts in Accounting and Economics from Tel Aviv University in 1981. Mr. Tenne is also a Certified Public Accountant in Israel.
Nadav Amir. Nadav Amir has served as our Executive Vice President of Engineering, since July 1, 2004. From 2001 through June 30, 2004, Mr. Amir was Executive Vice President of Engineering of Ormat Industries; from 1993 to 2001, he was Vice President of Engineering of Ormat Industries Ltd.; from 1988 to 1993, he was Manager of Engineering of Ormat Industries Ltd.; from 1984 to 1988, he was Manager of Product Engineering of Ormat Industries Ltd.; and from 1983 to 1984, he was Manager of Research and Development of Ormat Industries. Mr. Amir obtained a Bachelor of Science in Aeronautical Engineering from Technion Haifa in 1972.
Zvi Reiss. Zvi Reiss has served as our Executive Vice President of Project Management since July 1, 2004. From 2001 through June 30, 2004, Mr. Reiss was the Executive Vice President of Project Management of Ormat Industries Ltd.; from 1995 to 2000, he was Vice President of Project
Management of Ormat Industries Ltd. and, from 1993 to 1994, he was Director of Projects of Ormat Industries Ltd. Mr. Reiss obtained a Bachelor of Science in Mechanical Engineering from Ben Gurion University in 1975.
Joseph Shiloah. Joseph Shiloah has served as our Executive Vice President of Marketing and Sales, Rest of the World, since July 1, 2004. From 2001 through June 30, 2004, Mr. Shiloah was the Executive Vice President of Marketing and Sales at Ormat Industries Ltd.; from 1989 to 2000, he was Vice President of Marketing and Sales of Ormat Industries Ltd.; from 1983 to 1989, he was Vice President of Special Projects of Ormat Turbines Ltd.; from 1984 to 1989, he was Operating Manager of the Solar Pond project of Solmat Systems Ltd., a subsidiary of Ormat Turbines Ltd.; and from 1981 to 1983, he was Project Administrator of the Solar Pond power plant project of Ormat Turbines Ltd. and Solmat Systems Ltd. Mr. Shiloah obtained a Bachelor of Arts in Economics from Hebrew University in 1972.
Aaron Choresh. Aaron Choresh has served as our Vice President of Operations Rest of the World and Product Support, since July 1, 2004. From 1999 through June 30, 2004, Mr. Choresh was the Vice President of Operations and Product Support of Ormat Industries Ltd.; from 1993 to 1998, he was the Director of Operations and Product Support of Ormat Industries Ltd.; from 1991 to 1992, he was Manager of Project Engineering and Product Support; and from 1989 to 1990, he was Manager of Project Engineering of Ormat Industries Ltd.. Mr. Choresh obtained a Bachelor of Science in Electrical Engineering from Technion Haifa in 1982.
Zvi Krieger. Zvi Krieger has served as our Senior Vice President of Geothermal Engineering, since September 20, 2007; from July 1, 2004 to September 20, 2007, Mr. Krieger was our Vice President of Geothermal Engineering and from 2001 through June 30, 2004, he was the Vice President of Geothermal Engineering of Ormat Industries Ltd. Mr. Krieger has been with Ormat Industries Ltd. since 1981 and served as Application Engineer, Manager of System Engineering, Director of New Technologies Business Development and Vice President of Geothermal Engineering. Mr. Krieger obtained a Bachelor of Science in Mechanical Engineering from the Technion, Israel Institute of Technology in 1980.
Shimon Hatzir. Shimon Hatzir has served as our Senior Vice President of Electrical and Conceptual Engineering, since September 20, 2007. From July 1, 2004 to September 20, 2007, Mr Hatzir was our Vice President of Electrical and Conceptual Engineering and from 2002 through June 30, 2004; he was the Vice President of Electrical and Conceptual Engineering of Ormat Industries Ltd.. From 1996 to 2001, Mr. Hatzir was Manager of Electrical and Conceptual Engineering of Ormat Industries Ltd., and from 1989 to 1995, he was Project Engineer in the Engineering Division. Mr. Hatzir obtained a Bachelor of Science in Mechanical Engineering from Tel Aviv University in 1988 and a Certificate of the Technology Institute of Management, Senior Executive Program.
Etty Rosner. Etty Rosner has served as our Corporate Secretary, since October 21, 2004. Ms. Rosner is also the Corporate Secretary of Ormat Industries Ltd., a position she has held since 1991. Ms. Rosner is also our Senior Vice President of Contract Management since September 20, 2007; from July 1, 2004 to September 20, 2007, Ms. Rosner was our Vice President of Contract Management and from 1999 through June 30, 2004, she was the Vice President of Contract Management of Ormat Industries Ltd. From 1991 to 1999, Ms. Rosner was Contract Administration Manager and Corporate Secretary of Ormat Industries and from 1981 to 1991, she was the Manager of the Export Department and Office Administrative Manager of Ormat Industries. Ms. Rosner obtained a Diploma in General Management from Tel Aviv University in 1990.
Dan Falk. Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity Ltd., ClickSoftware Technologies Ltd., Jacada Ltd. and Nova Measuring Instruments Ltd., all NASDAQ publicly traded companies. In addition, Mr. Falk serves as a member of the Board of Directors of the following public non-US companies: AVT Ltd., Amiad Filteration System Ltd, Plastopil 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 Executive Officer of Sapiens International NV. From
1995 to 1999, Mr. Falk was an Executive Vice President of Orbotech Ltd. From 1985 to 1995, Mr. Falk was Vice President of Finance and Chief Financial Officer of Orbot Systems Ltd. and of Orbotech Ltd. Mr. Falk obtained a Master of Business Administration from Hebrew University in 1972 and a Bachelor of Arts in Economics and Political Science from Hebrew University in 1968. Mr. Falk is the Chair of our Audit Committee. Our Board of Directors has determined that Mr. Falk qualifies as an Audit Committee ‘‘financial expert’’ under Section 407 of the Sarbanes-Oxley Act of 2002 and Item 407(d)(5) of Regulation S-K, and is ‘‘independent’’ as that term is used in Item 407(d) 5(i)(B) of Regulation S-K under the Securities Exchange Act of 1934.
Jacob J. Worenklein. Jacob J. Worenklein has been a member of our Board of Directors since November 12, 2004, and has also served as Chairman and Chief Executive Officer of US Power Generating Company from 2003 to the present. From 1998 to 2003, he was Managing Director and Global Head of Project and Sectorial Finance for Societe Generale and, from 1996 to 1998, he was Managing Director and Head of Project Finance, Export Finance and Commodities for the Americas, for Societe Generale. Prior to joining Societe Generale in 1996, Mr. Worenklein was Managing Director and Global Head of Project Finance at Lehman Brothers and prior thereto was a partner and member of the executive committee of the law firm of Milbank, Tweed, Hadley & McCloy LLP, where he founded and headed the firm’s power and project finance practice. Mr. Worenklein served as Adjunct Professor of Finance at New York University and is a trustee of the Committee for Economic Development and a member of the Council on Foreign Relations. He is a member of the Board of Directors of GridPoint Inc. a company in the demand side management business. Mr. Worenklein obtained a Bachelor of Arts from Columbia College in 1970 and a Juris Doctor and Master of Business Administration from New York University in 1973.
Roger W. Gale, Ph.D. Roger W. Gale has been a member of our Board of Directors since October 26, 2005. Between 1988 and 2000, Dr. Gale was the CEO of Washington International Energy Group, which was sold to PHB Hagler Bailly (PHB) in 1999. In 2000, as PHB was sold to PA Consulting, Dr. Gale held several positions at PA Consulting until 2001, at which time he joined GF Energy LLC as President and CEO, a position he still holds. In addition, Dr. Gale served as a member of the Board of Directors of the US Energy Association, a not-for-profit organization. On December 1, 2005, he became a member of the Boards of Directors of The Adams Express Company and Petroleum & Resources Corporation (closed-end investment companies). He served on the Audit Committee of Constellation Holdings and on the board of the parent, Constellation Energy Group from 1996 to 2005. Dr. Gale has a Ph.D. in political science from the University of California, Berkeley.
Robert F. Clarke. Robert F. Clarke has been a member of our Board of Directors since February 27, 2007. Mr. Clarke was Chairman (since September 1998) and President and Chief Executive Officer (since January 1991) of Hawaiian Electric Industries, Inc. (HEI), from which he retired effective May 2006. Since June 1, 2006, Mr. Clarke has been Executive in Residence at the Shidler College of Business at the University of Hawaii. In addition, Mr. Clarke serves as an advisory director to Oceanic Cable Hawaii, as a member of the advisory board of the Shidler College of Business at the University of Hawaii, and as a trustee of the Oceanic Institute (Hawaii). Mr. Clarke joined HEI in February 1987 as Vice President of Strategic Planning and was in charge of implementing the Company’s diversification strategy. Mr. Clarke was named HEI Group Vice President - Diversified Companies in May 1988. He was made a director of HEI in 1989. Prior to joining HEI, Mr. Clarke served as Senior Vice President and Chief Financial Officer of Alexander & Baldwin and as Controller of Dillingham Corporation. Prior to that, he worked for the Ford Motor Company and for the Singer Company. He received his Bachelor’s degree in economics in 1965 and his Master’s degree in finance in 1966 from the University of California at Berkeley. Honors include Phi Beta Kappa in 1965.
Audit Committee
We are a listed issuer, as defined in Sec. 240.10A-3 of Regulation S-K, and have a separately designated audit committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934, composed of independent directors as required by Section 303A.07 of the
NYSE Listed Company Manual. The members of such committee are Dan Falk (Chair), Jacob Worenklein and Roger W. Gale, who are also independent directors of our company, as defined in Section 303A.02 of the NYSE Listed Company Manual.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required under this item is incorporated by reference herein from the Company’s definitive 2008 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 2008 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required under this item is incorporated by reference herein from the Company’s definitive 2008 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 2008 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 in Item 8 of this annual report.
(2) List of Financial Statement Schedules
All applicable schedule information is included in our Financial Statements in Item 8 of this annual report.
(b) EXHIBIT INDEX
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 5, 2008
By:
/s/ YEHUDIT BRONICKI
Name: Yehudit Bronicki
Title: Chief Executive Officer,
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 5, 2008.
Signature
Capacity
/s/ YEHUDIT BRONICKI
Chief Executive Officer and Director (Principal Executive Officer)
Yehudit Bronicki
/s/ JOSEPH TENNE
Chief Financial Officer (Principal Financial and Accounting Officer)
Joseph Tenne
/s/ LUCIEN Y. BRONICKI
Chairman of the Board of Directors and Chief Technology Officer
Lucien Y. Bronicki
/s/ YORAM BRONICKI
President, Chief Operating Officer and Director
Yoram Bronicki
/s/ DAN FALK
Director
Dan Falk
(c) EXHIBIT INDEX