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. A glossary of certain terms and abbreviations used in this annual report appears at the beginning of this report.
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 Product 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 Product 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.
The map below shows our current worldwide portfolio of operating geothermal power plants and recovered energy plants, as well as the geothermal and recovered energy-based power plants that are under construction and countries with projects under development and exploration.
The charts below show the relative contributions of the Electricity Segment and the Product Segment to our consolidated revenues and the geographical breakdown of our segment revenues for our fiscal year ended December 31, 2010. 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, 2010:
The following chart sets forth the geographical breakdown of the revenues attributable to our Electricity Segment for the year ended December 31, 2010:
The following chart sets forth the geographical breakdown of the revenues attributable to our Product Segment for the year ended December 31, 2010:
Most of the power plants 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 manufacture products that produce electricity from recovered energy or so-called “waste heat”. We also construct, own, and operate recovered energy power plants. Recovered energy represents residual heat that is generated as a by-product of gas turbine-driven compressor stations, solar thermal units and a variety of industrial processes, such as cement manufacturing. Such residual heat, which 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 additional emissions.
Company Contact and Sources of Information
We file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 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.
Our reports on Form 10-K, 10-Q and 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available through our website at 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. If we make any amendments to our Code of Business Conduct and Ethics or Code of Ethics Applicable to Senior
Executives or grant any waiver, including any implicit waiver, from a provision of either code applicable to our Chief Executive Officer, Chief Financial Officer or principal accounting officer requiring disclosure under applicable SEC rules, we intend to disclose the nature of such amendment or waiver on our website. 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 (Electricity Segment)
Power Plants in Operation
The table below summarizes certain key non-financial information relating to our power plants as of February 22, 2011:
(1)
We own and operate all of our power plants other than the Momotombo power plant in Nicaragua, which we do not own but which we control and operate through a concession arrangement with the Nicaraguan government. Two financial institution hold equity interests in one of our consolidated subsidiaries (OPC) that owns the Desert Peak 2 power plant in our Brady complex and the Steamboat Hills, Galena 2 and Galena 3 power plants in our Steamboat complex. In the above table, we show these power plants as being 100% owned because all of the generating capacity is owned by OPC and we control the operation of the power plants. The nature of the
equity interests held by the financial institution is described in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “OPC Transaction”.
(2)
References to generating capacity generally refer to the gross capacity less auxiliary power, in the case of all of our existing domestic power plants and the Momotombo, Amatitlan and Olkaria III power plants (three of our foreign power plants), and to the generating capacity that is subject to the “take or pay” obligation in the case of the PPA of the Zunil power plant (one of our foreign power plants). We determine the generating capacity figures taking into account resource capabilities. This column represents our net ownership in such generating capacity.
In any given year, the actual power generation of a particular power plant may differ from that power plant’s generating capacity due to variations in ambient temperature, the availability of the resource, and operational issues affecting performance during that year. The Capacity Factor of the geothermal power plants in commercial operation in 2010, excluding the North Brawley power plant which operates at partial load, was approximately 90%. The Capacity Factor of the REG power plants in 2010 was approximately 70%.
(3)
We completed the construction of the Jersey Valley power plant and placed it in service, but it is not yet in commercial operation under the PPA. Further information on the Jersey Valley power plant is provided under “Description of our Power Plants” below.
(4)
The North Brawley power plant is not operating at full capacity. Detailed information on the North Brawley power plant is provided under “Description of our Power Plants” below.
Substantially all of the revenues that we currently derive from the sale of electricity are pursuant to long-term PPAs. Approximately 68.2% of our total revenues in the year ended December 31, 2010 from the sale of electricity by our domestic power plants were derived from power purchasers that currently have investment grade credit ratings. The purchasers of electricity from our foreign power plants are either state-owned or private entities.
New Power Plants
We are currently in various stages of development of new power plants, construction of new power plants and expansion of existing power plants. Our growth plan includes our share of between 212 MW and 228 MW in generating capacity from geothermal power plants in the United States that are expected to come on-line in the next three years. In addition, we expect to add, in three phases, a total of approximately 42 MW, which is our share in the Sarulla project in Indonesia.
We have various leases and concessions for geothermal resources of approximately 343,000 acres in 27 sites. We have started or plan to start exploration activity at a number of these sites.
In addition, we have approximately 14 ground-mounted and roof-top Solar PV projects under development in Israel. Our share in these projects is 36 MW.
Our Product Business (Product Segment)
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 OECs. Our customers include contractors and geothermal power 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.” This heat is generated as a residual by-product of gas turbine-driven compressor stations, solar thermal units 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.
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 related costs.
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.
History
We were formed as a Delaware corporation by Ormat Industries Ltd. (also referred to in this annual report as the “Parent”, “Ormat Industries”, “the parent company”, or “our parent”) in 1994. Ormat Industries was one of the first companies to focus on the development of equipment for the production of clean, renewable and generally sustainable forms of energy. Ormat Industries owns approximately 60% of our outstanding common stock.
Industry Background
Geothermal Energy
Most of our power plants in operation produce electricity from geothermal energy. There are several different sources or methods to obtain geothermal energy, which are described below.
Hydrothermal geothermal-electricity generation - Hydrothermal geothermal energy is derived from naturally occurring hydrothermal reservoirs that are formed when water comes sufficiently close to hot 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 power plants 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. In addition, because geothermal energy power plants produce 24hr/day weather independent power, the variable operating costs are lower.
EGS - An EGS has been broadly defined as a subsurface system that may be artificially created to extract heat from hot rock where the characteristics required for a hydrothermal system, i.e., permeability and aquifers, are non-existent. A geothermal power plant that uses EGS techniques would recover the thermal energy from the subsurface rocks by creating or accessing a system of open fractures in the rock through which water can be injected, heated through contact with the hot rock, returned to the surface in production wells and transferred to a power unit.
Co-produced Geothermal from Oil and Gas fields, geo-pressurized resources - Another source of geothermal energy is hot water produced from oil and gas production. This application is referred to as “Co-produced Fluids”. In some oil and gas fields, water is produced as a by-product of the oil and gas extraction. When the wells are deep the fluids are often at high temperatures and if the water volume is significant, the hot water can be used for power generation in equipment similar to a geothermal power plant.
Geothermal Power Plant Technologies
Geothermal power plants generally employ either binary systems or conventional flash design systems, as described below. In our geothermal power plants, we also employ our proprietary technology of combined geothermal cycle systems.
Binary System
In a geothermal power 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 geothermal power 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 underground). 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.
Ormat’s Proprietary Technology
Our proprietary technology may be used in power plants operating according to the Organic Rankine Cycle only or in combination with, various other commonly used thermodynamic technologies that convert heat to mechanical power. It can be used with a variety of thermal 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 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) areas, we are examining two-level recovered energy systems and new motive fluids.
We also construct 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. Our combined cycle technology is depicted in the graphic below.
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 disposal 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 revolutions per minute (RPM), temperature and pressure in the OEC, 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 may 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 OEC’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 OEC 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 conventional steam turbines exhibit, requires no water treatment as it is air cooled, and does not require the continuous presence of a steam licensed operator on site.
Our REG technology is depicted in the graphic below.
Patents
We have been granted 80 U.S. patents (and about 16 pending patents) that 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” (e.g., geothermal fluid, waste heat, biomass or solar) to generated electricity. The duration of such patents ranges from one year to thirteen years. No single patent on its own is material to our business.
The products-related patents cover components such as turbines, heat exchangers, seals and controls. The system patents cover subjects such as waste heat recovery related to gas pipelines compressors, disposal of non-condensable gases present in geothermal fluids, power plants for very high pressure geothermal resources, and use of two-phase fluids as well as processes related to EGS. 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.
Research and Development
We are conducting research and development of new EGS technologies and their application to our power plants. We are undertaking this development effort at our Desert Peak 2 and Brady power plants in Nevada in cooperation with GeothermEx Inc., and a number of universities and national laboratories, with funding support from the DOE.
We are developing an OEC unit for a REG plant designed to use the residual energy from the vaporization process of LNG in LNG receiving terminals. The power plant takes advantage of the available hot and cold sources
(sea water and LNG at minus 238 degrees Fahrenheit, respectively) in the regasification process to generate electrical power from unused heat energy.
We also continue to conduct research and development to improve our turbines and other power plant equipment.
Market Opportunity
Interest in geothermal energy in the United States has increased as production costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel-based electricity generation and as legislative and regulatory incentives have become more prevalent, as described below.
Although electricity generation from geothermal resources is currently concentrated mainly 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 estimates that 13,000 MW of identified geothermal resources will be developed by 2025. In a report issued in April 2010 for the World Geothermal Congress, Ruggero Bertani of Enel Green Power forecasted that by 2015 the worldwide installed capacity will increase by approximately 73% from 10,715 MW in 2010 to 18,500 MW in 2015. The report identifies the U.S., Indonesia, the Philippines, New Zealand and Mexico as the main contributors to the forecasted growth.
In a report issued in April 2010, the Geothermal Energy Association identified a total of 188 confirmed and unconfirmed geothermal projects under various phases of consideration or development in 15 U.S. States that have between 5,254 MW and 7,875 MW potential capacity.
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, Kansas, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, Montana, New Hampshire, Nevada, New Jersey, New Mexico, New York, North Carolina, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, South Dakota, Texas, Utah, Vermont, Virginia, Washington, West Virginia, Wisconsin and the District of Colombia have all adopted RPS, renewable portfolio goals, or 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.
According to the Database of State Incentives for Renewables and Efficiency (DSIRE), twenty-eight 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 power plants in operation are located) and the District of Columbia define geothermal resources as “renewable”.
According to DSIRE, seventeen states have enacted RPS and Alternative Portfolio Standards that include some form of combined heat and power and/or waste heat recovery. The seventeen states are: Arizona, Colorado, Connecticut, Hawaii, Maine, Massachusetts, Michigan, Nevada, New York, North Carolina, North Dakota, Ohio, Pennsylvania, South Dakota, Utah, Washington, and West Virginia.
We believe that these legislative measures and initiatives present a significant market opportunity for us. In California, then Governor Arnold Schwarzenegger signed an Executive Order on September 15, 2009, requiring most retail sellers of electricity to derive at least 33% of retail sales from eligible renewable resources by 2020. On September 23, 2010, the California Air Resources Board adopted unanimously the 33% renewable electricity standard. Nevada’s RPS requires NV Energy to supply at least 15% of the total electricity it sells from eligible renewable energy resources by 2013, which will increase to 25% by 2025. In 2009, 11% of the electricity retail sales in Nevada were from renewable energy sources. Hawaii’s RPS requires each Hawaiian electric utility that sells electricity for consumption in Hawaii to obtain 15% of its net electricity sales from renewable energy sources by
December 31, 2015, 20% by December 31, 2020 and 40% by 2030. In 2009, Hawaiian Electric Company and its subsidiaries achieved a consolidated RPS of 19%.
In 2006, California passed a state climate change law, AB 32. The goal of AB 32 is to reduce greenhouse gas emissions to 1990 levels by the end of 2020. In 2008, the California Air Resources Board approved a Scoping Plan to carry out regulations implementing AB 32. In December 2010, the California Air Resources Board endorsed cap-and-trade regulation to reduce California’s greenhouse gas emissions under AB 32 The cap-and-trade regulation sets a statewide limit on emissions from sources responsible for emitting 80% of California’s greenhouse gases and according to the California Air Resources Board, will help establish a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. On January 21, 2011, the California Superior Court in San Francisco issued a tentative decision that would, if finalized, require the California Air Resources Board to enjoin implementation of the Scoping Plan until the California Air Resources Board complies with certain environmental review obligations. Under the tentative decision, the parties were allowed to file objections to the tentative decision. Both parties filed objections on February 8, 2011. It remains unclear whether there could be any delay to the planned 2012 implementation of the cap-and-trade program. On the federal level on January 2, 2011, the first phase of EPA’s Tailoring Rule took effect in almost all jurisdictions, with the notable exception of the state of Texas. The Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of greenhouse gas emissions .Regional initiatives are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. For example, ten Northeast and Mid-Atlantic States are part of the RGGI, a regional cap-and-trade system to limit carbon dioxide. The RGGI is the first mandatory, market-based carbon dioxide emissions reduction program in the United States. The first-in-the-nation auction of carbon dioxide allowances was held in September 2008. Under RGGI, the ten participating states plan to reduce carbon emissions from power plants by 10% by 2018.
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 difficult 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 30% of certain eligible costs of a new geothermal power plant in the United States as a one-time credit against our federal income taxes. Alternatively, we are permitted to claim a tax credit based on the power produced from a geothermal power plant. These production-based credits, which in 2010 were 2.2 cents per kWh, are adjusted annually for inflation and may be claimed for ten years on the electricity produced by a new geothermal power plant put into service prior to December 31, 2013. The production-based credits are allowed only to the extent the power is sold to a third party. The owner of the power plant must choose between these two types of tax credits 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. Another alternative available is a cash grant for Specified Energy Projects in Lieu of Tax Credits from the U.S. Treasury. It is available for certain power plants placed in service by the end of 2011, or on which construction begins in 2009, 2010 or 2011 and that are completed by the end of 2013.
Whether we claim tax credits or the U.S. Treasury cash grant, we are also permitted to depreciate, or write off, most of the cost of the plant. If we claim the one-time 30% tax credit or receive the U.S. Treasury cash grant, our tax basis in the plant that we can recover through depreciation must be reduced by half of the tax credit or U.S. Treasury cash grant; if we claim other tax credits, there is no reduction in the tax basis for depreciation. For projects that are placed into service after September 8, 2010 and before January 1, 2012, a depreciation “bonus” will permit us to write off 100% of the cost of certain equipment that is part of the geothermal power plant in the year the plant goes into service, if certain requirements are met. For projects that are placed into service after December 31, 2011 and before January 1, 2013, a similar “bonus” will permit us to write off 50% of the cost of that equipment in the year the power plant is placed into service. After applying any depreciation bonus that is available, we can write off the
remainder of our tax basis in the plant, if any, 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.
Collectively, these benefits (to the extent fully utilized) have a present value equivalent to approximately 30% to 40% of the capital cost of a new power plant.
Production of electricity from geothermal resources is also supported under the new “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s existing Innovative Technology Loan Guarantee Program. The new program (i) extends the scope of the existing federal loan guarantee program to cover renewable energy projects, renewable energy component manufacturing facilities and electricity transmission projects that embody established commercial, as well as innovative, technologies; and (ii) provides an appropriation to cover the “credit subsidy costs” of such projects (meaning the estimated average costs to the federal government from issuing the loan guarantee, equivalent to a lending bank’s loan loss reserve).
To be eligible for a guarantee under the new program, a supported project must commence construction on or before September 30, 2011, and the guarantee must be issued by September 30, 2011. A project supported by the federal guarantee under the new program must pay prevailing federal wages.
Operations outside of the United States may be subject to and/or benefit from requirements under the Kyoto Protocol. In December 2010, the United Nations Climate Change Conference was held in Cancún, Mexico. The conference encompassed the 16th Conference of the Parties to the United Nations Framework Convention on Climate Change and the sixth Meeting of the Parties to the Kyoto Protocol. At the conference, the participating countries signed an accord to reduce global warming. While the Cancún agreement is not legally binding, it creates a balanced package of decisions that is designed to set all participating governments more firmly on the path towards a low-emissions future and to support enhanced action on climate change in the developing world. The next Conference of the Parties is scheduled to take place in South Africa in November 2011.
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 power plants are located, approved in November 2003 a law which created 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. Another example is New Zealand, where Ormat has been actively designing and supplying geothermal power solutions since 1986. The New Zealand government’s policies to fight climate change include a target for greenhouse gas emissions reductions of between 10% and 20% below 1990 levels by 2020 and the target of increasing renewable electricity generation to 90% of New Zealand’s total electricity generation by 2025. In Indonesia, the government has implemented policies and regulations intended to accelerate the development of renewable energy and geothermal projects in particular. These include designating approximately 4,000 MW of geothermal projects in its 2nd phase of power acceleration projects to be implemented by 2014, of which the majority is IPP projects and the remaining state utility PLN projects. For the IPP, geothermal projects regulations have been implemented providing for incentives such as investment tax credits and accelerated depreciation, and pricing guidelines intended to allow preferential power prices for generators. In addition, there is a regulation providing feed-in tariffs for small scale renewable energy projects up to 10 MW. On a macro level, the Government of Indonesia committed at the United Nations Climate Change Conference 2009 in Copenhagen to reduce its CO2 emissions by 20% by 2020, which is intended to be achieved mainly through prevention of deforestation and accelerated renewable energy development. Another example is Chile, where we were recently
awarded an exploration concession. The Chilean Renewable Energy Act of 2008 requires that 5% of electricity sold come from renewable sources beginning in 2010, increasing gradually to 10% by 2024.
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 our Product Segment.
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 may benefit from the increased attention to energy efficiency. For example, in the United States, the FERC has expressed its position that the primary goal of natural gas pipeline design should be the efficient, low-cost transportation of fuel, including through the use of waste heat (recovered energy) from combustion turbines or reciprocating engines that drive station compressors to generate electricity for use at compressor stations or for commercial sale. 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 built over 20 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.
Several states, and to a certain extent, the federal government, have recognized the environmental benefits of recovered energy-based power generation. For example, Colorado, Connecticut, Hawaii, Louisiana, Massachusetts, Michigan, Nevada, North Carolina, North Dakota, Ohio, Pennsylvania, South Dakota, Utah, and Washington allow electric utilities to include recovered energy-based power generation in calculating their compliance with their mandatory or voluntary RPS. 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, but currently do not qualify for ITC. Recovery of waste heat is also considered “environmentally friendly” in the western Canadian provinces. We believe that Europe and other markets worldwide may offer similar opportunities in recovered energy-based power generation. In North America, we estimate the potential total market for recovered energy-based power generation to be over 1,000 MW. However, much of this potential is in states where the cost of electricity is relatively low, which creates marketing and pricing challenges.
Competitive Strengths
Competitive Assets. Our assets are competitive for the following reasons:
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Contracted Generation. Virtually all of the electricity generated by our geothermal power plants is currently sold pursuant to long-term PPAs, providing generally predictable cash flows.
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Baseload Generation. All of our geothermal power plants supply all or a part of the baseload capacity of the electric system in their respective markets. This means they supply electric power on an around-the-clock basis. 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 their weather dependence and thus intermittent nature of these other renewable energy sources.
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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 compared to electricity generated from fossil fuels or other renewable sources under existing economic conditions and existing tax and regulatory regimes.
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Ability to Finance Our Activities from Internally Generated Cash Flow. The cash flow generated by our portfolio of operating geothermal and REG power plants provides us with a robust and predictable base for our exploration, development, and construction activities, to a certain level, without the need to tap into external liquidity sources. We believe that this gives us a competitive advantage over certain competitors
whose activities are dependent on external credit and financing sources that may be subject to availability constraints depending on prevailing global credit and market conditions.
Growing Legislative Demand for Environmentally-Friendly Renewable Resource Assets. Most of our currently operating power plants produce electricity from geothermal energy sources. The 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.
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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 and REG power plants. Our intimate knowledge of the equipment that we use in our operations allows us to operate and maintain our power plants 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 power plants, 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.
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We design, manufacture, and sell to third parties power units and other power generating equipment for geothermal and recovered energy-based electricity generation. Our extensive experience in the development of state-of-the-art, environmentally sound power solutions enable our customers to relatively easily finance their power plants.
Exploration and Drilling Capabilities. We have in-house capabilities to explore and develop geothermal resources. In 2007, we established a drilling subsidiary that currently owns five drilling rigs. We employ an experienced resource group that includes engineers, geologists, and drillers. This resource group executes our exploration and drilling plans for projects that we develop.
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 25 years of industry experience.
Technological Innovation. We have been granted 80 U.S. 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 apart from the impact fuel prices may have on the price at which we sell power under PPAs that are based on the relevant power purchaser’s avoided costs.
Although we are confident in our competitive position in light of the strengths described above, we face various challenges in the course of our business operations, including as a result of the risks described in 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 REG plants, which is subject to various operational risks.
Our financial performance depends on the successful operation of our subsidiaries’ geothermal and REG power plants. In connection with such operations, we derived approximately 78.2% of our total revenues for the year ended December 31, 2010 from the sale of electricity. The cost of operation and maintenance and the operating performance of our subsidiaries’ geothermal power and REG plants may be adversely affected by a variety of factors, including some that are discussed elsewhere in these risk factors and the following:
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regular and unexpected maintenance and replacement expenditures;
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shutdowns due to the breakdown or failure of our equipment or the equipment of the transmission serving utility;
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labor disputes;
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the presence of hazardous materials on our power plant sites;
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continued availability of cooling water supply;
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catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of hazardous materials, severe storms, or similar occurrences affecting our power plants or any of the power purchasers or other third parties providing services to our power plants; and
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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 power plants or reduce the overall generating capacity of our power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of our power plants, 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 2008, we experienced protracted failures of two of the Steamboat 2/3 power plant’s turbines, which were not manufactured by us. We replaced the turbines and successfully upgraded the power plant. 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 are subject to geological risks and uncertainties, which may result in decreased performance or increased costs for our power plants.
Our primary business involves the exploration, development, and operation of geothermal energy resources. These activities are subject to uncertainties that, in certain respects, are similar to those typically associated with oil and gas exploration, development, and exploitation, such as dry holes, uncontrolled releases, and pressure and temperature decline. Any of these uncertainties may increase our capital expenditures and our operating costs, or
reduce the efficiency of our power plants. We may not find geothermal resources capable of supporting a commercially viable power plant at a number of exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants. Prior to our acquisition of the Steamboat Hills power plant, one of the wells related to the power plant experienced an uncontrolled release. The high temperature and high pressure in the Puna power plant’s geothermal energy resource requires special reservoir management and monitoring. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling and/or reservoir pressure decline in the normal course of operations. For example, some of Brady’s production wells have cooled significantly due to breakthrough from injection wells. At Momotombo, early operations without injection resulted in reservoir pressure decline and consequent reduced productivity and scale plugging in the formation near the producer wellbores. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal power plants depends on different factors directly related to the geothermal resource (such as the temperature, pressure, storage capacity, transmissivity, and recharge) as well as operational factors relating to the extraction or reinjection of geothermal fluids. At our North Brawley power plant instability of the sands and clay in the geothermal resource and variability in the chemical composition of the geothermal fluid have all combined to increase our capital expenditures for the project, as well as our ongoing operating expenses, and have so far prevented the project from sustainable operation at its intended design capacity. Our geothermal energy power plants may also 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.
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 complex, 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 complex 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, active geothermal areas, such as the areas in which our power plants are located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible and could result in damage to our power plants or equipment or degrade the quality of our geothermal resources to such an extent that we could not perform under the PPA for the affected power plant, 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.
Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, or failure to reinject the geothermal fluid, or improper maintenance of the hydrological balance may affect the operational duration of the geothermal resource and cause it to become a wasting asset, and may adversely affect our ability to generate power from the relevant geothermal power plant.
Reduced levels of recovered energy required for the operation of our REG power plants may result in decreased performance of such power plants.
Our REG 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. We are also currently examining the possibility of entering the solar energy sector of the renewable energy industry and have recently entered into a joint venture with a third party to develop Solar PV power projects in Israel. Our success in developing a particular project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and PPAs, 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 PPA, 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. Our lack of experience in the Solar PV sector may also affect our ability to successfully develop, construct, finance, and operate the Solar PV power projects.
Currently, we have power plants under development or construction in the United States and Indonesia, 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:
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unanticipated cost increases;
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shortages and inconsistent qualities of equipment, material and labor;
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work stoppages;
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inability to obtain permits and other regulatory matters;
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failure by key contractors and vendors to timely and properly perform;
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adverse environmental and geological conditions (including inclement weather conditions); and
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our attention to other projects, including those in the solar energy sector.
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 rely on power transmission facilities that we do not own or control.
We depend on transmission facilities owned and operated by others to deliver the power we sell from our power plants to our customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver power to our customers may be adversely impacted and we may either incur additional costs or forego revenues. In addition, lack of access to new transmission capacity may affect our ability to develop new projects. Existing congestion of transmission capacity, as well as expansion of transmission systems and competition from other developers seeking access to expanded systems, could also affect our performance.
The aftermath of the recent global recession and its attendant credit constraints could adversely affect us.
We may continue to experience lower levels of worldwide demand for energy, and face tighter credit markets, as the world economy continues to recover from the disruption in the global credit markets, failures or material business deterioration of investment banks, commercial banks, and other financial institutions and intermediaries in the United States and elsewhere around the world, and significant reductions in asset values across businesses, households and individuals that led to the recent global recession. These conditions may adversely affect both our Electricity and Product Segments. Among other things, we might face:
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potential adverse impacts on our ability to negotiate with existing lenders, waivers or modifications of the terms of existing financing arrangements if and when that might be necessary;
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potential declines in revenues in our Product Segment due to reduced or postponed orders or other factors caused by economic challenges faced by our customers and prospective customers; and
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potential adverse impacts on our customers’ ability to pay, when due, amounts payable to us and related increases in our cost of capital associated with any increased working capital or borrowing needs we may have if this occurs, or to collect amounts payable to us in full (or at all) if any of our customers fail or seek protection under applicable bankruptcy or insolvency laws.
Any of these things could adversely affect our business, financial condition, operating results, and cash flow.
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, 2010, we had approximately $789.7 million of total consolidated indebtedness, of which approximately $361.0 million represented non-recourse debt and limited recourse debt held by our subsidiaries. Each of our projects under development or construction and those projects and businesses we may seek to acquire or construct will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms.
Market conditions and other factors may not permit future project and acquisition financings on terms similar to those our subsidiaries have previously received. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic conditions, conditions in the global capital and credit markets (as discussed above), investor confidence, the continued success of current power plants, the credit quality of the power plants being financed, the political situation in the country where the power plant 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 power plants 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 power plants 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 power plants.
We have substantial operations outside of the United States that generated revenues in the amount of $142.9 million for the year ended December 31, 2010, which represented 38.3% 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 power plants 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 power plants that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such power plants. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:
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changes in government policies or personnel;
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changes in general economic conditions;
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restrictions on currency transfer or convertibility;
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changes in labor relations;
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political instability and civil unrest;
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changes in the local electricity market;
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breach or repudiation of important contractual undertakings by governmental entities; and
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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 power plants 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 power plant, 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 power plant. 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 IPPs to lower their tariffs. In addition, further re-organization of KPLC has been made with the formation of a new company known as KETRACO to undertake power transmission. KPLC will continue to undertake power distribution. This re-organization is in accordance with the National Energy Policy (Sessional Paper No. 4 of 2004). No announcement has been made as to whether KPLC’s transmission assets will be transferred to KETRACO. Another highlight of the Sessional Paper was the establishment of the state owned GDC which has now been formed and is operational. GDC is charged with the responsibility of geothermal assessment, drilling of steam wells and sale of steam to future IPPs and to KenGen for electricity generation. Any break-up and potential privatization of KPLC may adversely affect our Olkaria III complex. Although we generally obtain political risk insurance in connection with our foreign power plants, 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 power plant 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 power plants and foreign manufacturing operations expose us to risks related to fluctuations in currency rates, which may reduce our profits from such power plants 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 power plants and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign power plants and operations.
A significant portion of our net revenue is attributed to payments made by power purchasers under PPAs. The failure of any such power purchaser to perform its obligations under the relevant PPA or the loss of a PPA 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 PPAs. Southern California Edison, Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy) and HELCO have accounted for 29.1%, 15.0% and 8.6%, respectively, of our revenues for the year ended December 31, 2010. Neither we nor any of our affiliates makes any representations as to the financial condition or creditworthiness of any purchaser under a PPA, 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 PPAs. For example, as a result of the energy crisis in California in the early 2000s, Southern California Edison withheld payments it owed under various of its PPAs with a number of power generators (such as the Ormesa, Heber, and Mammoth power plants) payable for certain energy delivered between November 2000 and March 2001 under such PPAs until March 2002. If any of the power purchasers fails to meet its payment obligations under its PPAs, 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 power plants receive higher capacity payments under the relevant PPAs during the summer months, and due to the generally higher short run avoided costs in effect during the summer months. Some of our other power plants 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 PPAs 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 PPAs of our Burdette, Desert Peak 2, Galena 2, Galena 3, Carson Lake, Jersey Valley, McGinness Hills, Tuscarrora and North Brawley projects, 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 PPA and which such power purchaser is forced to obtain from an alternate source. Three of these nine projects were in commercial operation in 2010, 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 PPA. 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 PPAs. With respect to the Brady PPA, we may also be required to pay liquidated damages of approximately $1.5 million to our power purchaser if the relevant power plant does not maintain availability of at least 85% during applicable peak periods. Any or all of these could materially and adversely affect our business, financial condition, future results and cash flow.
The short run avoided costs for our power purchasers may decline, which would reduce our power plant revenues and could materially and adversely affect our business, financial condition, future results and cash flow.
Under the PPAs for our power plants 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 2012 and thereafter will be based on Southern California Edison’s short run avoided costs, as determined by the CPUC. 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 power plant revenues derived from Southern California Edison under our PPAs and could materially and adversely affect our business, financial condition, future results and cash flow.
In December 2010, a global settlement (Global Settlement) relating primarily to the purchase and payment obligations of investor-owned utilities to combined heat and power (CHP) Qualifying Facilities was approved by
the CPUC. The Global Settlement will become effective upon the satisfaction of certain conditions precedent, including (a) a final and non-appealable order from the FERC approving the investor-owned utilities’ request for a waiver of the QF must-take purchase obligation for Qualifying Facilities above 20 MW; and(b) that the CPUC order becomes final and non-appealable. As of February 22, 2011, not all of the conditions precedent (including the two noted above) have been satisfied.
Under the terms of the Global Settlement, existing Qualifying Facilities with “Legacy PPAs” (meaning any PPA that is in effect at the time the Global Settlement goes into effect) will have the option to choose to enter into a “Legacy PPA Amendment” within 180 days of the effectiveness of the Global Settlement. The Legacy PPA Amendment will allow a Qualifying Facility to choose a pricing methodology option going forward from the “pricing effective date”, which in Ormat’s case will be the end of the fixed rate period that terminates April 2012 under a prior settlement agreement with Southern California Edison. The pricing options include:
(1) switching to a new SRAC methodology, which has fixed, declining heat rates, a variable O&M component, an adjustment based on location, and a price adjustment if greenhouse gas (GHG) costs are imposed on the facility, all until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates;
(2) the same formula specified in (1) above but with somewhat higher heat rates and no GHG cost adder;
(3) the same formula specified in (1) above but with heat rates between options (1) and (2) and a fixed GHG payment of $20 per metric ton for allowances used by a facility;
(4) the same pricing terms as (3) above, but tied to actual GHG costs imposed on a facility, capped at $12.50 per metric ton; or
(5) a 90-day negotiation period to see if the parties can turn the PPA into a tolling agreement on agreed terms.
If an existing Qualifying Facility chooses not to enter into a Legacy PPA Amendment, its pricing under the existing Legacy PPA will revert at the end of the current fixed rate period (meaning, in Ormat’s case, the one that ends April 2012) to the SRAC formula pricing specified in (1) above.
The Global Settlement further provides that after July 1, 2015 if the term of a Qualifying Facility’s Legacy PPA expires, the utility will have no obligation to purchase power from the Qualifying Facility if the Qualifying Facility has a generating capacity in excess of 20 MW. Until July 1, 2015, a transition PPA will be available for Qualifying Facilities with Legacy PPAs that expire, which will incorporate the pricing structure outlined above. The investor-owned utilities have also agreed to conduct competitive solicitations for CHP Qualifying Facilies’ output (akin to the competitive solicitations available to renewable generators under the State’s Renewables Portfolio Standard program, but with various differences). There are also several other contracting options under the Global Settlement, including bilateral contracts with the investor-owned utilities. Qualifying Facilities below 20 MW will be entitled to a new standard offer PPA, with SRAC pricing and capacity payments as determined from time to time by the CPUC. The joint parties to the Global Settlement have agreed that the utilities can go to FERC to obtain a waiver of the mandatory purchase obligation under PURPA for Qualifying Facilities above 20 MW, which is one of the conditions precedent for the Global Settlement.
If any of our domestic power plants 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 power plants are Qualifying Facilities pursuant to the PURPA, which largely exempts the power plants from the FPA, and certain state and local laws and regulations regarding rates and financial and organizational requirements for electric utilities.
If any of our domestic power plants were to lose its Qualifying Facility status, such power plant 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 power plants 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, 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 power plant were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs would be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such PPAs are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that some or all of our domestic power plants refund amounts previously paid by the relevant power purchaser to such power plant. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic power plants, either of which would have an adverse effect on our revenues. Even if a power plant does not lose its Qualifying Facility status, pursuant to a final rule issued by FERC for power plants above 20 MW, if a power plant’s PPA is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that power plant 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 PPA, to cease taking and paying for electricity from the relevant power plant 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 PPAs, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our power plants. 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 power plant 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 power plants, which would enable the lenders to exercise their remedies and enforce the liens on the relevant power plant.
Pursuant to the Energy Policy Act of 2005, FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing PPAs between a Qualifying Facility and a utility are not affected. If the utilities in the regions in which our domestic power plants operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the power plant in the region under Federal law upon termination of the existing PPA or with respect to new power plants, 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 power plants, which is subject to changes in the legal and regulatory environment affecting our power plants.
All of our power plants 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 power plants. 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.
Any changes to applicable laws and regulations could significantly increase the regulatory-related compliance and other expenses incurred by the power plants and could significantly reduce or entirely eliminate the revenues generated by one or more of the power plants, 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 power plants 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 power plants 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 power plants 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 power plants. 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 power plants under construction or enhancement. In addition, a nearby municipality has informed our Amatitlan power plant 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 power plants 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 power plants.
Our power plants 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 power plants 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 power plants in concentrations that exceed regulatory limits, 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 power plants 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 complex site, but because of significant surface disturbance and construction since that time, further physical evaluation of the environmental condition 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:
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failure of the acquired companies to achieve the results we expect;
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inability to retain key personnel of the acquired companies;
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risks associated with unanticipated events or liabilities; and
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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 PPAs 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 reduction or elimination of government incentives related to solar power could cause the revenues we expect to derive from our solar power joint venture to decline.
Today, the cost of solar power exceeds the cost of power furnished by the electric utility grid in most locations. As a result, federal, state and local government bodies in many countries have provided various incentives in the form of rebates, tax credits, mandated feed-in-tariffs and other incentives to end users, distributors, system integrators and manufacturers of solar power products to promote the use of solar energy to reduce dependency on other forms of energy. These government economic incentives could be reduced or eliminated. Reductions in, or eliminations or expirations of, incentives related to solar power could result in decreased demand for solar power and adversely affect the revenues we expect to derive from our solar power joint venture in Israel.
We face competition from other companies engaged in the solar energy sector.
The solar power market is intensely competitive and rapidly evolving. We compete with many companies that have longer operating histories in this sector, larger customer bases, and greater brand recognition, as well as, in some cases, significantly greater financial and marketing resources than us. In some cases, these competitors are vertically integrated in the solar energy sector, manufacturing Solar PV, silicon wafers, and other related products for the solar industry, which may give them an advantage in developing, constructing, owning and operating solar power projects. We do not represent a significant competitive presence in the solar power market. Our lack of experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.
The existence of a prolonged force majeure event or a forced outage affecting a power plant 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 power plant experiences an occurrence resulting in a force majeure event, our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA. However, the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant or plant so long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely
terminate the PPA. 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 power plant, and if, as a result the power plant fails to attain certain performance requirements under certain of our PPAs, 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 PPA. As a consequence, we may not receive any net revenues from the affected power 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 IID 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 IID experiences a force majeure event or a forced outage which prevents it from transmitting the electricity from the Heber complex, the Ormesa complex or the North Brawley power plant 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 power plant so long as such force majeure event or forced outage continues. Our revenues for the year ended December 31, 2010, from the power plants utilizing the IID transmission system, were approximately $110.4 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 power plant 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 BLM leases may be terminated if we fail to comply with any of the provisions of the Geothermal Steam Act 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 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. 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 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 power plant 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 power plants, 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 power plants, thereby affecting our ability to utilize, access, inject, and/or transport geothermal resources on or underneath the affected surface areas. In particular, the Heber power plants 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 power plants. 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 power plants, 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 power plants in Nevada may also affect future permitting for geothermal operations relating to those power plants. 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 complex.
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, Yoram Bronicki, Nadav Amir, 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 power plants have generally been financed through a combination of our corporate funds 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 power plants.
Our power plants have generally been financed using a combination of our corporate funds 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 power plant’s revenues and are secured by the power plant’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 power plant, to provide limited financial support for the power plant 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 power plants, 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 power plants) 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 power plant 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 Solar PV 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 power plants 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.
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.
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. Future cost increases of such raw materials and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.
Conditions in and around 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 power plants.
Operations in Israel accounted for approximately 18.8%, 29.7%, and 27.7% of our operating expenses in the years ended December 31, 2010, 2009, and 2008, 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.
Negotiations between Israel and representatives of the Palestinian Authority in an effort to resolve the state of conflict have been sporadic and have failed to result in peace. The establishment in 2006 of a government in the Gaza territory by representatives of the Hamas militant group has created additional unrest and uncertainty in the region. At the end of December 2008, Israel engaged in an armed conflict with Hamas lasting for over three weeks, which involved additional missile strikes from the Gaza Strip into Israel and disrupted most day-to-day civilian activity in the proximity of the border with the Gaza Strip. Our production facilities in Israel are located approximately 26 miles from the border with the Gaza Strip.
The recent political instability and civil unrest in the Middle East and North Africa have raised new concerns regarding security in the region and the potential for armed conflict or other hostilities involving Israel. We could be adversely affected by any such hostilities, the interruption or curtailment of trade between Israel and its trading partners, or a significant downturn in the economic or financial condition of Israel. In addition, the sale of products manufactured in Israel may be adversely affected in certain countries by restrictive laws, policies or practices directed toward Israel or companies having operations in Israel.
In addition, some of our employees in Israel are subject to being called upon to perform military service in Israel, and their absence may have an adverse effect upon our operations. Generally, unless exempt, male adult citizens of Israel under the age of 41 are obligated to perform up to 36 days of military reserve duty annually. Additionally, all such citizens are subject to being called to active duty at any time under emergency circumstances.
These events and conditions could disrupt our operations in Israel, which could materially harm our business, financial condition, future results, and cash flow.
Failure to comply with certain conditions and restrictions associated with tax benefits provided to Ormat Systems by the Government of Israel as an “approved enterprise” may require us to refund such tax benefits and pay future taxes in Israel at higher rates.
Our subsidiary, Ormat Systems, has received “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 of two years that started in 2004, and thereafter such income is subject to a reduced Israeli income tax rate not exceeding 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 a period of two years that started in 2007, and thereafter such income is subject to a reduced Israeli income tax rate not exceeding 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 product 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. We recently entered into a new lease agreement with Ormat Industries for the sublease of additional manufacturing facilities that were 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 power plants 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 power plants that are owned jointly with other partners there may be certain additional restrictions on dividend distributions pursuant to our agreements with those 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 power plants 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 our Senior Vice President - Contract Management and Corporate Secretary, Etty Rosner, 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% of our common stock. Bronicki Investments Ltd. holds approximately 35.1% of the outstanding shares of common stock of Ormat Industries Ltd. as of February 22, 2011 (35.1% 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 product 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 may be highly volatile and may fluctuate substantially due to many factors, including:
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actual or anticipated fluctuations in our results of operations including as a result of seasonal variations in our electricity-based revenues;
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variance in our financial performance from the expectations of market analysts;
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conditions and trends in the end markets we serve and changes in the estimation of the size and growth rate of these markets;
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announcements of significant contracts by us or our competitors;
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changes in our pricing policies or the pricing policies of our competitors;
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loss of one or more of our significant customers;
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legislation;
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changes in market valuation or earnings of our competitors;
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the trading volume of our common stock; and
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general economic conditions.
In addition, the stock market in general, and the NYSE 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% 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 SEC 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 SOX Act 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 SOX Act. The SOX Act contains a variety of provisions affecting public companies, including but not limited to, corporate governance requirements, our relationship with our auditors, evaluation of our internal disclosure controls and procedures, and evaluation of our internal control over
financial reporting. See Management’s Report on Internal Control over Financial Reporting and Item 9A. - “Controls and Procedures.”
ITEM 1B.
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 807,000 square feet office and manufacturing facility (including approximately 75,000 square feet in a new specialized manufacturing building) 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 including the new facility will be adequate for our operations as currently conducted.
Each of our power plants 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 2010, other than as described below.
Securities Class Actions
Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Exchange Act. One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act. All three complaints allege claims on behalf of a putative class of purchasers of Company stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010.
These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (CAC) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.
Defendants filed a motion to dismiss the CAC on August 13, 2010 which remains pending.
The Company does not believe that these lawsuits have merit and is defending the actions vigorously.
Stockholder Derivative Cases
Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.
The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the state derivative cases.
The two federal derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010. Plaintiffs filed a consolidated derivative complaint on October 28, 2010 and in accordance with a stipulation by the parties, defendants filed a motion to dismiss on December 13, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the federal derivative cases.
The Company believes the allegations in these purported derivative actions are also without merit and is defending the actions vigorously.
Other
In addition, from time to time, we are named as a party to various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of our 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. GAAP. We do not believe that any of these proceedings, individually or in the aggregate, would materially and adversely affect our business, financial condition, future results and cash flows.
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 NYSE 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. As of February 22, 2011, there were 17 record holders of the Company’s common stock. On February 22, 2011, our stock’s closing price as reported on the NYSE was $27.95 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, 2009 and 2010, and from January 1, 2011 until February 22, 2011:
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, 2010 for our common stock, compared to the Standard and Poor’s Composite 500 Index, and two peer groups.
Comparison of Cumulative Returns for the Period November 11, 2004 through December 31, 2010
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IPP Peers are The AES Corporation, NRG Energy Inc., Calpine Corporation and International Power PLC. Renewable Energy (Renewable) Peers are Acciona S.A., Evergreen Solar Inc., Energy Conversion Devices Inc., NGP., Raser Technologies Inc. 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 and Related Stockholder Matters”.
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, 2010, 2009 and 2008 and as of December 31, 2010 and 2009 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, 2007 and 2006, and as of December 31, 2008, 2007 and 2006 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, sell, 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 Product 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. We have recently decided to expand our activities in the Electricity Segment to include the ownership and operation of power plants that produce electricity generated by Solar PV systems that we do not manufacture. In our Product 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 Product Segment operations are conducted in the United States and throughout the world. Our current generating portfolio includes geothermal plants in the United States, Guatemala, Kenya, and Nicaragua, as well as REG plants in the United States. During the years ended December 31, 2010 and 2009, our consolidated power plants generated 3,762,283 MWh and 3,296,824 MWh, respectively.
For the year ended December 31, 2010, our Electricity Segment represented approximately 78.2% of our total revenues, while our Product Segment represented approximately 21.8% of our total revenues during such year. For the year ended December 31, 2009, our Electricity Segment represented approximately 61.3% of our total revenues, while our Product Segment represented approximately 38.7% of our total revenues during such year.
For the year ended December 31, 2010, our total revenues decreased by 9.4% (from $412.0 million to $373.2 million) over the previous year. Revenues from the Electricity Segment increased by 15.5%, while revenues from the Product Segment decreased by 48.9%.
For the year ended December 31, 2010, total Electricity Segment revenues from the sale of electricity by our consolidated power plants were $291.8 million, compared to $252.6 million for the year ended December 31, 2009. In addition, revenues from our 50% ownership of the Mammoth complex in the period from January 1, 2010 to August 1, 2010 (the date we acquired the remaining 50% interest in the Mammoth complex) and in the year ended December 31, 2009 were $5.7 million and $9.9 million, respectively. 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. We believe that such Non-GAAP data is useful to the readers as it provides a more complete view of the scope of activities of the power plants that we operate. Our investment in the Mammoth complex prior to our acquisition of the remaining 50% interest was accounted for in our consolidated financial statements under the equity method, and the revenues were not included in our consolidated revenues for the period from January 1, 2010 to August 1, 2010 nor for the year ended December 31, 2009.
For the year ended December 31, 2010, revenues attributable to our Product Segment were $81.4 million, compared to $159.4 million during the year ended December 31, 2009, a decrease of 48.9%. As discussed below and in our previous quarterly reports, this decrease is attributable to the decline in our Product Segment customer orders. We expect a similar level of revenues from our Product Segment in 2011.
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 PPAs. The price for electricity under all but one of our PPAs is effectively a fixed price at least through April 2012. The exception is the 25 MW PPA of the Puna power plant. It has a monthly variable energy rate based on the local utility’s 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, 2010, approximately 86.2% of our electricity revenues were derived from contracts with fixed energy rates, and therefore most of our electricity 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 Product 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 power plants based on revenues and expenses, and our projects that are under development based on costs attributable to each such project. We evaluate the performance of our Product Segment based on the timely delivery of our products, performance quality of our products, gross margin, and costs actually incurred to complete customer orders 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 costs for electricity generated from geothermal resources have become more competitive relative to fossil fuel generation. This has partly been due to increasing natural gas and oil prices during much of this period and, equally important, to newly enacted legislative and regulatory requirements and incentives, such as state renewable portfolio standards and federal tax credits. The recently enacted ARRA further encourages the use of geothermal energy through production or investment tax credits as well as cash grants (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits”). 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 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.
We expect to continue to generate the majority of our revenues from our Electricity Segment through the sale of electricity from our power plants. Substantially all of our current revenues from the sale of electricity are derived from fully-contracted payments under long-term PPAs. We also intend to continue to pursue growth in our recovered energy business and in the solar sector.
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:
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Our primary focus continues to be the implementation of our organic growth through exploration, development, construction of new projects and enhancements of existing power plants. We expect that this investment in organic growth will increase our total generating capacity, consolidated revenues and operating income attributable to our Electricity Segment year over year. We routinely look at acquisition opportunities.
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In the United States, we expect to continue to benefit from the increasing demand for renewable energy. Thirty-six 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 power plants are located) have RPS, 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 outpace a possible reduction in general demand for energy due to the economic slowdown and will continue to create opportunities for us to expand existing power plants and build new power plants.
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We expect that the increased awareness of climate change may result in significant changes in the business and regulatory environments, which may create business opportunities for us going forward. In January 2011, the first phase of the EPA’s “Tailoring Rule” took effect in almost all of the states, with the notable exception of the state of Texas. The Tailoring Rule sets thresholds for when permitting requirements under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs apply to certain major sources of greenhouse gas emissions. Federal legislation or additional federal regulations addressing climate change are possible. Several states and regions are already addressing climate change. For example, California’s state climate change law, AB 32, which was signed into law in September 2006, regulates most sources of greenhouse gas emissions and aims to reduce greenhouse gas emissions to 1990 levels by 2020. In 2008, the California Air Resources Board approved a Scoping Plan to carry out regulations implementing AB 32. In December 2010, the California Air Resources Board endorsed cap-and-trade regulation to reduce California’s greenhouse gas emissions under AB 32. The cap-and-trade regulation sets a statewide limit on emissions from sources responsible for emitting 80 percent of California’s greenhouse gases and according to the California Air Resources Board, will help establish a price signal needed to drive long-term investment in cleaner fuels and more efficient use of energy. In September of 2006, California also passed Senate Bill 1368, which prohibits the state’s utilities from entering into long-term financial commitments for base-load generation with power plants that fail to meet a CO2 emission performance standard established by the California Energy Commission and the California Public Utilities Commission. California’s long-term climate change goals are reflected in Executive Order S-3-05, which requires a reduction in greenhouse gases to: (i) 2000 levels by 2010; (ii) 1990 levels by 2020; and (iii) 80% of 1990 levels by 2050. In addition to California, twenty-two other states have set greenhouse gas emissions targets or goals (Arizona, Colorado, Connecticut, Florida, Hawaii, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, Montana, New Hampshire, New Jersey, New Mexico, New York, Oregon, Rhode Island, Utah, Vermont, Virginia and Washington). Regional initiatives, such as the Western Climate Initiative (which includes seven U.S. states and four Canadian provinces) and the Midwest Greenhouse Gas Reduction Accord, are also being developed to reduce greenhouse gas emissions and develop trading systems for renewable energy credits. In September 2008, the first-in-the-nation auction of CO2 allowances was held under the RGGI, a regional cap-and-trade system, which includes ten Northeast and Mid-Atlantic States. Under RGGI, the ten participating states plan to stabilize power section carbon emissions at their capped level, and then reduce the cap by 10% at a rate of 2.5% each year between 2015 and 2018. In addition, twenty-nine states and the District of Columbia have all adopted RPS and seven other states have adopted renewable portfolio goals. In California, Governor Arnold Schwarzenegger signed an Executive Order on September 15, 2009, requiring most retail sellers of electricity to derive at least 33% of retail sales from eligible renewable resources by 2020. On September 23, 2010, the California Air Resources Board adopted unanimously the 33% renewable electricity standard.
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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 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.
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We expect competition from the wind and solar power generation industry to continue. The current demand for renewable energy is large enough that this increased competition has not materially impacted our ability to obtain new PPAs. However, the increase in competition and the amount of renewable energy under contract 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 continue to be a leading source of renewable energy in areas with commercially viable geothermal resource.
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We expect increased competition from binary power plant equipment suppliers. While we believe that we have a distinct competitive advantage based on our accumulated experience and current worldwide share of installed binary generation capacity, which is in excess of 90%, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition also may lead to a reduction in prices that we are able to charge for our binary equipment, which in turn may impact our profitability.
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Our PPA for 25 MW in the Puna power plant has a monthly variable energy rate based on the local utility’s 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. A decrease in the price of oil will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from oil, which will result in a reduction of the energy rate that we may charge under this PPA and any other variable energy rate in PPAs that we may enter into in the future.
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While the current demand for renewable energy is large enough that increased competition has not impacted our ability to obtain new PPAs and new leases, increased competition in the power generation industry may contribute to a reduction in electricity prices, and increased competition in geothermal leasing may contribute to an increase in lease costs
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The viability of a geothermal resource depends on various factors such as the resource temperature, the permeability of the resource (i.e., the ability to get geothermal fluids to the surface) and operational factors relating to the extraction of the geothermal fluids. 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 growth expectations.
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As our power plants age, they may require increased maintenance with a resulting decrease in their availability, potentially leading to the imposition of penalties if we are not able to meet the requirements under our PPAs as a result of any decrease in availability.
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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 some of the countries in which we operate. Although we maintain political risk insurance for most of our foreign power plants to mitigate these risks, insurance does not provide complete coverage with respect to all such risks.
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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 PPAs. We do not expect this change in law to affect our U.S. power plants significantly, as all except one of our current contracts (our Steamboat 1 power plant, 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 power plants 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 power plants 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 PPA, which could have an adverse effect on our revenues.
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The Global Settlement, once it becomes effective, will affect all of our PPAs with Southern California Edison, which accounted for approximately 29.1%, 21.1% and 27.7% of our revenues during 2010, 2009 and 2008, respectively. Under the Global Settlement, we have basically two choices available to us:
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We can do nothing, in which case our existing PPAs will automatically convert to SRAC pricing beginning in May 2012.
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We can amend our existing PPAs, which must be done within 180 days of the effectiveness of the Global Settlement, to incorporate one of the pricing options provided by the terms of the Global Settlement. If we make this choice, our existing PPAs will reflect the selected pricing option until December 2014 and thereafter convert to SRAC.
We plan to amend our existing PPAs, and are still evaluating which of the pricing options to select, which may vary from one PPA to another. We anticipate this may expose our revenues from these PPAs to greater fluctuations and may adversely affect our revenues under these PPAs. Because of the uncertainties inherent in pricing based on one or more future market-based prices for energy, heat rates and avoided costs, such as
future natural gas prices, it is not possible at this time to reliably estimate the potential impact on our revenues from these PPAs.
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In January 2011, the CPUC approved a program that allows investor-owned utilities to purchase tradeable renewable energy credits (TRECs) for purposes of compliance with the utility’s RPS obligations. A TREC is the environmental attribute of generated energy, and can be purchased and sold separately from the underlying energy itself. Under the CPUC decision, a utility can meet up to 25% of its annual RPS obligation with TRECs. TRECs can only be acquired from projects in the Western Electric Coordinating Council (WECC) region that are not directly connected to a California balancing authority. In addition, there is a cap on utility payments of $50 per MWH for each TREC. The CPUC has indicated that the percentage limits on TRECs, the cap on TREC pricing, and the limitations to eligibility in the TREC definition will be revisited in the future. Although we cannot predict at this time whether the new TREC program will have a significant impact on our operations or revenues, it may facilitate additional options when negotiating power purchase agreements and in selling electricity from our projects.
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 pursuant to long-term PPAs. 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 PPAs generally provide for the payment of energy payments alone, 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 PPAs 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 PPAs 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 prices paid for electricity pursuant to the PPA of the Puna power plant for 25 MW are impacted by the price of oil. Accordingly, our revenues for that power plant, which accounted for 8.6% and 6.3% of our total revenues for the years ended December 31, 2010 and 2009, respectively, may be volatile.
Revenues attributable to our Product 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 or requests for proposals 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 Product 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
The following table sets forth the geographic breakdown of the revenues attributable to our Electricity Segment and Product Segment for the years indicated:
Seasonality
The prices paid for the electricity generated by our domestic power plants pursuant to our PPAs are subject to seasonal variations. The prices paid for electricity under the PPAs with Southern California Edison, for the Heber 1 and 2 plants, the Mammoth complex, the Ormesa complex, and the North Brawley plant 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 PPAs of our power plants 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.
Breakdown of Cost of Revenues
Electricity Segment
The principal cost of revenues attributable to our operating power plants 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. In our California power plants our principal cost of revenues also include transmission charges, scheduling charges and purchases of make-up water for use in our 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. 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, 2010, royalties constituted 3.6% of the Electricity Segment revenues, compared to approximately 3.3% in the year ended December 31, 2009.
Product Segment
The principal cost of revenues attributable to our Product 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 Product 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 Product 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 and Cash Equivalents
Our cash and cash equivalents as of December 31, 2010 increased to $82.8 million from $46.3 million as of December 31, 2009. This increase is principally due to: (i) the issuance of an aggregate principal amount of $142.0 million of Senior Unsecured Bonds on August 3, 2010; (ii) receipt of $108.3 million received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; (iii) $101.4 million derived from operating activities during the year ended December 31, 2010; (iv) a net increase of $55.5 million in amounts drawn under revolving credit lines with commercial banks; (v) proceeds in the amount of $20.0 million from long-term loan agreements with a group of institutional investors; (vi) $19.6 million received from the sale of GDL; and (vii) a net increase of $17.7 million in restricted cash and cash equivalents. The increase in our cash resources was partially offset by: (i) our use of $283.3 million of cash resources to fund capital expenditures; (ii) net payment of $64.5 million for the acquisition of the remaining 50% interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); and (iii) $61.8 million to repay long-term debt to our parent and to third parties. Our corporate borrowing capacity under committed lines of credit with different commercial banks as of December 31, 2010 was $402.5 million, as described below in the section entitled “Liquidity and Capital Resources”, of which we utilized $253.4 million (including $63.9 million of letters of credit) as of December 31, 2010.
Critical Accounting Policies
Our significant accounting policies are more fully described in Note 1 to our consolidated financial statements set forth in 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:
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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 PPAs. The PPAs are exempt from derivative treatment due to the normal purchase and sale exception. Revenues related to PPAs accounted for as operating leases with minimum lease rentals which vary over time are generally recognized on a straight-line basis over the term of the PPA.
Revenues generated from the construction of geothermal and recovered energy power plant equipment and other equipment on behalf of third parties (product 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 Product 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. 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.
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Property, Plant and Equipment. We capitalize all costs associated with the acquisition, development and construction of power plant facilities. 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 PPAs, geothermal resources, the location of the assets and specific power plant 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 beginning when we acquire land rights to the potential geothermal resource. Prior to acquiring land rights, we make an initial assessment that an economically feasible geothermal reservoir is probable on that land using available data and external assessments vetted through our exploration department and occasionally outside service providers. Costs incurred prior to acquiring land rights are expensed. It normally takes one to two years from the time we start active exploration of a particular geothermal resource to the time we have an operating production well, assuming we conclude the resource is commercially viable.
In most cases, we obtain the right to conduct our geothermal development and operations on land owned by the BLM, various states or with private parties. In consideration for certain of these leases, we may pay an up-front non-refundable bonus payment which is a component of the competitive lease process. The up-front non-refundable bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. Once we acquire land rights to the potential geothermal resource, we perform additional activities to assess the commercial viability of the resource. Such activities include among others conducting surveys and other analyses, obtaining drilling permits, creating access roads to drilling sites, and exploratory drilling which may include temperature gradient holes and/or slim holes. Such costs are capitalized and included in construction-in-process. Once our exploration activities are complete, we finalize our assessment as to the commercial viability of the geothermal resource and either proceed to the construction phase for a power plant or abandon the site. If we decide to abandon a site, all previously capitalized costs associated with the exploration project are written off.
Our assessment of economic viability of an exploration project involves significant management judgment and uncertainties as to whether a commercially viable resource exists at the time we acquire land rights and begin to capitalize such costs. As a result, it is possible that our initial assessment of a geothermal resource may be incorrect and we would have to write-off costs associated with the project that were previously capitalized. During the years ended December 31, 2010, 2009 and, 2008, we determined that the geothermal resource at four of our exploration projects would not support commercial operations and abandoned the sites. As a result of this determination, we expensed $3,050,000, $2,367,000, and $9,828,000 of capitalized costs during the years ended December 31, 2010, 2009, and 2008, respectively. Due to the uncertainties inherent in geothermal exploration, these historical impairments may not be indicative of future impairments. Included in construction-in-process are costs related to projects in exploration and development of $54,697,000 and $33,617,000 at December 31, 2010 and 2009, respectively. Of this amount, $33,600,000 and $15,867,000 relates to up-front bonus payments at December 31, 2010 and 2009, respectively.
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Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. We evaluate long-lived assets, such as property, plant and equipment, construction-in-process, PPAs, 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, among others, significant underperformance relative to historical or projected future operating results, significant changes in our use of assets or our overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, 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.
We test our operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. We test for impairment our operating plants which are not operated as a complex, as well as our projects under exploration, development or construction that are not part of an existing complex, at the plant or project level. To the extent an operating plant becomes part of a complex in the future, we will test for impairment at the complex level.
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 power plant and rates to be received under the respective PPA; and (ii) projected operating expenses of the relevant power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset. If future cash flows are less than the assumptions we used in such estimates, we may incur impairment losses in the future that could be material to our financial condition and/or results of operations.
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. We believe that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances. 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.
The North Brawley power plant (North Brawley), which is under development, was tested for impairment in the current year due to the low output and higher than expected operating costs. Based on these indicators, we tested North Brawley for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. We applied a probability-weighted approach and considered alternative courses of action.
Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($245 million as of December 31, 2010) by approximately $46 million and therefore, no impairment occurred. Estimated undiscounted cash flow are subject to significant uncertainties. If actual cash flows differ from our current estimates due to factors that include, among others, if the plant’s generating capacity is less than approximately 45 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of our current projections, a material impairment write-down may be required in the future.
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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 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 power plant 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.
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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, more likely than not, and therefore 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 carryforwards. 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 deferred tax assets as of December 31, 2010, net of an immaterial valuation allowance related to state income taxes, 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
On January 1, 2010, we adopted the amended consolidation guidance for variable interest entities. As to the impact of the adoption of this amendment on the consolidated financial statements and the additional disclosure in such consolidated financial statements, see Note 6 to our consolidated financial statements set forth in Item 8 of this annual report.
On July 1, 2010, we adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The adoption of this accounting standards update resulted in a reclassification to retained earnings with an offset to other comprehensive income effective July 1, 2010.
See Note 1 to our consolidated financial statements set forth in Item 8 of this annual report for additional 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 power plants and enhancement of acquired power plants; and (ii) fluctuation in revenues from our Product Segment.
(1)
In January 2010, we sold our interest in our New Zealand subsidiary, GDL. As a result of such sale, the operations of GDL have been included in discontinued operations in the years ended December 31, 2009 and 2008.
Comparison of the Year Ended December 31, 2010 and the Year Ended December 31, 2009
Total Revenues
Total revenues for the year ended December 31, 2010 were $373.2 million, compared to $412.0 million for the year ended December 31, 2009, which represented a 9.4% decrease in total revenues. This decrease is attributable to our Product Segment whose revenues decreased by 48.9% from the same period in 2009 (for the reasons discussed below). Revenues in our Electricity Segment increased by 15.5% from the same period in 2009.
Electricity Segment
Revenues attributable to our Electricity Segment for the year ended December 31, 2010 were $291.8 million, compared to $252.6 million for the year ended December 31, 2009, which represented a 15.5% increase in such revenues. The increase is primarily a result of increased electricity generation at most of our power plants from 3,296,824 MWh in the year ended December 31, 2009 to 3,762,283 MWh in the year ended December 31, 2010, an increase of 14.1%. The most significant contributors to the increase in our electricity revenues were: (i) an increase in the generation of the Puna power plant following repair work that was completed in the second quarter of 2010; (ii) the placement in service of our North Brawley power plant in January 2010, with revenues of $15.0 million in the year ended December 31, 2010; and (iii) the consolidation of the Mammoth complex effective August 2, 2010, with revenues of $7.6 million in the period from August 2, 2010 to December 31, 2010, resulting from the acquisition of the remaining 50% interest in Mammoth Pacific. The increase in our Electricity Segment revenues is also attributable to a slight increase in the average revenue rate of our electricity portfolio from $77 per MWh in the year ended December 31, 2009 to $78 per MWh in the year ended December 31, 2010.
Product Segment
Revenues attributable to our Product Segment for the year ended December 31, 2010 were $81.4 million, compared to $159.4 million for the year ended December 31, 2009, which represented a 48.9% decrease in such revenues. This decrease in our product revenue is a result of reduced Product Segment customer orders for the year ended December 31, 2010. We expect a similar level of revenues from our Product Segment in 2011.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2010 was $295.6 million, compared to $291.6 million for the year ended December 31, 2009, which represented a 1.4% increase in total cost of revenues. This increase is attributable to an increase in our Electricity Segment cost of revenues, which was offset by a decrease in our Product Segment cost of revenues, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2010 was 79.2%, compared to 70.8% for the year ended December 31, 2009. This increase is mainly attributable to high costs in our North Brawley power plant, as described below, as well as the lower volume of Product Segment revenues.
Electricity Segment
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2010 was $242.3 million, which include $39.6 million (including depreciation) related to our North Brawley power plant, compared to $179.1 million for the year ended December 31, 2009, which represented a 35.3% increase in total cost of revenues for such segment. The increase over the same period last year is mainly attributable to our North Brawley power plant which was placed in service in January 2010. We have incurred high costs (including depreciation) associated with operating and maintaining this power plant, which has a design capacity of 50 MW but is currently operating at a reduced capacity. The higher costs in the North Brawley power plant increased the cost per MWh for the year ended December 31, 2010, compared to the year ended December 31, 2009. Further details on the operational issues at the North Brawley power plant are discussed in Item 1 - “Business” under the heading “Description of Our Power Plants” of this annual report. We expect to have high operation expenses at the North Brawley power plant for at least the next few quarters. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2010 was 83.0%, compared to 70.9% for the year ended December 31, 2009.
Product Segment
Total cost of revenues attributable to our Product Segment for the year ended December 31, 2010 was $53.3 million, compared to $112.5 million for the year ended December 31, 2009, which represented a 52.6% decrease in total cost of revenues related to such segment. This decrease is attributable to the decrease in product revenues, as described above. As a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2010 decreased from 70.6% for the year ended December 31, 2009 to 65.4% for the year ended December 31, 2010. This percentage decrease is attributable to the removal of a contingency relating to a project that was substantially completed in the second quarter of 2010.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2010 were $10.1 million, compared to $10.5 million for the year ended December 31, 2009, which represented a 3.6% decrease. Our research and development activities during the year ended December 31, 2010 included primarily: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals, including developing and building a unit at a customer’s premises in Spain. (ii) continued development of enhanced geothermal systems (EGS); and (iii) development of a solar thermal system for the production of electricity. Construction of the experimental REG plant commenced in the third quarter of 2010 and is expected to be completed in the first half of 2011. If the development of the unit is not successful we will have to remove the unit from the customer’s site. If the unit operates successfully and passes acceptance tests, we will be paid by the customer an amount of approximately $15.0 million which will be recognized as revenue upon acceptance by the customer. The research and development expenses are net of grants from the DOE in the amount of $0.9 million and $1.3 million for the years ended December 31, 2010 and 2009, respectively, with respect to the EGS project. We expect research and development expenses to decrease further in 2011 as a result of the completion of the experimental REG plant project.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2010 were $13.4 million, compared to $14.6 million for the year ended December 31, 2009, which represented an 7.8% decrease. The decrease was due primarily to the decrease in Product Segment revenues. Selling and marketing expenses for the year ended December 31, 2010 constituted 3.6% of total revenues for such period, compared to 3.5% for the year ended December 31, 2009.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2010 were $27.4 million, compared to $26.4 million for the year ended December 31, 2009, which represented a 3.9% increase. General and administrative expenses for the year ended December 31, 2010 constituted 7.4% of total revenues for such year, compared to 6.4% for the year ended December 31, 2009.
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year ended December 31, 2010 was $3.1 million, compared to $2.4 million for the year ended December 31, 2009. Write-off of unsuccessful exploration activities for the year ended December 31, 2010 relates to the Gabbs Valley exploration project in Nevada, which we determined in the second quarter of 2010 would not support commercial operations. Write-off of unsuccessful exploration activities for the year ended December 31, 2009 relates to the Rock Hills exploration project in Nevada, which we determined in the third quarter of 2009 would not support commercial operations.
Operating Income
Operating income for the year ended December 31, 2010 was $23.6 million, compared to $66.6 million for the year ended December 31, 2009. Such decrease of $43.0 million in operating income was principally attributable to a decrease in the total gross margin due to the decrease in Product Segment revenues and the increase in Electricity
Segment cost of revenues. Operating income attributable to our Electricity Segment for the year ended December 31, 2010 was $12.8 million, compared to $45.3 million for the year ended December 31, 2009, mainly due to the increase in electricity cost of revenues, as explained above. Operating income attributable to our Product Segment for the year ended December 31, 2010 was $10.8 million, compared to $21.3 million for the year ended December 31, 2009, mainly due to the decrease in product revenues, as explained above.
Interest Expense, Net
Interest expense, net, for the year ended December 31, 2010 was $40.5 million, compared to $16.2 million for the year ended December 31, 2009, which represented a 149.2% increase. The $24.2 million increase is primarily due to: (i) a decrease of $17.9 million in interest capitalized to projects as a result of decreased aggregate investment in projects under construction; (ii) an increase in interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants; (iii) borrowings under our revolving credit lines with banks; (iv) loan agreements with institutional investors and a commercial bank; and (v) issuance of Senior Unsecured Bonds on August 3, 2010, as discussed below. The increase was partially offset by a decrease in interest expense as a result of the acquisition of a 30% interest in the Class B membership units of OPC on October 30, 2009 by our subsidiary, Ormat Nevada, as well as principal repayments.
Foreign Currency Translation and Transaction Gains (Losses)
Foreign currency translation and transaction gains for the year ended December 31, 2010 were $1.6 million, compared to foreign currency translation and transaction losses of $1.7 million for the year ended December 31, 2009. The $3.3 million increase is primarily due to an increase in gains on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes.
Income Attributable to Sale of Tax Benefits
Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the year ended December 31, 2010 was $8.7 million, compared to $15.5 million for the year ended December 31, 2009. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease is due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing MACRS and to the purchase of Class B membership units of OPC from Lehman-OPC in October 2009, as described under “Gain from Extinguishment of Liability” below.
Gain on Acquisition of Controlling Interest
Gain on acquisition of controlling interest for the year ended December 31, 2010 was $36.9 million. This gain relates to the acquisition of the remaining 50% interest in Mammoth Pacific. The acquisition-date fair value of the previous 50%-equity interest was $64.9 million. In the year ended December 31, 2010, we recognized a pre-tax gain of $36.9 million ($22.4 million after tax), which is equal to the difference between the acquisition-date fair value of the initial investment in Mammoth Pacific and the acquisition-date carrying value of such investment.
Gain from Extinguishment of Liability
Gain from extinguishment of liability for the year ended December 31, 2009 was $13.3 million. On October 30, 2009, Ormat Nevada acquired Lehman-OPC’s 30% interest in the Class B membership units of OPC. The membership units were acquired from Lehman-OPC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million ($8.2 million after tax) in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million was classified in the year ended December 31, 2009 from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.
Income Taxes
Income tax benefit for the year ended December 31, 2010 was $1.1 million, compared to income tax provision of $15.4 million for the year ended December 31, 2009. The effective tax rate for the year ended December 31, 2010 was 3.6% compared to 19.7% for the year ended December 31, 2009. The decrease in the effective tax rate primarily resulted from the higher impact of PTCs on the effective tax rate for the year ended December 31, 2010 due to our low pretax income from continuing operations.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2010 was $1.0 million, compared to $2.1 million for the year ended December 31, 2009. The amount is derived mainly from our 50% ownership of the Mammoth complex which was included in the Company’s consolidated financial statements effective August 2, 2010, as a result of our acquisition of the remaining 50% interest in Mammoth Pacific. For the year ended December 31, 2010, the amount represents our share in the loss of the Mammoth complex in the period from January 1, 2010 to August 1, 2010.
Income from Continuing Operations
Income from continuing operations for the year ended December 31, 2010 was $32.9 million, compared to $65.1 million for the year ended December 31, 2009. Such decrease of $32.2 million in income from continuing operations was principally attributable to: (i) a $43.0 million decrease in operating income; (ii) a $24.2 million increase in interest expense, net; (iii) a $6.8 million decrease in income attributable to the sale of tax benefits; and (iv) gain from extinguishment of liability of $13.3 million in the year ended December 31, 2009. This was partially offset by: (i) a $3.3 million increase in foreign currency transaction and translation gains; (ii) gain on acquisition of controlling interest of $36.9 million in the year ended December 31, 2010; and (iii) a $16.5 million decrease in income tax provision.
Discontinued Operations
In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. We did not exercise our right of first refusal, and therefore we transferred our shares in GDL to the former shareholder. As a result, we recorded an after-tax gain of $4.3 million in the year ended December 31, 2010. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL.
Net Income
Net income for the year ended December 31, 2010 was $37.2 million, compared to $68.6 million for the year ended December 31, 2009, which represents a decrease of 31.3 million. Such decrease in net income was principally attributable to the decrease in income from continuing operations in the amount of $32.2 million, as discussed above.
Comparison of the Year Ended December 31, 2009 and the Year Ended December 31, 2008
Total Revenues
Total revenues for the year ended December 31, 2009 were $412.0 million, compared to $344.0 million for the year ended December 31, 2008, which represented a 19.8% increase in total revenues. This increase was primarily attributable to our Product Segment whose revenues increased by 72.2% from the same period in 2008 (for the reasons discussed below). Revenues in our Electricity Segment increased by 0.5% from the same period in 2008.
Electricity Segment
Revenues attributable to our Electricity Segment for the year ended December 31, 2009 were $252.6 million, compared to $251.4 million for the year ended December 31, 2008, which represented a 0.5% increase in such revenues. This increase resulted from an increase in our electricity generation from 2,932,031 MWh in the year
ended December 31, 2008 to 3,296,824 MWh in the year ended December 31, 2009, an increase of 12.4%. Despite the 12.4% increase in our electricity generation, our electricity revenues increased by a modest 0.5% due to the decline in the average revenue rate of our electricity portfolio from $86 per MWh in the year ended December 31, 2008 to $77 per MWh in the year ended December 31, 2009. The decrease in the average rate was mainly attributable to a decrease in the energy rates in the Puna power plant due to lower oil prices, and the expiration of the “adder”, an additional energy rate paid to us under the Heber 2 PPA at the end of July 2008. The increase in our electricity generation was attributable mainly to the 35 MW Phase II of the Olkaria III complex in Kenya, which started generating electricity in January 2009. In the United States, electricity generation increased due to: (i) the new Galena 3 power plant, which was placed in service in the second half of the first quarter of 2008; and (ii) the restored generating capacity of our Steamboat 2/3 power plant following the replacement of turbines during the second half of 2008. The increase in our electricity generation in the United States in the year ended December 31, 2009 was offset by a temporary decrease in the generating capacity of the Puna power plant due to the enhancement and repair of the geothermal wellfield, which we undertook to increase its capacity in advance of an 8 MW expansion
Product Segment
Revenues attributable to our Product Segment for the year ended December 31, 2009 were $159.4 million, compared to $92.6 million for the year ended December 31, 2008, which represented a 72.2% increase in such revenues. Most of this increase in revenues was derived from EPC contracts with third parties for the construction of three large binary geothermal projects, the Blue Mountain project in Nevada, the Centennial Binary Plant in New Zealand, and the Las Pailas project in Costa Rica.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2009 was $291.6 million, compared to $242.1 million for the year ended December 31, 2008, which represented a 20.4% increase in total cost of revenues. This increase was primarily attributable to the increase in the cost of revenues in our Product Segment, as discussed below. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2009 was 70.8% compared to 70.4% for the year ended December 31, 2008.
Electricity Segment
Total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2009 was $179.1 million, compared to $169.3 million for the year ended December 31, 2008, which represented a 5.8% increase in total cost of revenues for such segment. The increase from the same period last year was due to: (i) increased costs (including depreciation) as a result of new and enhanced projects placed into service; (ii) an increase in certain maintenance costs in order to ensure higher availability of geothermal resource during the summer, when electricity rates paid under the relevant PPA are higher; and (iii) increased repair costs of the geothermal wellfield in Puna. This increase was partially offset by decreased royalty costs in the Puna power plant as a result of lower revenues as discussed above. The cost per MWh in the year ended December 31, 2009 decreased compared to the year ended December 31, 2008 due to our higher volume of energy generation. As a percentage of total electricity revenues, the total cost of revenues attributable to our Electricity Segment for the year ended December 31, 2009 was 70.9%, compared to 67.3% for the year ended December 31, 2008.
Product Segment
Total cost of revenues attributable to our Product Segment for the year ended December 31, 2009 was $112.5 million, compared to $72.8 million for the year ended December 31, 2008, which represented a 54.6% increase in total cost of revenues related to such segment. This increase was attributable to the increase in our product revenues. Despite the increase in the Product Segment cost of revenues, as a percentage of total Product Segment revenues, our total cost of revenues attributable to this segment for the year ended December 31, 2009 decreased from 78.6% for the year ended December 31, 2008 to 70.6%. This decrease is mainly attributable to the higher volume of revenues coupled with a more moderate than estimated increase in our costs as a result of the global decrease in commodities prices.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2009 were $10.5 million, compared to $4.6 million for the year ended December 31, 2008, which represented a 128.6% increase. Our research and development activities during the year ended December 31, 2009 included: (i) an experimental REG plant specifically designed to use the residual energy from the vaporization process at LNG regasification terminals; (ii) EGS; and (iii) development of a solar thermal system for the production of electricity. The costs related to an experimental REG plant specifically designed to use the residual energy from the vaporization process at a liquefied natural gas regasification terminal in the amount of $7.5 million relate to a research and development project that includes developing and building a unit at a customer’s premises in Spain. The research and development expenses are net of grants from the DOE in the amount of $1.3 million and $0.6 million for the years ended December 31, 2009 and 2008, respectively, with respect to the EGS project.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2009 were $14.6 million, compared to $10.9 million for the year ended December 31, 2008, which represented a 34.0% increase. The increase was due primarily to an increase in expenses related to Product Segment revenues. Selling and marketing expenses for the year ended December 31, 2009 constituted 3.5% of total revenues for such period, compared to 3.2% for the year ended December 31, 2008.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2009 were $26.4 million, compared to $25.9 million for the year ended December 31, 2008, which represented a 1.8% increase. General and administrative expenses for the year ended December 31, 2009 constituted 6.4% of total revenues for such year, compared to 7.5% for the year ended December 31, 2008.
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year ended December 31, 2009 was $2.4 million, compared to $9.8 million for the year ended December 31, 2008. Write-off of unsuccessful exploration activities for the year ended December 31, 2009 relates to the Rock Hills exploration project in Nevada, which we determined in the third quarter of 2009 would not support commercial operations. Write-off of unsuccessful exploration activities for the year ended December 31, 2008 relates to the Buffalo Valley and Grass Valley exploration projects in Nevada, which we determined in the fourth quarter of 2008 would not support commercial operations.
Operating Income
Operating income for the year ended December 31, 2009 was $66.6 million, compared to $50.7 million for the year ended December 31, 2008. Such increase in operating income was principally attributable to an increase in revenues and gross margin of our Product Segment. Operating income attributable to our Electricity Segment for the year ended December 31, 2009 was $45.3 million, compared to $45.0 million for the year ended December 31, 2008. Operating income attributable to our Product Segment for the year ended December 31, 2009 was $21.3 million, compared to $5.7 million for the year ended December 31, 2008.
Interest Income
Interest income for the year ended December 31, 2009 was $0.6 million, compared to $3.1 million for the year ended December 31, 2008, which represented a 79.5% decrease. The decrease was primarily due to a decrease in cash and cash equivalents, marketable securities and restricted cash during the year ended December 31, 2009, as well as a decrease in interest rates payable on investments.
Interest Expense, Net
Interest expense, net, for the year ended December 31, 2009 was $16.2 million, compared to $14.9 million for the year ended December 31, 2008, which represented an 8.7% increase. The $1.3 million increase was primarily due to: (i) an increase in interest expenses related to our long-term project finance loans of the Olkaria III and Amatitlan power plants; (ii) borrowings under our revolving credit lines with banks; and (iii) loan agreements with institutional investors and a commercial bank. The increase was partially offset by an increase of $6.1 million in interest capitalized to projects primarily as a result of increased costs for projects under construction, as well as principal repayments.
Foreign Currency Translation and Transaction Losses
Foreign currency translation and transaction losses for the year ended December 31, 2009 were $1.7 million, compared to $4.4 million for the year ended December 31, 2008. The $2.7 million decrease was primarily due to a decrease in losses on forward foreign exchange transactions which do not qualify as hedge transactions for accounting purposes.
Impairment of Auction Rate Securities
In the year ended December 31, 2009, we recorded $0.3 million of impairment charges as a result of other-than-temporary declines in the value of certain auction rate securities, compared to $4.2 million in the year ended December 31, 2008. The carrying value of auction rate securities as of December 31, 2009 was $3.2 million.
Income Attributable to Sale of Tax Benefits
Income attributable to the sale of tax benefits to institutional equity investors (as described in “OPC Transaction” below) for the year ended December 31, 2009 was $15.5 million, compared to $18.1 million for the year ended December 31, 2008. This income represents the value of PTCs and taxable income or loss generated by OPC and allocated to the investors. The decrease was due to lower depreciation for tax purposes as a result of declining depreciation rates utilizing MACRS and to the purchase of Class B membership units of OPC from Lehman-OPC in October 2009, as described under “Gain from Extinguishment of Liability” below.
Gain from Extinguishment of Liability
Gain from extinguishment of liability for the year ended December 31, 2009 was $13.3 million. On October 30, 2009, Ormat Nevada acquired Lehman-OPC’s 30% interest in the Class B membership units of OPC. The membership units were acquired from Lehman-OPC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million ($8.8 million after tax) in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been classified in the year ended December 31, 2009 from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC’s Class B membership units.
Income Taxes
Income tax provision for the year ended December 31, 2009 was $15.4 million, compared to $5.3 million for the year ended December 31, 2008. The effective tax rate for the year ended December 31, 2009 and 2008 was 19.7% and 10.8%, respectively. The increase in the effective tax rate primarily resulted from a lower impact of PTCs on the effective tax rate for the year ended December 31, 2009 due to the increase in our income before income taxes.
Equity in Income of Investees
Our participation in the income generated from our investees for the year ended December 31, 2009 was $2.1 million, compared to $1.7 million for the year ended December 31, 2008. The amount is derived mainly from our 50% ownership of the Mammoth complex.
Income from Continuing Operations
Income from continuing operations for year ended December 31, 2009 was $65.1 million, compared to $45.5 million for year ended December 31, 2008. Such increase of $19.6 million in income from continuing operations was principally attributable to: (i) an increase of $15.9 million in our operating income; (ii) a decrease of $2.7 million in foreign currency transaction and translation losses; (iii) a decrease of $3.9 million in impairment of auction rate securities; and (iv) a $13.3 million gain from extinguishment of liability. This increase was partially offset by: (i) a $10.1 million increase in income tax provision; (ii) a $2.5 million decrease in interest income; (iii) a $1.3 million increase in interest expense, net; and (iv) a $2.6 million decrease in income attributable to sale of tax benefits.
Discontinued Operations
In January 2010, a former shareholder of GDL exercised a call option to purchase from us our shares in GDL for approximately $2.8 million. We did not exercise our right of first refusal and, therefore, we transferred our shares in GDL to the former shareholder. The operations of GDL have been included in discontinued operations for all periods prior to the sale of GDL.
Net Income
Net income for the year ended December 31, 2009 was $68.6 million, compared to $43.3 million for the year ended December 31, 2008, which represents an increase of 58.4%. Such increase in net income was principally attributable to the increase in income from continuing operations in the amount of $19.6 million and to an increase of $5.7 million in income from discontinued operations, as discussed above.
Liquidity and Capital Resources
Our principal sources of liquidity have been derived from cash flows from operations, the issuance of our common stock in public and private offerings, proceeds from third party debt in the form of borrowings under credit facilities and private offerings, issuance by OFC and OrCal of their respective Senior Secured Notes, project financing (including the Puna lease and the OPC Transaction described below), and a cash grant we received under the ARRA in respect of the North Brawley power plant. We have utilized this cash to fund our acquisitions (including the acquisition of the remaining 50% ownership of the Mammoth complex in August 2010), to develop and construct power generation plants, and to meet our other cash and liquidity needs.
As of December 31, 2010, we have access to the following sources of funds: (i) $82.8 million in cash and cash equivalents; and (ii) $149.1 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.
Our estimated capital needs for 2011 include approximately $467 million for capital expenditures on new projects under development or construction, exploration activity, operating projects, and machinery and equipment, as well as $49.0 million for debt repayment.
We expect to finance these requirements with: (i) the sources of liquidity described above; (ii) cash flows from our operations; (iii) proceeds of approximately $108 million that we received from the issuance of additional senior unsecured notes to institutional investors in February 2011 (see below); (iv) proceeds of $24.9 million from the sale by Ormat Nevada on February 3, 2011 of all its Class B membership units of OPC that it acquired on October 30, 2009 (see below); (v) additional borrowing capacity under future lines of credit with commercial banks that are under negotiations; (vi) future project financing and refinancing; and (vii) cash grants available to us under the ARRA in respect of new projects that will be placed in service before the end of 2013. 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 October 2, 2008, provides us with the ability to raise additional capital of up to $1.5 billion through the issuance of securities, subject to market conditions.
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
OFC Senior Secured Notes - Non-Recourse
On February 13, 2004, OFC, one of our subsidiaries, issued $190.0 million of OFC Senior Secured Notes in an offering subject to Rule 144A and Regulation S of the Securities Act, 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, 2010, OFC was in compliance with the covenants under the OFC Senior Secured Notes. As of December 31, 2010, there were $136.3 million of OFC Senior Secured Notes outstanding.
OrCal Geothermal Senior Secured Notes - Non-Recourse
On December 8, 2005, OrCal, one of our subsidiaries, issued $165.0 million of OrCal Senior Secured Notes in an offering subject to Rule 144A and Regulation S of the Securities Act, 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, 2010, OrCal was in compliance with the covenants under the OrCal Senior Secured Notes. As of December 31, 2010, there were $95.6 million of OrCal Senior Secured Notes outstanding.
Olkaria III Loan - Non-Recourse
In March 2009, OrPower 4 closed a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III complex located in Kenya. We initially financed construction of Phase I and Phase II of the project, as well as the drilling of wells, with our own funds. The loan is provided by a group of European DFIs arranged by DEG. The first disbursement of $90.0 million was made on March 23, 2009, and the second disbursement of $15.0 million was made on July 10, 2009. The loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments. Interest on the loan is variable based on 6-month LIBOR plus 4.0%, but we had the option to fix the interest rate upon each disbursement. We fixed the interest rate on $77.0 million of the loan at 6.90% per annum. There are various restrictive covenants under the loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, OrPower 4 was in compliance with the covenants under the loan. As of December 31, 2010, $88.4 million of the above loan was outstanding.
Amatitlan Loan - Non-Recourse
In May 2009, Ortitlan entered into a note purchase agreement in an aggregate principal amount of $42.0 million to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala. We initially financed the construction of the project, as well as the drilling of wells with corporate funds. The loan was
provided by TCW Global Project Fund II, Ltd. The loan will mature on June 15, 2016, and is payable in 28 quarterly installments. The annual interest rate on the loan is 9.83%, but the effective cost for us is approximately 8%, due to the elimination, following the refinancing, of the political risk insurance premiums that we had been paying on our equity investment in the project. There are various restrictive covenants under the loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, Ortitlan was in compliance with the covenants under the loan. As of December 31, 2010, $39.0 million of the above loan was outstanding.
Senior Loan from IFC - Non-Recourse
Orzunil has a senior loan agreement with IFC. The loan, of which $1.7 million was outstanding as of December 31, 2010, has a fixed annual interest rate of 11.775%, and matures on November 15, 2011. There are various restrictive covenants under this senior loan, which include limitations on Orzunil’s ability to make distributions to its shareholders. As of December 31, 2010, Orzunil was in compliance with the covenants under this senior loan.
New Financing of our Projects
Financing of the North Brawley Power Plant
We refinanced a portion of the equity invested in the North Brawley power plant with the cash grant we received under the ARRA in September 2010. We expect that once we bring the power plant closer to its original design capacity, we will be able to refinance a portion of the remainder with long-term debt.
Financing for Jersey Valley, McGinness Hills and Tuscarora Projects in Nevada
Our subsidiary, Ormat Nevada, has engaged John Hancock to arrange senior secured construction and term loan facilities under a United States DOE loan guarantee program of up to $350 million for three geothermal projects currently under construction in Nevada. The three projects are the Jersey Valley, McGinness Hills, and Tuscarora geothermal projects. Construction of all three projects has already commenced with commercial operation of the first phase of each project expected between 2011 and 2013.
The availability of the credit facilities is subject to various conditions, including execution of mutually satisfactory documentation and approval of the DOE.
John Hancock and the DOE are conducting a due diligence review of the three projects. Upon the satisfactory completion of the review, John Hancock and the DOE will consider issuing a conditional commitment which may lead to a loan guarantee, although we have no assurance this will occur.
Full-Recourse Third-Party Debt
In December 2008, our subsidiary, Ormat Nevada, entered into an amendment of its credit agreement with Union Bank extending the final maturity of the facility and increasing its total amount to $37.5 million. 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. Union Bank 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 a 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, and subject to specified carve-outs and exceptions, a negative pledge on the assets of Ormat Nevada in favor of Union Bank.
As of December 31, 2010, letters of credit in the aggregate amount of $34.4 million remain issued and outstanding under this credit agreement with Union Bank.
We also have credit agreements with five commercial banks for an aggregate amount of $365.0 million. Under the terms of these credit agreements, we or our Israeli subsidiary, Ormat Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $315.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $50.0. The credit agreements mature between May 2011 and September 2013. 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. Credit agreements in the amount of $165.0 million are due to expire in 2011. We are currently negotiating the extension of these credit agreements for up to three years. We anticipate that these extensions will include an increase in the annual average interest rates.
As of December 31, 2010, loans in the total amount of $189.5 million were outstanding, and letters of credit with an aggregate stated amount of $29.5 million were issued and outstanding under such credit agreements. The $189.5 million in loans are for terms of three months or less and bear interest at an annual weighted average rate of 2.03% as of December 31, 2010.
We have a $20.0 million term loan with a group of institutional investors, which matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%. As of December 31, 2010, $17.2 million was outstanding under this loan.
We have a $20.0 million term loan with a group of institutional investors, which matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%. As of December 31, 2010, $20.0 million was outstanding under this loan.
We also have a $20.0 million term loan with a group of institutional investors, which matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears annual interest of 5.75%. As of December 31, 2010, $20.0 million was outstanding under this loan.
We have a $50.0 million term loan with a commercial bank, which matures on November 10, 2014, and is payable in ten semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%. As of December 31, 2010, $40.0 million was outstanding under this loan.
We have an aggregate principal amount of approximately $250.0 million of Senior Unsecured Bonds issued and outstanding. We issued approximately $142.0 million of these bonds in August 2010 and an additional $107.5 million in February 2011. Subject to early redemption, the principal of the bonds is repayable in a single bullet payment upon the final maturity of the bonds on August 1, 2017. The bonds bear interest at a fixed rate of 7% per annum, payable semi-annually. The bonds that we issued in February 2011 were issued at a premium which reflects an effective fixed interest of 6.75% per annum. We issued the bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act.
Our obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but we are subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, 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, or a change of control in our ownership structure. Some of the credit agreements, the loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, we have agreed to maintain certain financial ratios such as a debt service coverage ratio, a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. 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 are currently in compliance with our covenants with respect to the credit agreements, the loan agreements and the trust instrument, and believe that the restrictive covenants, financial ratios and other terms of any of our (or Ormat Systems’) full-recourse bank credit agreements will not materially impact our business plan or plan of operations.
Letters of Credit
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.
Two commercial banks have issued such performance letters of credit in favor of our customers from time to time. As of December 31, 2010, such banks have issued on our behalf letters of credit totaling $17.1 million. These letters of credit were not issued under the credit agreements discussed under “Full-Recourse Third Party Debt” above.
In addition, we and certain of our subsidiaries may request letters of credit under the credit agreements with Union Bank and five other commercial banks as described above under “Full-Recourse Third Party Debt”. As of December 31, 2010, letters of credit in the aggregate amount of $67.0 million remained issued and outstanding under the Union Bank credit agreement and our other agreements with commercial banks.
Puna Power Plant Lease Transactions
On May 19, 2005, our subsidiary in Hawaii, 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 payments of $83.0 million by such financing parties to PGV , which are accounted for as deferred lease income.
OPC Transaction
In June 2007, our wholly owned subsidiary, Ormat Nevada, entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. (Morgan Stanley Geothermal LLC and Lehman-OPC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC, entitling the investors to certain tax benefits (such as PTCs and accelerated depreciation) and distributable cash associated with four geothermal power plants.
The first closing under the agreements occurred in 2007 and covered our Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.
Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants until it recovered the capital that it invested in the power plants, which occurred in the fourth quarter of 2010, while the investors receive substantially all of the PTCs and the taxable income or loss, and receive the distributable cash flow after Ormat Nevada recovered its capital. The 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, 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 power plants.
The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty, and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments.
Our voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. We own, through our subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC. The investors own all of the Class B membership units, which represent 25% of the voting rights of OPC. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC pursuant to a right of first offer for a purchase price of $18.5 million. As a result of that transaction, Lehman-OPC has no further interest in OPC.
On February 3, 2011, Ormat Nevada sold to JPM Capital Corporation (JPM) all of the Class B membership units of OPC that it had acquired on October 30, 2009 for a sale price of $24.9 million in cash. We will not record any gain from the sale of our Class B membership interests in OPC to JPM.
Liquidity Impact of Uncertain Tax Positions
As discussed in Note 19 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 approximately $5.4 million as of December 31, 2010. 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 affect 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, 2010
Net cash provided by operating activities for the year ended December 31, 2010 was $101.4 million, compared to $110.8 million for the year ended December 31, 2009. The net decrease of $9.4 million resulted primarily from: (i) a decrease in net income to $37.2 million in the year ended December 31, 2010, from $68.6 million in the year ended December 31, 2009, mainly as a result of the decrease in operating income, as described above; (ii) gain on acquisition of controlling interest of $36.9 million in the year ended December 31, 2010; (iii) a gain on sale of GDL of $6.4 million in the year ended December 31, 2010; and (iv) a net decrease in deferred income taxes of $10.1 million in the year ended December 31, 2010, compared to a net increase of $4.0 million in the year ended December 31, 2009. Such decrease was partially offset by: (i) an increase of $22.4 million in depreciation and amortization mainly due to the placement in service of our North Brawley power plant in January 2010, as described above; (ii) a gain from extinguishment of liability of $13.3 million in the year ended December 31, 2009; (iii) a net decrease in costs and estimated earnings in excess of billings on uncompleted contracts of $8.7 million in the year ended December 31, 2010, compared to a net increase of $20.0 million in the year ended December 31, 2009; and (iv) an increase in accounts payable and accrued expenses of $9.7 million in the year ended December 31, 2010, compared to a decrease of $2.1 million in the year ended December 31, 2009.
Net cash used in investing activities for the year ended December 31, 2010 was $203.8 million, compared to $286.0 million for the year ended December 31, 2009. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2010 were: (i) capital expenditures of $283.3 million, primarily for our facilities under construction; and (ii) net payment of $64.5 million for acquisition of controlling interest in Mammoth Pacific ($72.5 million purchase price less $8.0 million available cash in such subsidiary at the acquisition date); offset by: (i) $108.3 million of cash grant received in September 2010 for Specified Energy Property in Lieu of Tax Credits relating to our North Brawley geothermal power plant under Section 1603 of the ARRA; (ii) $19.6 million cash received from the sale of GDL; and (iii) a $17.5 million decrease in restricted cash, cash equivalents and marketable securities.
Net cash provided by financing activities for the year ended December 31, 2010 was $138.9 million, compared to $187.0 million for the year ended December 31, 2009. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2010 were: (i) the issuance of an aggregate amount of approximately $142.0 million of Senior Unsecured Bonds on August 3, 2010; (ii) $20.0 million proceeds from a long-term loan agreement with a group of institutional investors; and (iii) $55.5 million increase in amounts drawn under revolving lines of credit from banks; offset by: (i) the repayment of long-term debt to our parent in the amount of $9.6 million; (ii) the repayment of debt to third parties in the amount of $52.2 million; and (iii) the payment of a dividend to our shareholders in the amount of $12.3 million.
For the Year Ended December 31, 2009
Net cash provided by operating activities for the year ended December 31, 2009 was $110.8 million, compared to $116.9 million for the year ended December 31, 2008. The net decrease of $6.1 million resulted primarily from: (i) the net increase in costs and estimated earnings in excess of billings on uncompleted contracts of $20.0 million in the year ended December 31, 2009, compared to net decrease of $7.5 million in the year ended December 31, 2008; and (ii) a decrease in accounts payable and accrued expenses of $2.0 million in the year ended December 31, 2009,
compared to an increase of $13.5 million in the year ended December 31, 2008. Such decrease was partially; offset by: (i) the increase in net income to $68.6 million in the year ended December 31, 2009 from $43.3 million in the year ended December 31, 2008, as described above; and (ii) a decrease in receivables and prepaid expenses of $8.1 million in the year ended December 31, 2009, compared to an increase of $15.5 million in the year ended December 31, 2008.
Net cash used in investing activities for the year ended December 31, 2009 was $286.0 million, compared to $399.0 million for the year ended December 31, 2008. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2009 were capital expenditures of $270.6 million, primarily for our facilities under construction, and a $15.9 million increase in restricted cash, cash equivalents and marketable securities.
Net cash provided by financing activities for the year ended December 31, 2009 was $187.0 million, compared to $269.3 million for the year ended December 31, 2008. The principal factors that affected the cash flows provided by financing activities during the year ended December 31, 2009 were: (i) the proceeds of $105.0 million from the Olkaria III Loan; (ii) proceeds of $42.0 million from the Amatitlan Loan; (iii) $34.0 million increase in amounts drawn under revolving lines of credit from banks; (iv) proceeds of $40.0 million from long-term loan agreements with two groups of institutional investors; and (v) proceeds of $50.0 million from long-term loan agreement with a commercial bank; offset by: (i) the repayment of long-term debt to our parent in the amount of $16.6 million; (ii) the repayment of debt to third parties in the amount of $33.2 million; and (iii) the payment of a dividend to our shareholders in the amount of $11.3 million.
Adjusted EBITDA
Adjusted EBITDA for the year ended December 31, 2010 decreased to $164.3 million, compared to $167.0 million for the year ended December 31, 2009. Adjusted EBITDA for the year ended December 31, 2009 increased to $167.0 million, compared to $121.9 million for the year ended December 31, 2008. Adjusted EBITDA includes consolidated EBITDA and the Company’s share in the interest, taxes, depreciation and amortization related to the Company’s unconsolidated 50% interest in the Mammoth complex.
We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate adjusted EBITDA to include depreciation and amortization, interest and taxes attributable to our equity investments in the Mammoth complex. EBITDA and adjusted EBITDA are not measurements of financial performance or liquidity under GAAP and should not be considered as an alternative to cash flow from operating activities or as a measure of liquidity or an alternative to net earnings as indicators of our operating performance or any other measures of performance derived in accordance with GAAP. EBITDA and adjusted EBITDA are presented because we believe they are frequently used by securities analysts, investors and other interested parties in the evaluation of a Company’s ability to service and/or incur debt. However, other companies in our industry may calculate EBITDA and adjusted EBITDA differently than we do. This information should not be considered in isolation or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.
The following table reconciles net cash provided by operating activities to EBITDA and adjusted EBITDA, for the years ended December 31 2010, 2009, and 2008:
Capital Expenditures
Our capital expenditures primarily relate to two principal components: (i) the enhancement of our existing power plants; and (ii) the development and construction 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 have estimated approximately $570 million in capital expenditures for construction of new projects that are still under construction and that are expected to be completed by 2013. We have invested approximately $122 million of such estimated amount as of December 31, 2010. We expect to invest an additional $232 million of such total in 2011. The remaining $216 million will be invested in 2012 and 2013.
We also estimate approximately $235 million in additional capital expenditures in 2011 to be allocated as follows: (i) $114 million in new projects under development; (ii) $19 million for enhancement of our operating power plants; (iii) $10 million in land acquisition; (iv) $46 million in exploration activities in various leases for geothermal resources in which we have started the exploration activity; (v) $36 million in new project development, provided that part or all of the aforementioned exploration activities succeed; and (vi) $10 million in enhancement of our production facilities.
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 PPAs (except for the Puna PPA for 25 MW) 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 PPAs of the Heber 1 and 2 power plants, the Ormesa complex and the Mammoth complex will be determined by reference to the relevant power purchaser’s short run avoided costs, that are impacted by natural gas prices which may decline. Decreases in the price of natural gas will result in a decrease in the incremental cost that the power purchaser avoids by not generating its electrical energy needs from natural gas, which will result in a reduction of the energy rate that we may charge. The Puna power plant is currently
benefiting from energy prices which are higher than the floor under the Puna PPA for 25 MW as a result of the high fuel costs that impact HELCO’s avoided costs.
As of December 31, 2010, 65.4% of our consolidated long-term debt was in the form of fixed rate securities and therefore not subject to interest rate volatility risk. As of such date, 34.6% of our debt was in the form of a floating rate instrument, exposing us to changes in interest rates in connection therewith. As of December 31, 2010, $272.9 million of our debt remained subject to some floating rate risk.
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).
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. 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.
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 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. Substantially all of our PPAs 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.
Effect of Inflation
We do not expect that inflation will be a significant risk in the near term, given the current global economic conditions. However, that could change in the future. 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 PPAs that could be triggered upon such occurrences. The energy payments pursuant to the PPAs for the Brady power plant, the Steamboat 2/3 power plant, the Steamboat Hills power plant, and the Burdette power plant increase every year through the end of the relevant terms of such agreements, though such increases are not directly linked to the CPI or any other inflationary index. Lease payments are generally fixed, while royalty payments are generally determined as a percentage of revenues and therefore are not significantly impacted by inflation. In our Product Segment, inflation may directly impact fixed and variable costs incurred in the construction of our power plants, hence
increasing our operating costs in that segment. In this segment, it is more likely that we will be able to offset part or all of the inflationary impact through our project pricing. With respect to power plants that we construct for our own electricity production, inflationary pricing may impact our operating costs which may be partially offset in the pricing of the new long-term PPAs that we negotiate. Overall, we believe that the impact of inflation on our business will not be significant.
Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of December 31, 2010 (in thousands):
(1)
Interest on the OFC Senior Secured Notes due in 2020 is fixed at a rate of 8 1/4%. Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the Orzunil Senior Loan due in 2011 is fixed at a rate of 11.775%. Interest on the Olkaria III loan due in 2018 is fixed for $77.0 million at a rate of 6.9% and variable on the remaining balance. Interest on the Amatitlan Loan due in 2016 is fixed at a rate of 9.83%. Interest on the Senior Unsecured Bonds due in 2017 is fixed at a rate of 7%. 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.
(2)
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.
(3)
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 our requirements. At December 31, 2010, total obligations related to such supplier agreements were approximately $56.6 million (out of which approximately $36.8 million relate to construction-in-process). All such obligations are payable in 2011.
The above table does not reflect unrecognized tax benefits of $5.4 million the timing of which is uncertain. Refer to Note 19 to our consolidated financial statements set forth in Item 8 of this annual report for additional discussion of unrecognized tax benefits. The above table also does not reflect a liability associated with the sale of tax benefits of $66.6 million the timing of which is uncertain. Refer to Note 13 of our consolidated financial statements as set forth in Item 8 of this annual report for additional discussion of this liability.
Concentration of Credit Risk
Our credit risk is currently concentrated with a limited number of major customers: Southern California Edison, HELCO, and Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.). If any of these electric utilities fails to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition.
Southern California Edison accounted for 29.1%, 21.1%, and 27.7% of our total revenues for the three years ended December 31, 2010, 2009, and 2008, respectively. Southern California Edison is also the power purchaser and revenue source for our Mammoth project, which we accounted for separately under the equity method of accounting through August 1, 2010.
Sierra Pacific Power Company and Nevada Power Company accounted for 15.0%, 13.0%, and 12.6% of our total revenues for the three years ended December 31, 2010, 2009, and 2008 and, respectively.
HELCO accounted for 8.6%, 6.3%, and 16.8% of our total revenues for the three years ended December 31, 2010, 2009, and 2008, respectively.
Government Grants and Tax Benefits
The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted ARRA. We are permitted to claim 30% of the cost of each new geothermal power plant in the United States as an ITC against our federal income taxes. Alternatively, we are permitted to claim a PTC, which in 2010 was 2.2 cents per kWh and which is adjusted annually for inflation. The PTC may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The owner of the project must choose between the PTC and the 30% ITC 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 PTC or the ITC, 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 ITC, our “tax basis” in the plant that we can recover through depreciation must be reduced by half of the tax credit. If we claim a PTC, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during 2009, 2010 or 2011 or that begin construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the ITC. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.
Production of electricity from geothermal resources is also supported under the new “Temporary Program For Rapid Deployment of Renewable Energy and Electric Power Transmission Projects” established with the DOE as part of the DOE’s existing Innovative Technology Loan Guarantee Program. The new program: (i) extends the scope of the existing federal loan guarantee program to cover renewable energy projects, renewable energy component manufacturing facilities, and electricity transmission projects that embody established commercial, as well as innovative, technologies; and (ii) provides an appropriation to cover the “credit subsidy costs” of such projects (meaning the estimated average costs to the federal government from issuing the loan guarantee, equivalent to a lending bank’s loan loss reserve).
To be eligible for a guarantee under the new program, a supported project must break ground, and the guarantee must be issued, by September 30, 2011. A project supported by the federal guarantee under the new program must pay prevailing federal wages.
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 a period of two years that started in 2004, and thereafter such income is subject to reduced Israeli income tax rates, which will not exceed 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 a period of two years that started in 2007, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 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 arm’s 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 Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to
income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt whether to irrevocably implement the new law while waiving benefits provided under the current law or keep implementing the current law during the next years. Changing from the current law to the new law is permissible at any stage.
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
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, equity and cash flows present fairly, in all material respects, the financial position of Ormat Technologies, Inc. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, 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.
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
February 28, 2011
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying notes are an integral part of the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the consolidated 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, Guatemala, and Nicaragua. 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, 2010.
Cash dividends
During the years ended December 31, 2010, 2009, and 2008, the Company’s Board of Directors declared, approved, and authorized the payment of cash dividends in the aggregate amount of $12.3 million ($0.27 per share), $11.3 million ($0.25 per share), and $8.9 million ($0.20 per share) respectively. Such dividends were paid in the years declared.
Issuance of stock and shelf registration statements
On January 8, 2008, the Company completed an unregistered sale of 693,750 shares of common stock to the Parent, at a price of $48.02 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 May 14, 2008, the Company completed a sale of 3,100,000 shares of common stock to Lehman Brothers Inc. in a block trade at a price of $48.36 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 $149.7 million.
On September 17, 2008, the Company filed a universal shelf registration statement on Form S-3, which was declared effective by the Securities and Exchange Commission (“SEC”) on October 2, 2008. The shelf registration statement replaces the Company’s former shelf registration statement, which would have expired on January 31, 2009, and 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 $1.5 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.
Rounding
Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000, unless otherwise indicated.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Reclassification
Certain comparative figures have been reclassified to conform to the current year presentation (see Note 17).
Basis of presentation
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) 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, net” 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
At December 31, 2010 and 2009, all of the Company’s investments in auction rate securities were classified as available-for-sale securities and as a result, were reported at their fair value which was determined based on the factors discussed in Note 7.
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 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 (see Note 7). Such amounts are invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”, and auction rate securities.
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, 2010 and 2009, the Company had deposits totaling $55,537,000 and $24,561,000, respectively, in seven U.S. financial institutions that were federally insured up to $250,000 per account (after December 31, 2013, the deposits will be insured up to $100,000 per account). At December 31, 2010 and 2009, the Company’s deposits in foreign countries of approximately $37,929,000 and $35,095,000, respectively, were not insured.
At December 31, 2010 and 2009, accounts receivable related to operations in foreign countries amounted to approximately $26,128,000 and $30,761,000, respectively. At December 31, 2010 and 2009, accounts receivable
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
from the Company’s major customers that have generated 10% or more of its revenues (see Note 20) amounted to approximately 40% and 61%, respectively, of the Company’s accounts receivable.
Southern California Edison Company (“SCE”) accounted for 29.1%, 21.1%, and 27.6% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, respectively. SCE is also the power purchaser and revenue source for the Mammoth complex, which was accounted for separately under the equity method through August 1, 2010.
Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy, Inc.) accounted for 15.0%, 13.0%, and 12.6% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, respectively.
Hawaii Electric Light Company accounted for 8.6%, 6.3%, and 16.8% of the Company’s total revenues for the years ended December 31, 2010, 2009, and 2008, 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 weighted-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories, which amount was not significant at December 31, 2010 and 2009.
Deferred Charges
Deferred charges represent prepaid income taxes on intercompany sales. Such amounts are being amortized and included in income tax provision over the life of the related property, plant and equipment.
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, which include geothermal wells and exploration and resource development costs, are depreciated using the straight-line method over their estimated useful lives, which range from 25 to 30 years. The geothermal power plant in Zunil, Guatemala is to be fully depreciated over the term of the PPA, since the Company does not own the geothermal resource used by the plant. The geothermal power plant in Nicaragua is to be fully depreciated over the period that the plant is operated by the Company (see Note 8). The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $9,493,000, $27,395,000, and $21,312,000 for the years ended December 31, 2010, 2009, and 2008, respectively.
Cash grant
On August 27, 2010, the Company was awarded a cash grant from the U.S. Department of Treasury (“U.S. Treasury”) for Specified Energy Property in Lieu of Tax Credits under Section 1603 of the American Recovery and Reinvestment Act of 2009 (“ARRA”) in the amount of $108.3 million relating to its North Brawley geothermal power plant. The plant’s estimated useful life is 30 years. The Company has recorded the cash grant as a reduction in the carrying value of the plant and is amortizing the grant as a reduction in depreciation expense over the plant’s estimated useful life. During the year ended December 31, 2010, amortization of the cash grant reduced depreciation expense by $1.4 million.
For federal income tax purposes, the tax basis of the plant is only reduced by 50 percent of the cash grant. To account for the tax effect of the difference between the tax and book basis of the plant, the Company has recorded a deferred tax asset of $33.8 million with a corresponding decrease in the carrying value of the plant. This reduction in the carrying value of the plant will be amortized as a reduction in depreciation expense over the plant’s estimated useful life. During the year ended December 31, 2010, amortization of this basis difference reduced depreciation expense by $0.4 million.
Exploration and development costs
The Company capitalizes costs incurred in connection with the exploration and development of geothermal resources once it acquires land rights to the potential geothermal resource. Prior to acquiring land rights, the Company makes an initial assessment that an economically feasible geothermal reservoir is probable on that land. The Company determines the economic feasibility of potential geothermal resources internally, with all available data and external assessments vetted through the exploration department and occasionally using outside service providers. Costs associated with the initial assessment are expensed and included in cost of electricity revenues in the consolidated statements of operations and comprehensive income. Such costs were immaterial during the years ended December 31, 2010, 2009, and 2008. It normally takes one to two years from the time active exploration of a particular geothermal resource begins to the time a production well is in operation, assuming the resource is commercially viable.
In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the Bureau of Land Management (“BLM”), various states or with private parties. In consideration for certain of these leases, the Company may pay an up-front bonus payment which is a component of the competitive lease process. The up-front bonus payments and other related costs, such as legal fees, are capitalized and included in construction-in-process. The annual land lease payments made during the exploration, development and construction phase are expensed as incurred and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income. Upon commencement of power generation on the leased land, the Company begins to pay to the lessors long-term royalty payments based on the utilization of the geothermal resources as defined in the respective agreements. Such payments are expensed when the related revenues are earned and included in “electricity cost of revenues” in the consolidated statements of operations and comprehensive income.
Following the acquisition of land rights to the potential geothermal resource, the Company conducts further studies and surveys, including water and soil analyses among others, and augments its database with the results of
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these studies. The Company then initiates a suite of geophysical surveys to assess the resource and determine drilling locations. If the results of these activities support the initial assessment of the feasibility of the geothermal resource, the Company then proceeds to exploratory drilling and other related activities which may include drilling of temperature gradient holes, drilling of slim holes, building access roads to drilling locations, drilling full size production and/or injection wells and flow tests. If the slim hole supports a conclusion that the geothermal resource will support a commercially viable power plant, it may either be converted to a full-size commercial well, used either for extraction or re-injection or geothermal fluids, or used as an observation well to monitor and define the geothermal resource. Costs associated with these activities and other directly attributable costs, including interest once physical exploration activities begin and permitting costs are capitalized and included in “construction-in-process”. If the Company concludes that a geothermal resource will not support commercial operations, capitalized costs are expensed in the period such determination is made.
Grants received from the U.S. Department of Energy are offset against the related exploration and development costs. Such grants amounted to $1,116,000, $0, and $0 for the years ended December 31, 2010, 2009, and 2008, respectively.
All exploration and development costs that are being capitalized, including the up-front bonus payments made to secure land leases, will be depreciated over their estimated useful lives when the related geothermal power plant is substantially complete and ready for use. A geothermal power plant is substantially complete and ready for use when electricity generation commences.
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 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 $12,966,000 and $9,924,000 at December 31, 2010 and 2009, respectively. Amortization expense for the years ended December 31, 2010, 2009, and 2008 amounted to $3,042,000, $3,060,000, and $1,499,000, respectively. In the year ended December 31, 2009 an amount of $834,000 was written-off as a result of the extinguishment of a liability.
Deferred transaction costs relating to the Puna operating lease (see Note 12) in the amount of $4,172,000 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 $1,037,000 and $853,000 at December 31, 2010 and 2009, respectively. Amortization expense for each of the years ended December 31, 2010, 2009, and 2008 amounted to $184,000.
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.
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Impairment of long-lived assets and long-lived assets to be disposed of
The Company evaluates long-lived assets, such as property, plant and equipment, construction-in-process, PPAs, 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, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company’s use of assets or its overall business strategy, negative industry or economic trends, a determination that an exploration project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold.
The Company tests its operating plants that are operated together as a complex for impairment at the complex level because the cash flows of such plants result from significant shared operating activities. For example, the operating power plants in a complex are managed under a combined operation management generally with one central control room that controls all of the power plants in a complex and one maintenance group that services all of the power plants in a complex. As a result, the cash flows from individual plants within a complex are not largely independent of the cash flows of other plants within the complex. The Company tests for impairment its operating plants which are not operated as a complex as well as its projects under exploration, development or construction that are not part of an existing complex at the plant or project level. To the extent an operating plant becomes part of a complex, the Company will test for impairment at the complex level.
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 the Company uses in estimating its undiscounted future cash flows include: (i) projected generating capacity of the complex or power plant and rates to be received under the respective PPA(s); and (ii) projected operating expenses of the relevant complex or power plant. Estimates of future cash flows used to test recoverability of a long-lived asset under development also include cash flows associated with all future expenditures necessary to develop the asset.
If the 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. Management believes that no impairment exists for long-lived assets; however, estimates as to the recoverability of such assets may change based on revised circumstances (see Note 8).
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 forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by exchange rate or 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 the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated to qualify as a cash flow hedge are included currently in earnings.
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Foreign currency translation
The U.S. dollar is the functional currency for substantially all of the Company’s consolidated operations and those of its equity affiliates. For those entities, all gains and losses from currency translations are included in results of operations. For the subsidiary in New Zealand that was sold in January 2010, and which was using a functional currency other than the U.S. dollar, the cumulative translation effects were included in “accumulated other comprehensive income” in the consolidated balance sheets.
Comprehensive income reporting
Comprehensive income includes net income plus other comprehensive income, which for the Company consists of foreign currency translation adjustments, the non-credit portion of unrealized gain or loss on available-for-sale marketable securities 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. The PPAs are exempt from derivative treatment due to the normal purchase and sale exception. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003 revenues related to the lease element of the PPAs are included in electricity revenues. The lease element of the PPAs is determined in accordance with the revenue arrangements with multiple deliverables guidance, which requires that revenues be allocated to the separate earnings processes based on their relative fair value. PPAs with minimum lease rentals which vary over time are generally recognized on the straight-line basis over the term of the PPA.
The components of electricity revenues are as follows:
The components of cost of electricity revenues are as follows:
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
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recovered energy power plant equipment and other equipment to third parties are recognized using the percentage of 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 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, 2010, 2009, and 2008.
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 $704,000, $1,330,000, and $554,000 for the years ended December 31, 2010, 2009, and 2008, respectively.
Stock-based compensation
The Company accounts for stock-based compensation using the fair value method whereby 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). The Company uses the simplified method in developing an estimate of the expected term of “plain vanilla” stock-based awards. In December 2007, the SEC issued an extension which continues to allow, under certain circumstances, entities to use the simplified method. The Company has continued to use the simplified method to estimate the expected term of its stock-based awards.
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 not, 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 Note 19).
Earnings per share
Basic earnings per share attributable to the Company’s stockholders (“earnings per share”) is computed by dividing net income attributable to the Company’s stockholders by the weighted average number of shares of common stock outstanding for the period. The Company does not have any equity instruments that are dilutive, except for stock-based awards.
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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.
The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:
The number of stock-based awards that could potentially dilute future earnings per share and were not included in the computation of diluted earnings per share because to do so would have been anti-dilutive was 2,676,712, 1,161,870, and 875,648, respectively, for the years ended December 31, 2010, 2009, and 2008.
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, impairment of long-lived assets and assets to be disposed of, revenue recognition of product sales using the percentage completion method, asset retirement obligations, and the provision for income taxes.
New accounting pronouncements
New accounting pronouncements effective in the year ended December 31, 2010
Accounting for Transfers of Financial Assets
In June 2009, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting and disclosure requirements for transfers of financial assets. This amendment requires greater transparency and additional disclosures for transfers of financial assets and the entity’s continuing involvement with them and changes the requirements for derecognizing financial assets. In addition, this amendment eliminates the concept of a qualifying special-purpose entity (“QSPE”). The adoption by the Company of this amendment on January 1, 2010 did not have any effect on the Company’s financial position, results of operations, or liquidity.
Consolidation Guidance for Variable Interest Entities
In June 2009, the FASB issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities (“VIEs”). The elimination of the concept of a QSPE removes the exception from applying the consolidation guidance within this amendment. This amendment requires a company to perform a qualitative analysis when determining whether or not it must consolidate a VIE. The amendment also requires a company to continuously reassess whether it must consolidate a VIE. Additionally, the amendment requires enhanced disclosures about a company’s involvement with VIEs and any significant change in risk
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exposure due to that involvement, as well as how its involvement with VIEs impacts the company’s financial statements. Finally, a company is required to disclose significant judgments and assumptions used to determine whether or not to consolidate a VIE. The Company adopted this amendment on January 1, 2010. The impact of the adoption of this amendment on the Company’s consolidated financial statements is disclosed in Note 6.
Updated Disclosure for Fair Value Measurements
In January 2010, the FASB updated the fair value measurements disclosures. This update will require an entity to disclose separately the amounts of significant transfers in and out of Levels 1 and 2 fair value measurements and to describe the reasons for the transfers. In addition, information about purchases, sales, issuances and settlements are required to be presented separately (i.e., present the activity on a gross basis rather than net) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3 inputs). This update clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value, and requires disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. This update became effective as of the first interim or annual reporting period beginning after December 15, 2009 (January 1, 2010 for the Company), except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 (January 1, 2011 for the Company) and for interim reporting periods within those years. The adoption by the Company of the new guidance on January 1, 2010 did not have a material impact on the Company’s consolidated financial statements (see Note 7).
Scope Exception Related to Embedded Credit Derivatives
In March 2010, the FASB issued an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The guidance is effective on the first day of the first fiscal quarter beginning after June 15, 2010 (July 1, 2010 for the Company). The effect of adopting this accounting standards update on July 1, 2010 is disclosed in Note 7.
New accounting pronouncements effective in future years
Accounting for Revenue Recognition
In October 2009, the FASB issued amendments to the accounting and disclosures for revenue recognition. These amendments, effective for fiscal years beginning on or after June 15, 2010 (January 1, 2011 for the Company) with early adoption permitted, modify the criteria for recognizing revenue in multiple element arrangements and require companies to develop a best estimate of the selling price to separate deliverables and allocate arrangement consideration using the relative selling price method. Additionally, the amendments eliminate the residual method for allocating arrangement considerations. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.
In April 2010, the FASB issued guidance for revenue recognition - milestone method, which provides guidance on the criteria that, should be met for determining whether the milestone method of revenue recognition is appropriate. A vendor can recognize consideration that is contingent upon achievement of a milestone in its entirety as revenue in the period in which the milestone is achieved only if the milestone meets all criteria to be considered substantive. A milestone should be considered substantive in its entirety. An individual milestone may not be bifurcated. The amendments in this update are effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010 (January 1, 2011 for the Company). The adoption of this guidance is not expected to have a material effect on the Company’s consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Accounting for Share-Based Payments
In April 2010, the FASB issued an accounting standards update, which addresses the classification of an employee share-based payment award with an exercise price denominated in the currency of a market in which the underlying equity security trades. This update clarifies that an employee share-based payment award with an exercise price denominated in the currency of a market in which a substantial portion of the entity’s equity securities trades should not be considered to contain a condition that is not a market, performance, or service condition. Therefore, an entity should not classify such an award as a liability if it otherwise qualifies as equity. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2010 (January 1, 2011 for the Company). The adoption of this update is not expected to have a material effect on the Company’s consolidated financial statements.
NOTE 2 - MAMMOTH COMPLEX ACQUISITION
On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth-Pacific, L.P. (“Mammoth Pacific”), which owns the Mammoth complex located near the city of Mammoth, California, for a purchase price of $72.5 million in cash. The Company acquired the remaining interest in Mammoth Pacific to increase its geothermal power plant operations in the United States.
Prior to the acquisition, the Company had a 50% interest in Mammoth Pacific that was accounted for under the equity method of accounting. Following the acquisition, the Company became the sole owner of the Mammoth complex, as well as the sole owner of rights to over 10,000 acres of undeveloped federal lands.
As a result of the acquisition of the remaining 50% interest in Mammoth Pacific, the financial statements of Mammoth Pacific have been consolidated with the Company’s financial statements effective August 2, 2010. The acquisition-date fair value of the previously held 50% equity interest was $64.9 million, which takes into account a “control premium” of $7.6 million. In the year ended December 31, 2010, the Company recognized a pre-tax gain of $36.9 million, which is equal to the difference between the acquisition-date fair value of the previously held 50% equity interest in Mammoth Pacific and the acquisition-date carrying value of such investment. The gain is included in “gain on acquisition of controlling interest” in the consolidated statements of operations and comprehensive income.
The values of the assets acquired and liabilities assumed at the acquisition date are based management’s estimates using the methodology and assumptions described below.
Valuation methodology and assumptions
In estimating the fair value for the assets acquired, the Company primarily relied on the “Income Approach”. After reviewing several geothermal transactions, the Company concluded that those transactions were not sufficiently comparable to the assets acquired in this transaction. The Company also considered the “Cost Approach” as a reasonableness check to compare to the “Income Approach” value, but did not rely on it as a final indicator of the value.
The “Income Approach” is based on the premise that the value of an asset is equal to the present value of the cash flows that the assets are expected to generate. To estimate the fair value of the existing and replacement tangible and intangible assets as well as the development project at the Mammoth Pacific site, a discounted cash flow (“DCF”) analysis was utilized whereby the cash flows expected to be generated by the acquired assets were discounted to their present value equivalent using the rate of return that reflects the relative risk of each asset, as well as the time value of money. This return, known as the weighted average cost of capital (“WACC”), is an overall rate based upon the individual rates of return for invested capital (equity and interest-bearing debt), and was calculated by weighting the acquired return on interest-bearing debt and common equity capital in proportion to their estimated percentage in the expected capital structure. The estimates for the WACC, which ranged from 9.5% to 14.0%, developed in the valuation are for independent power producers and geothermal power producers.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes the fair value of the assets acquired and liabilities assumed at the acquisition date:
The acquired property, plant and equipment will be depreciated over their estimated useful lives.
The revenues of the Mammoth complex and the net loss of the Mammoth complex were $7,567,000 and $645,000, respectively, for the period from August 2, 2010 to December 31, 2010.
The following unaudited consolidated pro forma financial information for the years ended December 31, 2010 and 2009, assumes the Mammoth Pacific acquisition occurred as of January 1, 2009, after giving effect to certain adjustments, including the depreciation based on the adjustments to the fair market value of the property, plant and equipment acquired, and related income tax effects. The pro forma results have been prepared for comparative purposes only and are not necessarily indicative of the results of operations that may occur in the future or that would have occurred had the acquisition of Mammoth Pacific been effected on the dates indicated.
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NOTE 3 - INVENTORIES
Inventories consist of the following:
NOTE 4 - COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS
Cost and estimated earnings on uncompleted contracts consist of the following:
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:
The Mammoth Complex
Prior to August 2, 2010, the Company had a 50% interest in Mammoth Pacific, which owns the Mammoth complex. The Company’s 50% ownership interest in Mammoth Pacific was accounted for under the equity method
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of accounting as the Company had the ability to exercise significant influence, but not control, over Mammoth Pacific. On August 2, 2010, the Company acquired the remaining 50% interest in Mammoth Pacific (see Note 2).
The unaudited condensed financial position and results of operations of Mammoth Pacific are summarized below:
The Sarulla Project
The Company is a 12.75% member of a consortium which is in the process of developing a geothermal power project in Indonesia with expected generating capacity of approximately 340 MW. The project is located in Tapanuli Utara, North Sumatra, Indonesia and will be owned and operated by the consortium members under the framework of a Joint Operating Contract with PT Pertamina Geothermal Energy (“PGE”). The project will be constructed in three phases over five years, with each phase utilizing the Company’s 110 MW to 120 MW 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. The consortium is currently negotiating certain amendments to the energy sales contract, including an adjustment of commercial terms, and intends to proceed with the project after those amendments have become effective. On April 26, 2010, the parties agreed to increase the price of the power sold under the energy sales contract.
The Company’s investment in the Sarulla project was not significant for each of the years presented in these consolidated financial statements.
Watts & More Ltd.
In October 2010, the Company invested $2.0 million in Watts & More Ltd. (“W&M”), an early stage start-up company, engaged in the development of energy harvesting and system balancing solutions for electrical sources and, in particular, solar photovoltaic systems. The Company holds approximately 28.6% of W&M’s shares.
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The Company’s investment in W&M was not significant for the year ended December 31, 2010.
NOTE 6 - VARIABLE INTEREST ENTITIES
Effective January 1, 2010, the Company adopted new accounting and disclosure guidance for variable interest entities (“VIEs”). Among other accounting and disclosure requirements, the new guidance requires the primary beneficiary of a VIE to be identified as the party that both (i) has the power to direct the activities of a VIE that most significantly impact its economic performance; and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE. The adoption of this new accounting guidance did not result in the Company consolidating any additional VIEs or deconsolidating any VIEs.
The Company evaluated all transactions and relationships with VIEs to determine whether the Company is the primary beneficiary of the entities in accordance with the guidance. The Company’s overall methodology for evaluating transactions and relationships under the VIE requirements includes the following two steps: (i) determining whether the entity meets the criteria to qualify as a VIE; and (ii) determining whether the Company is the primary beneficiary of the VIE.
In performing the first step, the significant factors and judgments that the Company considers in making the determination as to whether an entity is a VIE include:
•
The design of the entity, including the nature of its risks and the purpose for which the entity was created, to determine the variability that the entity was designed to create and distribute to its interest holders;
•
The nature of the Company’s involvement with the entity;
•
Whether control of the entity may be achieved through arrangements that do not involve voting equity;
•
Whether there is sufficient equity investment at risk to finance the activities of the entity; and
•
Whether parties other than the equity holders have the obligation to absorb expected losses or the right to receive residual returns.
If the Company identifies a VIE based on the above considerations, it then performs the second step and evaluates whether it is the primary beneficiary of the VIE by considering the following significant factors and judgments:
•
Whether the Company has the power to direct the activities of the VIE that most significantly impact the entity’s economic performance; and
•
Whether the Company has the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.
The Company’s VIEs include certain of its wholly owned subsidiaries that own one or more power plants with long-term PPAs. In most cases, the PPAs require the utility to purchase substantially all of the plant’s electrical output over a significant portion of its estimated useful life. Most of the VIEs have associated project financing debt that is non-recourse to the general creditors of the Company, is collateralized by substantially all of the assets of the VIE and those of its wholly owned subsidiaries (also VIEs) and is fully and unconditionally guaranteed by such subsidiaries. The Company has concluded that such entities are VIEs primarily because the entities do not have sufficient equity at risk and/or subordinated financial support is provided through the long-term PPAs. The Company has evaluated each of its VIEs to determine the primary beneficiary by considering the party that has the power to direct the most significant activities of the entity. Such activities include, among others, construction of the power plant, operations and maintenance, dispatch of electricity, financing and strategy. Except for power plants that it acquired, the Company is responsible for the construction of its power plants and generally provides operation and maintenance services. Primarily due to its involvement in these and other activities, the Company has concluded that it directs the most significant activities at each of its VIEs and, therefore, is considered the primary
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beneficiary. The Company performs an ongoing reassessment of the VIEs to determine the primary beneficiary and may be required to deconsolidate certain of its VIEs in the future. The Company has aggregated its consolidated VIEs into the following categories: (i) wholly owned subsidiaries with project debt; (ii) wholly owned subsidiaries with PPAs; and (iii) less than majority-owned subsidiaries.
Agreement for joint development, construction, ownership and operation of one or more geothermal power plants in Oregon
On October 29, 2010, the Company entered into an agreement to jointly develop, construct, finance, own and operate one or more geothermal power plants in the Crump Geothermal Area located in Lake County, Oregon (the “Crump Project”). Under the terms of the agreement, the other joint owner, Nevada Geothermal Power Inc., contributed all of its rights, titles and interest in the Crump Project, consisting mainly of geothermal rights, to the newly formed entity. The Company paid $0.1 million and will pay an additional $2.4 million over a three-year period to the other joint owner for its ownership interest in the Crump Project and related rights. The Company has a 50% voting interest and will have equal representation with the other joint owner on the governing board. During the development stage of the Crump Project, the Company has the obligation to fund the first $15.0 million on behalf of the Crump Project. All other funding requirements will be required jointly by each owner. If the other joint owner is unable to obtain the necessary capital to fund its share of the Crump Project, the Company will provide financing directly to the joint owner in an aggregate amount of up to $15.0 million. In addition, the Company will be responsible for leading the development of the Crump Project and once operational, will be considered the operator of the facility. At any time during the development or construction of the Crump Project, the Company may terminate its involvement in the Crump Project, whereby the Company would transfer its 50% ownership interest to the other joint owner, at no cost to the other joint owner. If this occur, the Company will have no obligation to make any additional payments to the other joint owner.
The Company concluded that the entity is a VIE primarily because the entity does not have sufficient equity at risk. Through the Company’s equity ownership and other variable interest, the Company determined that it is the primary beneficiary of the Crump Project and therefore will consolidate the assets, liabilities and operations. In making the determination to consolidate, the Company considered the activities that most significantly impact the project’s economic performance, which party has the power to direct those activities, and whether the obligation to absorb the losses or the right to receive the benefits could potentially be significant to the Crump Project. The Company determined that the activities that most significantly impact the economic performance of the Crump Project currently include the development of the project. As the Company is the managing member and is primarily responsible during the development phase and further, since the Company’s obligations and benefits would be significant to the Crump Project, the Company determined that it is the primary beneficiary.
The Company has incurred $3.1 million in development costs of the Crump Project, as of December 31, 2010, which are presented in the Company’s consolidated balance sheet in “construction-in process”. No amounts related to this transaction have been included in the statement of operations and comprehensive income during the year ended December 31, 2010. In addition, the assets related to the Crump Project can only be used to settle the obligations related to the Crump Project.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated in consolidation) for the Company’s VIEs, combined by VIE classifications, that were included in the consolidated balance sheets as of December 31, 2010 and 2009:
NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value measurement guidance clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. It establishes a fair value hierarchy that prioritizes the inputs to
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valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under the fair value measurement guidance are described below:
Level 1 - Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities;
Level 2 - Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability;
Level 3 - Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (supported by little or no market activity).
The following table sets forth certain fair value information at December 31, 2010 and 2009 for financial assets and liabilities measured at fair value by level within the fair value hierarchy, as well as cost or amortized cost. As required by the fair value measurement guidance, assets and liabilities are classified in their entirety based on the lowest level of inputs that is significant to the fair value measurement.
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(1)
Derivatives represent foreign currency forward contracts which are valued primarily based on observable inputs including forward and spot prices for currencies.
(2)
Included in the consolidated balance sheets as follows:
The Company’s financial assets measured at fair value (including restricted cash accounts) at December 31, 2010 and 2009 include investments in auction rate securities and money market funds (which are included in cash equivalents). Those securities, except for the illiquid auction rate securities, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.
The Company’s auction rate securities are valued using Level 3 inputs. As of December 31, 2010 and 2009, all of the Company’s auction rate securities are associated with failed auctions. Such securities have par values totaling $4.5 million at December 31, 2010 and 2009, all of which have been in a loss position since the fourth quarter of 2007. 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. Due to the lack of observable market quotes on the Company’s illiquid auction rate securities, the Company utilizes valuation models that rely exclusively on Level 3 inputs including, among other things: (i) the underlying structure of each security; (ii) the present value of future principal and interest payments discounted at rates considered to reflect the uncertainty of current market conditions; (iii) consideration of the probabilities of default, auction failure, or repurchase at par for each period; (iv) assessments of counterparty credit quality; (v) estimates of the recovery rates
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in the event of default for each security; and (vi) overall capital market liquidity. These estimated fair values are subject to uncertainties that are difficult to predict. Therefore, such auction rate securities have been classified as Level 3 in the fair value hierarchy.
The table below sets forth a summary of the changes in the fair value of the Company’s financial assets classified as Level 3 (i.e., illiquid auction rate securities) for the year ended December 31, 2010, 2009 and 2008:
Effective April 1, 2009, the Company adopted the recognition and presentation of the other-than-temporary impairments standard, which requires an entity to separate an other-than-temporary impairment of a debt security into two components when there are credit-related losses associated with the impaired security for which management does not have the intent to sell the security and it is not more likely than not, that it will be required to sell the security before recovery of its cost basis. For those securities, the amount of the other-than-temporary impairment related to a credit loss is recognized in earnings and reflected as a reduction in the cost basis of the security, and the amount of the other-than-temporary impairment related to other factors is recorded in other comprehensive loss with no change to the cost basis of the security. For securities for which there is an intent to sell before recovery of the cost basis, the full amount of the other-than-temporary impairment is recognized in earnings and reflected as a reduction in the cost basis of the security. Upon adoption of this standard, the Company reclassified $1,205,000 (net of taxes of $650,000) to other comprehensive income with an offset to retained earnings related to the other-than-temporary impairment charges previously recognized in earnings. This cumulative effect adjustment related to auction rate securities for which the Company did not have the intent to sell and would not, more likely than not, be required to sell prior to recovery of its cost basis.
Effective July 1, 2010, the Company adopted an accounting standards update that amends and clarifies the guidance on how entities should evaluate credit derivatives embedded in beneficial interests in securitized financial assets. The updated guidance eliminates the scope exception for bifurcation of embedded credit derivatives in interests in securitized financial assets unless they are created solely by subordination of one beneficial interest to another. The auction rate securities held by the Company are considered securitized financial assets and therefore fall under the guideline in the abovementioned accounting standards update. The Company elected the fair value option for its auction rate securities as permitted by the update. Upon adoption of this accounting standards update, the Company reclassified $693,000 (net of income taxes of $377,000) to retained earnings with an offset to other comprehensive income. Effective with the adoption of this new guidance, all changes in the fair value of auction rate securities are recognized in earnings.
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 reach
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maturity. As a result, the Company has classified those securities with failed auctions as long-term assets in the consolidated balance sheets as of December 31, 2010 and 2009.
The Company continues to monitor the market for auction rate securities and to consider the market’s impact (if any) on the fair market value of the Company’s investments. If current market conditions deteriorate further, the Company may be required to record additional impairment charges in 2011.
There were no transfers of assets or liabilities between Level 1 and Level 2 during the year ended December 31, 2010.
The fair value of the Company’s long-term debt approximates its carrying amount, except for the following:
The fair value of OFC Senior Secured Notes is determined using observable market prices as these securities are traded. The fair value of other long-term debt is determined by a valuation model which is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves.
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NOTE 8 - PROPERTY, PLANT AND EQUIPMENT AND CONSTRUCTION-IN-PROCESS
Property, plant and equipment
Property, plant and equipment, net, consist of the following:
Depreciation expense for the years ended December 31, 2010, 2009, and 2008 amounted to $80,669,000, $60,811,000, and $51,873,000, respectively. Depreciation expense for the years ended December 31, 2010 is net at $1,382,000 impact of a cash grant received in August 2010 (see Note 1).
U.S. Operations
The net book value of the property, plant and equipment, including construction-in-process, located in the United States was approximately $,1,485,527,000 and $1,287,836,000 as of December 31, 2010 and 2009, respectively. This amount as of December 31, 2010 is net of a cash grant in the amount of $106,900,000 received on August 27, 2010 (net of accumulated depreciation of $1,382,000).
The North Brawley power plant (North Brawley) which is under development was tested for impairment in the current year due to the low output and higher than expected operating costs. Based on these indicators, the Company tested North Brawley for recoverability by estimating its future cash flows taking into consideration the various outcomes from different generating capacities, rates to be received under the PPA through the end of its term and expected market rates thereafter, possible penalties for underperformance during periods when the plant is expected to operate below the stated capacity in the PPA, projected capital expenditures to complete development of the plant and projected operating expenses over the life of the plant. The Company applied a probability-weighted approach and considered alternative courses of action.
Using a probability-weighted approach, the estimated undiscounted cash flows exceed the carrying value of the plant ($245 million as of December 31, 2010) by approximately $46 million and therefore, no impairment occurred. Estimated undiscounted cash flows are subject to significant uncertainties. If actual cash flows differ from the Company’s current estimates due to factors that include, among others, if the plant’s generating capacity is less than approximately 45 MW, or if the capital expenditures required to complete development of the plant and/or future operating costs exceed the level of our current projections, a material impairment write-down may be required in the future.
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Foreign Operations
The net book value of property, plant and equipment, including construction-in-process, located outside of the United States was approximately $210,574,000 and $229,452,000 as of December 31, 2010 and 2009, respectively.
The Company, through its wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”) owns and operates geothermal power plants in Kenya. The net book value of assets associated to the power plants was $111,112,000 and $110,810,000 as of December 31, 2010 and 2009, respectively. The Company sells the electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a 20-year PPA.
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 $10,509,000 and $14,216,000 at December 31, 2010 and 2009, respectively.
The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“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 $27,836,000 and $30,776,000 at December 31, 2010 and 2009, respectively.
The Company, through its wholly owned subsidiary, Ortitlan, Limitada (“Ortitlan”), owns a power plant in Guatemala. The net book value of the assets related to the power plant was $46,995,000 and $48,623,000 at December 31, 2010 and 2009, respectively.
The Company, through its wholly owned subsidiary, Geothermal Development Limited (“GDL”), owned a power plant in New Zealand. The net book value of the assets related to the power plant was $11,940,000 at December 31, 2009. The former shareholder of GDL exercised its call option to purchase from the Company its shares in GDL in January 2010 (see Note 17).
Construction-in-process
Construction-in-process consists of the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables present a rollforward of the construction-in-process for the years ended December 31, 2010, 2009, and 2008:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 9 - INTANGIBLE ASSETS
Intangible assets consist mainly of the Company’s PPAs acquired in business combinations and amounted to $40,274,000 and $41,981,000, net of accumulated amortization of $22,086,000 and $18,907,000, as of December 31, 2010 and 2009, respectively. Amortization expense for the years ended December 31, 2010, 2009, and 2008 amounted to $3,179,000, $3,197,000, and $3,136,000, respectively.
Estimated future amortization expense for the intangible assets as of December 31, 2010 is as follows:
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NOTE 10 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consist of the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 11 - LONG-TERM DEBT AND CREDIT AGREEMENTS
Long-term debt consists of notes payable under the following agreements:
Senior Loan (the Zunil Power Plant)
Orzunil, a wholly owned subsidiary of the Company, has a senior loan agreement with International Finance Corporation (“IFC”). 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%.
There are various restrictive covenants under this senior loan, which include limitations on Orzunil’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, Orzunil was in compliance with the covenants under this senior loan.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Loan Agreement (the Olkaria III Complex)
In March 2009, the Company’s wholly owned subsidiary, OrPower 4, Inc. (“OrPower 4”), entered into a project financing loan of $105.0 million to refinance its investment in the 48 MW Olkaria III complex located in Kenya (the “Olkaria Loan”). The Company initially financed the construction of Phase I and Phase II of the project, as well as the drilling of wells with corporate funds. The Olkaria Loan is provided by a group of European Development Finance Institutions (“DFIs”) arranged by DEG - Deutsche Investitions - und Entwicklungsgesellschaft mbH (“DEG”). The first disbursement of $90.0 million occurred on March 23, 2009 and the second disbursement of $15.0 million occurred on July 10, 2009. The Olkaria Loan will mature on December 15, 2018, and is payable in 19 equal semi-annual installments, commencing December 15, 2009. Interest on the Olkaria Loan is variable based on 6-month LIBOR plus 4.0% and the Company had the option to fix the interest rate upon each disbursement. Upon the first disbursement, the Company fixed the interest rate on $77.0 million of the Olkaria Loan at 6.9% per annum.
There are various restrictive covenants under the Olkaria Loan, which include limitations on OrPower 4’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, OrPower 4 was in compliance with the covenants under the Olkaria Loan.
Debt service reserve
As required under the terms of the Olkaria Loan, OrPower 4 maintains an account 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 Olkaria Loan in the following six months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2010, the balance of such account was $10.5 million. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts were funded by a letter of credit in the amount of $5.9 million for both years.
Loan Agreement (the Amatitlan Power Plant)
In May 2009, the Company’s wholly owned subsidiary, Ortitlan, entered into a note purchase agreement, in an aggregate principal amount of $42.0 million, to refinance its investment in the 20 MW Amatitlan geothermal power plant located in Amatitlan, Guatemala (the “Amatitlan Loan”). The Company initially financed the construction of the project, as well as the drilling of wells with corporate funds. The Amatitlan Loan is provided by TCW Global Project Fund II, Ltd. (“TCW”). The Amatitlan Loan will mature on June 15, 2016, and will be payable in 28 quarterly installments. The Amatitlan Loan bears annual interest at a rate of 9.83%.
There are various restrictive covenants under the Amatitlan Loan, which include limitations on Ortitlan’s ability to make distributions to its shareholders. Management believes that as of December 31, 2010, Ortitlan was in compliance with the covenants under the Amatitlan Loan.
Debt service reserve
As required under the terms of the Amatitlan Loan, Ortitlan maintains an account 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 Amatitlan Loan in the following three months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $2.0 million and $4.5 million, respectively.
Credit Facility Agreement (the Momotombo Power Plant)
Ormat Momotombo Power Company, a wholly owned subsidiary of the Company, entered into a credit facility agreement with Bank Hapoalim B.M. The loans under the credit facility agreement were fully repaid during the year ended December 31, 2010.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
OFC Senior Secured Notes
On February 13, 2004, Ormat Funding Corp. (“OFC”), a wholly owned subsidiary, issued $190.0 million, 81/4% 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 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. Management believes that as of December 31, 2010, 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 in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $1.4 million and $0.1 million, respectively. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts was funded by a letter of credit in the amount of approximately $11.1 million (see Note 23).
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 $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, 2010, 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.
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Debt service reserve
As required under the terms of the OrCal Senior Secured Notes, OrCal 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 OrCal Senior Secured Notes in the following six months. This restricted cash account is classified as current in the consolidated balance sheet. As of December 31, 2010 and 2009, the balance of such account was $0.3 million and $2.6 million, respectively. In addition, as of December 31, 2010 and 2009, part of the restricted cash accounts was funded by a letter of credit in the amount of $10.8 million and $11.3 million, respectively. (see Note 23).
Senior Unsecured Bonds
On August 3, 2010, the Company entered into a trust instrument governing the issuance of, and accepted subscriptions for, an aggregate principal amount of approximately $142.0 million of senior unsecured bonds (the “Bonds”). The Company issued the Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended.
Subject to early redemption, the principal of the Bonds is repayable in a single bullet payment upon the final maturity of the Bonds on August 1, 2017. The Bonds bear interest at a fixed rate of 7% per annum, payable semi-annually.
In February 2011, the Company accepted subscription for, an aggregate principal amount of approximately $108.0 million of additional senior unsecured bonds (the “Additional Bonds”) under two addendums to the trust instrument. The Company issued the Additional Bonds outside the United States to investors who are not “U.S. persons” in an unregistered offering pursuant to, and subject to the requirements of, Regulation S under the Securities Act of 1933, as amended. The terms and conditions of the Additional Bonds are identical to the original Bonds. The Additional Bonds were issued at a premium which reflects an effective fixed interest of 6.75% per annum.
Loans from institutional investors
In July 2009, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “First Loan”). The First Loan matures on July 16, 2015, is payable in 12 semi-annual installments commencing January 16, 2010, and bears annual interest of 6.5%.
In July 2009, the Company entered into an 8-year loan agreement of $20.0 million with another group of institutional investors (the “Second Loan”). The Second Loan matures on August 1, 2017, is payable in 12 semi-annual installments commencing February 1, 2012, and bears interest at 6-month LIBOR plus 5.0%.
In November 2010, the Company entered into a 6-year loan agreement of $20.0 million with a group of institutional investors (the “Third Loan”). The Third Loan matures on November 16, 2016, is payable in ten semi-annual installments commencing May 16, 2012, and bears annual interest of 5.75%.
Loan from a commercial bank
On November 4, 2009, the Company entered into a 5-year loan agreement of $50.0 million with a commercial bank. The bank loan matures on November 10, 2014 and is payable in 10 semi-annual installments commencing May 10, 2010, and bears interest at 6-month LIBOR plus 3.25%.
Revolving credit lines with commercial banks
As of December 31, 2010, the Company has credit agreements with five commercial banks for an aggregate amount of $365.0 million. Under the terms of these credit agreements, the Company, or its Israeli subsidiary, Ormat
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Systems, can request: (i) extensions of credit in the form of loans and/or the issuance of one or more letters of credit in the amount of up to $315.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $50.0 million. The credit agreements mature between May 2011 and September 2013. 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.
As of December 31, 2010, loans in the total amount of $189.5 million were outstanding, and letters of credit with an aggregate stated amount of $29.5 million were issued and outstanding under such credit agreements. The $189.5 million in loans are for terms of three months or less, The Company intends to replace them with new draw-downs from the same or other lines of credit and with the proceeds from the issuance of the Additional Bonds in February 2011 (see above), therefore such amounts are classified as long-term debt. The loans bear interest at an annual weighted average rate of 2.03% as of December 31, 2010.
Restrictive covenants
Under the credit agreements, the loan agreements, and the trust instrument governing the Bonds, described above, are unsecured, but the Company is subject to a negative pledge in favor of the banks and the other lenders and certain other restrictive covenants. These include, among other things, 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 their assets, or a change of control in the Company’s ownership structure. Some of the credit agreements, the loan agreements, and the trust instrument contain cross-default provisions with respect to other material indebtedness owed by us to any third party. In some cases, the Company agreed to maintain certain financial ratios such as a debt to equity ratio, and a debt to adjusted EBITDA ratio. There are also certain restrictions on distribution of dividends. 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. Management believes that as of December 31, 2010, the Company was in compliance with the covenants under the credit agreements, the loan agreements and the trust instrument.
Credit agreement with Union Bank
On February 15, 2006, a subsidiary of the Company entered into a $25.0 million credit agreement with Union Bank, N.A. (“Union Bank”). In December 2008, the subsidiary entered into an amendment to the credit agreement. Under the amendment, the credit termination date was extended to February 15, 2012 and the aggregate amount available under the credit agreement was increased to $37.5 million. Under the credit agreement, as amended, the Company can request extensions of credit in the form of loans and/or the issuance of one or more letters of credit. Union Bank is currently the sole lender and issuing bank under the credit agreement, but is also designated as an administrative agent on behalf of banks that may, from time to time in the future, join the credit agreement as parties thereto. In connection with this transaction, the Company has entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee the subsidiary’s obligations under the credit agreement. The subsidiary’s obligations under the credit agreement are otherwise unsecured by any of its (or any of its subsidiaries’) assets. There are various restrictive covenants under the credit agreement, which include maintaining certain levels of tangible net worth, leverage ratio, minimum coverage ratio, and a distribution coverage ratio. In addition, there are restrictions on dividend distributions in the event of a payment default or noncompliance with such ratios. Management believes that as of December 31, 2010, the Company was in compliance with the covenants under the credit agreement. As of December 31, 2010, thirteen letters of credit with an aggregated stated amount of $34.4 million were issued and outstanding under the credit agreement.
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Future minimum payments
Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of December 31, 2010 are as follows:
NOTE 12 - PUNA POWER PLANT LEASE TRANSACTIONS
In 2005, the Company’s wholly owned subsidiary in Hawaii, Puna Geothermal Ventures (“PGV”), entered into transactions involving the Puna geothermal power plant located on the Big Island of Hawaii (the “Puna Power Plant”).
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, 2010 and 2009 amounted to $45.1 million and $47.8 million, net of accumulated depreciation of $17.3 million and $14.6 million, respectively. The unrelated company (the “Lessor”) simultaneously leased back the Puna Power Plant 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 Power Plant 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 the accounting standards 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 $4.2 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, 2010, are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Depository accounts
As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $8.1 million and $11.7 million as of December 31, 2010 and 2009, respectively, and were included in restricted cash accounts in the consolidated balance sheets. As of December 31, 2010 and 2009, $1.7 million and $2.5 million, respectively, 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 7, and the remaining $6.4 million and $9.2 million, respectively, were classified as current as they are 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 the Company’s wholly owned subsidiary, Ormat Nevada Inc. (“Ormat Nevada”). 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, 2010 and 2009, the balance of such account was $0 and $0.7 million respectively. This amount can be distributed to Ormat Nevada currently and has been classified as current restricted assets.
NOTE 13 - OPC TRANSACTION
In June 2007, Ormat Nevada entered into agreements with affiliates of Morgan Stanley & Co. Incorporated and Lehman Brothers Inc. ( Morgan Stanley Geothermal LLC and Lehman-OPC LLC), under which those investors purchased, for cash, interests in a newly formed subsidiary of Ormat Nevada, OPC LLC (“OPC”), entitling the investors to certain tax benefits (such as production tax credits and accelerated depreciation) and distributable cash associated with four geothermal power plants.
The first closing under the agreements occurred in 2007 and covered the Company’s Desert Peak 2, Steamboat Hills, and Galena 2 power plants. The investors paid $71.8 million at the first closing. The second closing under the agreements occurred in 2008 and covered the Galena 3 power plant. The investors paid $63.0 million at the second closing.
Ormat Nevada continues to operate and maintain the power plants. Under the agreements, Ormat Nevada initially received all of the distributable cash flow generated by the power plants until it recovered the capital that it has invested in the power plants, which occurred in the fourth quarter of 2010, while the investors receive substantially all of the production tax credits and the taxable income or loss (together, the “Economic Benefits”), and receive the distributable cash flow after Ormat Nevada recovered its capital. The 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, 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 power plants.
The Class B membership units are provided with a 5% residual economic interest in OPC. The 5% residual interest commences on achievement by the investors of a contractually stipulated return that triggers the Flip Date. The actual Flip Date is not known with certainty and is determined by the operating results of OPC. This residual 5% interest represents a noncontrolling interest and is not subject to mandatory redemption or guaranteed payments. Cash is distributed each period in accordance with the cash allocation percentages stipulated in the agreements. Until the fourth quarter of 2010, Ormat Nevada was allocated the cash earnings in OPC and therefore, the amount allocated to the 5% residual interest represented the noncash loss of OPC which principally represented depreciation on the property, plant and equipment. As from the fourth quarter of 2010, the distributable cash is allocated
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
to the Class B membership units. As a result of the acquisition by Ormat Nevada, on October 30, 2009, of all of the Class B membership units of OPC held by Lehman-OPC LLC (see below), the residual interest decreased to 3.5%. Such residual interest increased to 5% on February 3, 2011 when Ormat Nevada sold it Class B membership units to JPM Capital Corporation (“JPM”) (see below).
The Company’s voting rights in OPC are based on a capital structure that is comprised of Class A and Class B membership units. The Company owned, through its subsidiary, Ormat Nevada, all of the Class A membership units, which represent 75% of the voting rights in OPC, and 30% of the Class B membership units, which represent 7.5% of the voting rights of OPC from October 30, 2009 to February 3, 2011. In total the Company had 82.5% of the voting rights in OPC as of December 31, 2010. The investors owned 70% of the Class B membership units, which represented 17.5% of the voting rights of OPC, as of December 31, 2010. Other than in respect of customary protective rights, all operational decisions in OPC are decided by the vote of a majority of the membership units. Following the Flip Date, Ormat Nevada’s voting rights will increase to 95% and the investor’s voting rights will decrease to 5%. Ormat Nevada retains the controlling voting interest in OPC both before and after the Flip Date and therefore has continued to consolidate OPC.
On October 30, 2009, Ormat Nevada acquired from Lehman-OPC all of the Class B membership units of OPC held by Lehman-OPC LLC pursuant to a right of first offer for a price of $18.5 million. A substantial portion of the initial sale of the Class B membership units by Ormat Nevada was accounted for as a financing. As a result, the repurchase of these interests at a discount resulted in a pre-tax gain of $13.3 million in the year ended December 31, 2009. In addition, an amount of approximately $1.1 million has been reclassified from noncontrolling interest to additional paid-in capital representing the 1.5% residual interest of Lehman-OPC LLC’s Class B membership units. As a result of that transaction, Lehman-OPC LLC has no further interest in OPC.
On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for a sale price of $24.9 million in cash. The Company will not record any gain from the sale of its Class B membership interests in OPC to JPM.
NOTE 14 - 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 the year ended December 31, 2010, the Company increased the aggregate carrying amount of its asset retirement obligation by $527,000 due to increased costs associated with demolition and abandonment of property, plant and equipment. During the year ended December 31, 2009, the Company decreased the aggregate carrying amount of its asset retirement obligation by $686,000 due to decreased costs associated with demolition and abandonment of property, plant and equipment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 15 - STOCK-BASED COMPENSATION
The Company makes an estimate of expected forfeitures and recognizes compensation costs only for those stock-based awards expected to vest. As of December 31, 2010, the total future compensation cost related to unvested stock-based awards that are expected to vest is $9,657,000, which amount will be recognized over a weighted average period of 1.3 years.
During the years ended December 31, 2010, 2009 and 2008, the Company recorded compensation related to stock-based awards as follows:
During the fourth quarter of 2010, the Company evaluated the trends in the stock-based award forfeiture rate and came to the conclusion that the actual rate is 5.7%. This change resulted in an increase in the stock-based award expenses of approximately $1.0 million.
Valuation assumptions
The fair value of each grant of stock-based awards 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 giving consideration to the contractual term and vesting schedule. Since the Company does not have any traded stock-based award 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 0.72% yearly weighted average dividend rate in the year ended December 31, 2010. The risk-free interest rate was based on the yield from U.S. constant treasury maturities bonds with an equivalent term. The forfeiture rate is based on trends in actual stock-based awards forfeitures.
The Company calculated the fair value of each stock-based award on the date of grant based on the following assumptions:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock-based awards
The 2004 Incentive Compensation Plan
In 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 (“SARs”), 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 and SARs 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 or SARs from the Company’s authorized share capital.
The following table summarizes the status of the 2004 Incentive Plan as of and for the years presented below (shares in thousands):
*
Upon exercise, SARs entitle the recipient to receive shares of common stock equal to the increase in value of the award between the grant date and the exercise date.
As of December 31, 2010, 1,239,699 shares of the Company’s common stock are available for future grants.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes information about stock-based awards outstanding at December 31, 2010 (shares in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes information about stock-based awards outstanding at December 31, 2009 (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 $29.58 and $37.84 as of December 31, 2010 and 2009, respectively, which would have potentially been received by the stock-based award holders had all stock-based award holders exercised their stock-based award as of those dates. The total number of in-the-money stock-based award exercisable as of December 31, 2010 and 2009 was 64,301 and 183,396, respectively.
The total pretax intrinsic value of stock-based award exercised during the years ended December 31, 2009 and 2008 was $1,835,000 and $597,000, respectively, based on the Company’s average stock price of $35.98 and $42.01 during the years ended December 31, 2009 and 2008, respectively. No options were exercised during the year ended December 31, 2010.
The Parent’s Stock Option Plans
The Parent had four stock option plans. Under the Parent’s stock option 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. None of the options were exercisable or convertible into shares of the Company.
As of December 31, 2010 and 2009, all the options under the parent stock options plans have been fully exercised or expired, and no shares of the Parent’s ordinary shares are available for future grants.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes the status of the Parent’s Plans as of and for the periods presented below (shares in thousands):
The total pretax intrinsic value of options exercised during the years ended December 31, 2009 and 2008 was $1,163,000 and $1,130,985 based on the Parent’s average stock price of $7.88 and $13.19 during the year ended December 31, 2009 and 2008, respectively. No options were exercised during the year ended December 31, 2010.
NOTE 16 - 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 2034. Generally, capacity payments are calculated based on the amount of time that the power plants are available to generate electricity. The energy payments are 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 avoids 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 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 power plant may be permanently reduced.
As discussed in 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
lease accounting. Future minimum lease revenues under PPAs which contain a lease element as of December 31, 2010 were as follows:
NOTE 17 - DISCONTINUED OPERATIONS
In January 2010, a former shareholder of Geothermal Development Limited (“GDL”) who is the owner of an 8 MW power plant in New Zealand exercised a call option to purchase from the Company its shares in GDL for approximately $2.8 million. In addition, the Company received $17.7 million to repay the loan a subsidiary of the Company provided to GDL to build the plant. The Company did not exercise its right of first refusal and, therefore, the Company transferred its shares in GDL to the former shareholder after the former shareholder paid all of GDL’s obligations to the Company. As a result, the Company recorded a pre-tax gain of approximately $6.3 million in the year ended December 31, 2010 ($4.3 million after-tax).
The net assets of GDL on January 1, 2010 were as follows:
The operations and gain on sale of GDL have been included in discontinued operations in the consolidated statements of operations and comprehensive income for all periods prior to the sale of GDL in January 2010. Electricity revenues related to GDL were $3.2 million and $0.9 million in the years ended December 31, 2009 and 2008, respectively none in the year ended December 31, 2010). Basic and diluted earnings per share related to the $4.3 million after-tax gain on sale of GDL was $0.10 in the year ended December 31, 2010. Basic and diluted earnings (loss) per share related to income (loss) from discontinued operations was $0.08 and $(0.05) in the years ended December 31, 2009 and 2008, respectively (none in the year ended December 31, 2010).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 18 - INTEREST EXPENSE, NET
The components of interest expense are as follows:
NOTE 19 - INCOME TAXES
Income before provision for income taxes and equity in income of investees consisted of:
The components of income tax expense (income) are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The significant components of the deferred income tax expense (benefit) are as follows:
The difference between the U.S. federal statutory tax rate and the Company’s effective tax rate are as follows:
The net deferred tax assets and liabilities consist of the following:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 assets at December 31, 2010, net of an immaterial valuation allowance related to state income taxes of $0.4 million, will be realized.
At December 31, 2010, the Company had U.S. federal NOL carryforwards of approximately $255.8 million and state NOL carryforwards of approximately $105.5 million, net of valuation allowance of $0.6 million, available to reduce future taxable income, which expire between 2021 and 2031 for federal NOLs and between 2015 and 2031 for state NOLs. The investment tax credits in the amount of $2.0 million at December 31, 2010 are available for a 20-year period and expire in 2022 and 2024. The production tax credits in the amount of $48.3 million at December 31, 2010 are available for a 20-year period and expire between 2026 and 2031.
The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $196.5 million at December 31, 2010. 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.
Uncertain tax positions
The liability for unrecognized tax benefits of $5.4 million and $4.9 million at December 31, 2010 and 2009, respectively, 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, 2010, 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 2000-2010 and by local state jurisdictions for the years 2002-2010.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Tax benefits in the U.S.
The U.S. government encourages production of electricity from geothermal resources through certain tax subsidies under the recently enacted the ARRA. The Company is permitted to claim 30% of the cost of each new geothermal power plant in the United States as an investment tax credit against its federal income taxes. Alternatively, the Company is permitted to claim a production tax credit, which in 2010 was 2.2 cents per kWh and which is adjusted annually for inflation. The production tax credit may be claimed for ten years on the electricity output of new geothermal power plants put into service by December 31, 2013. The owner of the power plant must choose between the production tax credit and the 30% 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 the Company claims the production tax credit or the investment tax credit, it is 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 the Company claims the investment tax credit, the Company’s “tax base” in the plant that it can recover through depreciation must be reduced by half of the tax credit. If the Company claims the production tax credit, there is no reduction in the tax basis for depreciation. Companies that place qualifying renewable energy facilities in service, during 2009, 2010 or 2011, or that begin construction of qualifying renewable energy facilities during 2009, 2010 or 2011 and place them in service by December 31, 2013, may choose to apply for a cash grant from the U.S. Treasury in an amount equal to the investment tax credit. Under the ARRA, the U.S. Treasury is instructed to pay the cash grant within 60 days of the application or the date on which the qualifying facility is placed in service.
On June 7, 2007 and April 17, 2008, a wholly-owned subsidiary, Ormat Nevada, concluded transactions to monetize production tax credits and other favorable tax attributes (see Note 13).
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 power plant from income tax payable, which reduces the effective tax rate to zero. Ortitlan, another wholly owned subsidiary, was granted a tax exemption for a period of ten years ending August 2017. The effect of the tax exemption in the years ended December 31, 2010, 2009, and 2008 is $3.2 million, $3.8 million, and $3.9 million, respectively ($0.07, $0.08, and $0.09 per share of common stock, respectively).
Israel - The Company’s operations in Israel through its wholly owned Israeli subsidiary, Ormat Systems Ltd. (“Ormat Systems”), are taxed at the regular corporate tax rate of 27% in 2008, 26% in 2009, 25% in 2010, 24% in
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2011, 23% in 2012, 22% in 2013, 21% in 2014, 20% in 2015, and 18% in 2016 and thereafter. Ormat Systems 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, Ormat Systems was exempt from Israeli income taxes with respect to income derived from the first benefited investment for a period of two years that started in 2004, and thereafter such income is subject to reduced Israeli income tax rates which will not exceed 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 a period of two years that started in 2007, and thereafter such income will be subject to reduced Israeli income tax rates which will not exceed 25% for an additional five years. These benefits are subject to certain conditions, including among other things, that all transactions between Ormat Systems and its affiliates are at arm’s 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 Israel Tax Authority in order to maintain the tax benefits. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax would apply to all qualified income of certain industrial companies, as opposed to the current law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. According to the amendment, the uniform tax rate applicable to the zone where the production facilities of Ormat Systems are located would be 15% in 2011 and 2012, 12.5% in 2013 and 2014, and 12% in 2015 and thereafter. Under the transitory provisions of the new legislation, Ormat Systems may opt whether to irrevocably implement the new law while waiving benefits provided under the current law or keep implementing the current law during the next years. Changing from the current law to the new law is permissible at any stage.
Other significant foreign countries - The Company’s operations in Nicaragua, Kenya, and New Zealand are taxed at the rates of 25%, 37.5%, and 33%, respectively.
NOTE 20 - BUSINESS SEGMENTS
The Company has two reporting segments: Electricity and Product 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 from the Company’s power plants pursuant to PPAs. The Product 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Summarized financial information concerning the Company’s reportable segments is shown in the following tables:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table presents revenues from major customers:
(1)
Revenues reported in Electricity Segment.
(2)
Subsidiaries of NV Energy, Inc.
(3)
Revenues reported in Products Segment.
NOTE 21 - TRANSACTIONS WITH RELATED ENTITIES
Transactions between the Company and related entities, other than those disclosed elsewhere in these financial statements, are summarized below:
The current liability due from Parent at December 31, 2010 and 2009 of $272,000 and $422,000, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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%). The principal and interest on the Parent Loan Agreement was payable in varying amounts through the loan due date of June 2010. The outstanding balance of such loan at December 31, 2009 was $9,600,000 (which represented the then-current portion). The loan was fully repaid in the year ended December 31, 2010.
Corporate and administrative services agreement with the Parent
Ormat Systems and the Parent have agreements whereby Ormat Systems will provide to the Parent, for a monthly fee of $10,000 (adjusted annually, in part based on changes in the Israeli Consumer Price Index), certain corporate administrative services, including the services of executive officers. In addition, Ormat Systems agreed to provide the Parent with services of certain skilled engineers and other research and development employees at Ormat Systems’ cost plus 10%.
Lease agreements with the Parent
Ormat Systems has a rental agreement with the Parent entered into in July 2004 for the sublease 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 term of the rental agreement is for a period ending the earlier of: (i) 25 years from July 1, 2004; or (ii) the remaining periods of the underlying lease agreements between the Parent and the Israel Land Administration (which terminate between 2018 and 2047).
Effective April 1, 2009, Ormat Systems entered into an additional rental agreement with the Parent for the sublease of additional manufacturing facilities adjacent to the current manufacturing facilities in Yavne, Israel. The term of the additional rent agreement will expire on the same day as the abovementioned lease agreement entered into in July 2004. Pursuant to the additional lease agreement, Ormat Systems pays a monthly rent of $77,000, adjusted annually for changes in the Israeli Consumer Price Index, plus tax and other costs to maintain the properties.
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 22 - 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
employee’s annual salary. The Company’s contributions to the Plan were $451,000, $364,000, and $301,000 for the years ended December 31, 2010, 2009, and 2008, respectively.
Severance plan
The Company, through Ormat Systems, 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 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 in 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 $18,562,000 and $16,274,000 at December 31, 2010 and 2009, respectively, and have been presented in 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, 2010, 2009, and 2008 were $1,676,000, $1,148,000, and $2,843,000, respectively, which are net of income amounting to $1,889,000, $1,613,000, and $324,000, respectively, generated from the regular deposits and amounts accrued in severance funds
The Company expects the severance pay contributions in 2011 to be approximately $1.8 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 23 - COMMITMENTS AND CONTINGENCIES
Geothermal resources
The Company, through its project subsidiaries in the United States, controls certain rights to geothermal fluids through certain leases with the Bureau of Land Management (“BLM”) or through private leases. Royalties on the utilization of the geothermal resources are computed and paid to the lessors as defined in the respective agreements. Royalty expense under the geothermal resource agreements were $8,690,000, $6,611,000, and $10,737,000 for the years ended December 31, 2010, 2009, and 2008, respectively.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $67.0 million and $53.4 million at December 31, 2010 and 2009, 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.
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, 2010, total obligations related to such supplier agreements were approximately $56.6 million (out of which approximately $36.8 million relate to construction-in-process). All such obligations are payable in 2011.
Grants and royalties
The Company, through Ormat Systems, had historically, through December 31, 2003, requested and received grants for research and development from the Office of the Chief Scientist of the Israeli Government. Ormat Systems 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. No royalties were paid for the years ended December 31, 2010, 2009, and 2008. The Company is not liable for royalties if the Company does not sell such products and services. Such royalties are capped at the amount of the grants received plus interest at LIBOR. The cap at December 31, 2010 and 2009, amounted to $1,343,000 and $1,284,000, respectively, of which approximately $402,000 and $343,000 of the cap, respectively, increases based on the LIBOR rate, as defined above.
Contingencies
Securities Class Actions
Following the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs, three securities class action lawsuits were filed in the United States District Court for the District of Nevada on March 9, 2010, March 18, 2010 and April 7, 2010. These complaints assert claims against the Company and certain officers and directors for alleged violation of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). One complaint also asserts claims for alleged violations of Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 (the “Securities Act”). All three complaints allege claims on behalf of a putative class of purchasers of Company stock between May 6, 2008 or May 7, 2008 and February 23, 2010 or February 24, 2010.
These three lawsuits were consolidated by the Court in an order issued on June 3, 2010 and the Court appointed three of the Company’s stockholders to serve as lead plaintiffs. Lead plaintiffs filed a consolidated amended class action complaint (“CAC”) on July 9, 2010 that asserts claims under Sections 10(b) and 20(a) of the Exchange Act on behalf of a putative class of purchasers of Company stock between May 7, 2008 and February 24, 2010. The CAC alleges that certain of the Company’s public statements were false and misleading for failing to account properly for the Company’s exploration and development costs based on the Company’s announcement on February 24, 2010 that it was going to restate its financial results to change its method of accounting for exploration and development costs in certain respects. The CAC also alleges that certain of the Company’s statements concerning the North
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Brawley project were false and misleading. The CAC seeks compensatory damages, expenses, and such further relief as the Court may deem proper. The Company cannot make an estimate of the possible loss or range of loss.
Defendants filed a motion to dismiss the CAC on August 13, 2010 which remains pending.
The Company does not believe that these lawsuits have merit and is defending the actions vigorously.
Stockholder Derivative Cases
Four stockholder derivative lawsuits have also been filed in connection with the Company’s public announcement that it would restate certain of its financial results due to a change in the Company’s accounting treatment for certain exploration and development costs. Two cases were filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe on March 16, 2010 and April 21, 2010 and two in the United States District Court for the District of Nevada on March 29, 2010 and June 7, 2010. All four lawsuits assert claims brought derivatively on behalf of the Company against certain of its officers and directors for alleged breach of fiduciary duty and other claims, including waste of corporate assets and unjust enrichment.
The two stockholder derivative cases filed in the Second Judicial District Court of the State of Nevada in and for the County of Washoe were consolidated by the Court in an order dated May 27, 2010 and the plaintiffs filed a consolidated derivative complaint on September 7, 2010. In accordance with a stipulation between the parties, defendants filed a motion to dismiss on November 16, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the state derivative cases.
The two federal derivative cases filed in the United States District Court for the District of Nevada were consolidated by the Court in an order dated August 31, 2010. Plaintiffs filed a consolidated derivative complaint on October 28, 2010 and in accordance with a stipulation by the parties, defendants filed a motion to dismiss on December 13, 2010 which remains pending. The Company cannot make an estimate of the possible loss or range of loss on the federal derivative cases.
The Company believes the allegations in these purported derivative actions are also without merit and is defending the actions vigorously.
Other
From time to time, the Company is named as a party in various lawsuits, claims and other legal and regulatory proceedings that arise in the ordinary course of its 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, the Company accrues reserves in accordance with accounting principles generally accepted in the U.S. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not materially affect its business, financial condition, financial results or cash flow.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 24 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)
Included in income tax benefit (provision) for the three months ended December 31, 2009 is an out-of-period adjustment of $884,000 that increased income tax provision. Such adjustment related to tax positions taken in 2002 to 2008.
(2)
Included in income from discontinued operations for the three months ended December June 30, 2010 is an out-of-period adjustment of $570,000 that increased the after-tax gain on the sale of GDL. Such adjustment relates to an error in income taxes associated with the gain on sale of GDL in the three months ended March 31, 2010 (see Note 6)
NOTE 25 -
SUBSEQUENT EVENTS
Senior Unsecured Bonds
In February 2011, the Company accepted subscriptions for an aggregate principal amount of $107.5 million of additional senior unsecured bonds (see Note 11).
OPC Transaction
On February 3, 2011, Ormat Nevada sold to JPM all of the Class B membership units of OPC that it had acquired on October 30, 2010 for $24.9 million in cash (see Note 13).
Cash dividend
On February 22, 2011, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $2.3 million ($0.05 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 15, 2011, payable on March 24, 2011.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
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 Exchange Act, as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, the Company’s management, including the Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2010, that the disclosure controls and procedures were 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 to the Company’s management, including the Chief Executive Officer and the Chief Financial Officer to allow timely decisions regarding required disclosure.
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, 2010 using criteria established in Internal Control - Integrated Framework issued by the COSO and concluded that the Company maintained effective internal control over financial reporting as of December 31, 2010.
The effectiveness of the Company’s internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control over Financial Reporting
No changes in the Company’s internal control over financial reporting, as defined in Rule 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.
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 2010 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:
*
Performs the functions described in the table, but is employed by Ormat Systems.
(1)
Denotes Class I Director - Term expiring at 2011 Annual Shareholders Meeting.
(2)
Denotes Class II Director - Term expiring at 2012 Annual Shareholders Meeting.
(3)
Denotes Class III Director - Term expiring at 2013 Annual Shareholders Meeting.
Lucien Y. Bronicki. Lucien Y. Bronicki is the Chairman of our Board of Directors, , a position he has held since our inception in 1994, and has also been our Chief Technology Officer since July 1, 2004. Mr. Bronicki co-founded Ormat Turbines Ltd. in 1965 and is the Chairman of the Board of Directors of Ormat Industries Ltd., the publicly-traded successor to Ormat Turbines Ltd., and various of its subsidiaries. From 1999 to April 2006, Mr. Bronicki served as the Chairman of the Board of Directors of OPTI Canada Inc., a company engaged in the oil sands industry in Canada in which our parent owns an approximately 5% interest. From 1992 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Engines, a manufacturer of jet engines, and from 1997 to May 2006, Mr. Bronicki was the Chairman of the Board of Directors of Bet Shemesh Holdings. Mr. Bronicki was also the Chairman of the Board of Directors of Orad Hi-Tec Systems Ltd., a 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 Métiers, a Master of Science in Physics from Universite de Paris and a Master of Science in Mechanical Engineering from École Nationale Supérieure d’Ingenieurs Arts et Métiers. He received a Ph.D. Honoris Causa in 2005 from the Ben-Gurion University, in 2006 from the Weizmann Institute of Science, and in 2007 from the Technion - Israel Institute of Technology.
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, Mrs. Bronicki also served as our President. Mrs. Bronicki was 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, until May 2005, Mrs. Bronicki was a member of the Board of Directors of OPTI Canada Inc., a company engaged in the oil sands industry in Canada and in which our parent owns an approximately 5% interest, and since 2000 she has been 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. In 2007, she received a PhD. Honoris Causa from the Technion - Israel Institute of Technology.
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. 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 Inc.; 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 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 Operations, since November 4, 2009. From July 1, 2004 to November 3, 2009, Mr. Amir was our Executive Vice President of Engineering; from 2001 to June 30, 2004, he 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 to 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 Business Development, Rest of the World since January 1, 2010. From July 1, 2004 to December 31, 2009, Mr. Shiloah served as our Executive
Vice President of Marketing and Sales, Rest of the World; from 2001 to June 30, 2004, he was the Executive Vice President of Marketing and Sales of 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 Jerusalem in 1972.
Zvi Krieger. Zvi Krieger has served as our Executive Vice President of Geothermal Resource, since November 4, 2009; from September 20, 2007 to November 3, 2009, Mr. Krieger was our Senior Vice President of Geothermal Engineering; from July 1, 2004 to September 20, 2007, he was our Vice President of Geothermal Engineering; and from 2001 to 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 Engineering, since November 4, 2009. From September 20, 2007 to November 3, 2009, Mr. Hatzir was our Senior Vice President of Electrical and Conceptual Engineering; from July 1, 2004 to September 20, 2007, he was our Vice President of Electrical and Conceptual Engineering; and from 2002 to June 30, 2004, he was the Vice President of Electrical and Conceptual Engineering of Ormat Industries Ltd; from 1996 to 2001, he was Manager of Electrical and Conceptual Engineering of Ormat Industries Ltd.; and from 1989 to 1995, he was a 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; from 1999 to June 30, 2004, she was the Vice President of Contract Management of Ormat Industries Ltd; from 1991 to 1999, she 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.
Nir Wolf. Nir Wolf has served as our Vice President for Marketing and Sales, Rest of the World since January 1, 2010. From December 2005 to December 31, 2009, Mr. Wolf served as our Vice President Distributed Power responsible for the marketing, sales, engineering and after sales activities of the remote power units. From December 1999 to December 2005, Mr. Wolf had a leading position as Business Development Manager in the Marketing and Sales Department. Starting January 14, 1994, when Mr. Wolf joined us, he was positioned in the Project Management Department as a Budget and Schedule Controller and later on as a Project Manager. Mr. Wolf obtained a Bachelor of Science in Industrial Engineering, cum laude from the Technion - Israel Institute of Technology in 1991. In 1995, Mr. Wolf obtained a Master of Business Administration from the Bar Ilan University. Mr. Wolf participated in the Technion Institute of Management Senior Executive Program.
Dan Falk. Dan Falk has been a member of our Board of Directors since November 12, 2004. Mr. Falk also serves as the Chairman of the Board of Directors of Orad Hi-Tech Systems Ltd., a public non-U.S. company. He is also a member of the Board of Directors of Orbotech Ltd., Nice Systems Ltd., Attunity 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: Amiad Filteration System Ltd., Plastopil Ltd., and Oridion Medical Ltd. During the past five years, Mr. Falk served as a member of the Board of Directors of the following public companies, for which he no longer serves as a Director: AVT Ltd., Clicksoftware Technologies Ltd., Dmatek Ltd., Jacada Ltd., Poalim Ventures I Ltd., Medcon Ltd., and Ramdor 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 N.V. 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 Orbotech Ltd. Mr. Falk obtained a Masters 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.
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 serves 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 Directors 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, and as a member of the advisory boards of the Shidler College of Business at the University of Hawaii, of Sennet Capital, and of Aina Koa Pono, a Hawaii based privately held company exploring renewable energy projects in converting biomass into fuels. 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.
David Wagener. David Wagener has been a member of our Board of Directors since April 1, 2010. Since June 1995, Mr. Wagener has been the Managing Partner of Wagener Capital Management. From 1990 to 1995, Mr. Wagener served as Director of the Public Utility & Telecommunications Group in the Investment Banking Division of Salomon Brothers, and from 1980 to 1990, he was Vice President of the Public Utility Group and Co-Head of the Independent Power Group in the Investment Banking Division of Goldman Sachs & Co. Mr. Wagener serves on the Board of Directors of Suncor Development Company, a subsidiary of Pinnacle West Capital Corporation. He received his Bachelor’s degree in 1976 from Harvard College and his Master’s degree in Business Administration in 1980 from the University of Chicago.
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 Exchange Act, 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), Roger W. Gale, and Robert Clarke 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 2011 Proxy Statement.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required under this item is incorporated by reference herein from the Company’s definitive 2011 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 2011 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 2011 Proxy Statement.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(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 report to be signed on its behalf by the undersigned, thereunto duly authorized.
ORMAT TECHNOLOGIES, INC.
By:
/s/ YEHUDIT BRONICKI
Name: Yehudit Bronicki
Title:
Chief Executive Officer and Director
Date: February 28, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated, on February 28, 2011.
(c)
EXHIBIT INDEX