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 that is primarily engaged in the geothermal and recovered energy power businesses. We are also expanding into the storage, demand response and energy management business.
We design, develop, build, sell, own, and operate clean, environmentally friendly geothermal and recovered energy-based power plants, usually using equipment that we design and manufacture. Our objective is to become a leading global provider of renewable energy and we have adopted a strategic plan to focus on several key initiatives to expand our business.
Our owned geothermal power plants include both power plants that we have built and power plants that we have acquired. 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. As a result, electricity produced from geothermal energy sources contributes significantly less to global warming and local and regional incidences of acid rain than energy produced by burning fossil fuels. In addition, compared to power plants that utilize other renewable energy sources, such as wind or solar, geothermal power plants are generally available all year-long and all day-long and can provide base-load electricity services. Geothermal power plants can also be custom built to provide a range of electricity services such as baseload, voltage regulation, reserves and flexible capacity. Geothermal energy is also an attractive alternative to other sources of energy to support a diversification strategy to avoid dependence on any one energy source or politically sensitive supply sources.
In addition to our geothermal energy business, we manufacture and sell products that produce electricity from recovered energy or so-called “waste heat”. We also construct, own, and operate recovered energy-based power plants. We have built all of the recovered energy-based plants that we operate. Recovered energy comes from 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.
In March 2017, we entered the energy storage, demand response and energy management markets following the acquisition of substantially all of the business and assets of Viridity Energy, Inc., a Philadelphia-based company. The acquired business and assets comprise our Other segment. We are using our Viridity business to accelerate long-term growth, expand our market presence in a growing market and further develop our energy storage, demand response and energy management services, including the VPower™ software platform. We plan to continue providing services and products to existing Viridity customers, while expanding our service offerings to include development and EPC into new regions and targeting a broader potential customer base.
We currently conduct our business activities in three business segments:
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Electricity Segment. In the Electricity segment we develop, build, own and operate geothermal and recovered energy-based power plants in the U.S. and geothermal power plants in other countries around the world and sell the electricity they generate.
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Product Segment. In the Product segment we design, manufacture and sell equipment for geothermal and recovered energy-based electricity generation and remote power units and provide services relating to the engineering, procurement, construction, operation and maintenance of geothermal, Solar PV and recovered energy-based power plants.
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Other Segment. In the Other segment, we provide energy storage, demand response and energy management related services as well as services relating to the engineering, procurement, construction, operation and maintenance of energy storage units mainly through our Viridity business.
Business Strategy
Our strategy is focused on further developing a geographically balanced portfolio of geothermal and recovered energy assets and continuing our leading position in the geothermal energy market with the objective of becoming a leading global provider of renewable energy. We intend to implement this strategy through:
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Development and Construction of New Geothermal Power Plants - continuously seeking out commercially exploitable geothermal resources, developing and constructing new geothermal power plants and entering into long-term PPAs providing stable cash flows in jurisdictions where the regulatory, tax and business environments encourage or provide incentives for such development;
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Expanding our Geographical Reach - increasing our business development activities in an effort to grow our business in the global markets in all business segments. While we continue to evaluate global opportunities, we currently see Turkey, New Zealand, Chile, Kenya, Honduras, China, Indonesia and Ethiopia as attractive markets for us. We are actively looking at ways to expand our presence in those countries.
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Acquisition of New Assets - expanding and accelerating growth through acquisition activities globally, aiming to acquire additional geothermal assets as well as technologies and projects that can support our storage business.
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Manufacturing and Providing Products and EPC Services Related to Renewable Energy - designing, manufacturing and contracting power plants for our own use and selling to third parties power units and other generation equipment for geothermal and recovered energy-based electricity generation;
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Expanding into New Technologies - leveraging our technological capabilities over a variety of renewable energy platforms, including solar power generation and energy storage. Initially, however, we expect that our focus will be on expanding our core geothermal competencies to provide high efficiency solutions for high enthalpy applications by utilizing our binary enhanced cycle and technology, as well as, expanding into steam geothermal generation equipment and facilities. We may acquire companies with integration and technological capabilities we do not currently have, or develop new technology ourselves, where we can effectively leverage our expertise to implement this part of our strategic plan.
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Expand our Customer Base - evaluating a number of strategies for expanding our customer base to the C&I and CCA markets. In the near term, however, we expect that the majority of our revenues will continue to be generated, with our traditional electrical utility customer base for the Electricity segment.
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Increasing Output from Our Existing Power Plants - increasing output from our existing geothermal power plants by adding additional generating capacity, upgrading plant technology, and improving geothermal reservoir operations, including improving methods of heat source supply and delivery.
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Cost Saving by Increasing Efficiencies - increasing efficiencies in our operating power plants and manufacturing facility including procurement by adding new technologies, restructuring of management control, automating part of our manufacturing work and centralizing our operating power plants.
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Technological Expertise - investing in research and development of renewable energy technologies and leveraging our technological expertise to continuously improve power plant components, reduce operations and maintenance costs, develop competitive and environmentally friendly products for electricity generation and target new service opportunities.
The map below shows our worldwide portfolio of operating geothermal and recovered energy power plants as of February 26, 2019.
* In the Sarulla project, we include our 12.75% share only.
The charts below show the relative contributions of each of our segments to our consolidated revenues and the geographical breakdown of our segment revenues for the fiscal year ended December 31, 2018. Additional information concerning our segment operations, including year-over-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 our revenues for each of the years ended December 31, 2017 and 2018 (*):
(*) The contribution of the Other segment to revenues in 2017 was lower than 0.5% and therefore rounded down to 0% in the graph above.
The following chart sets forth the geographical breakdown of revenues attributable to our Electricity, Product and Other segments for each of the years ended December 31, 2017 and 2018:
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 Forms 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 biennial Sustainability Report, 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 and complexes as of February 26, 2019. The generating capacity of certain of our power plants and complexes listed below has been updated from our 2017 disclosure to reflect changes in the resource temperature and other factors that impact resource capabilities:
1.
We indirectly own and operate all of our power plants, although financial institutions hold equity interests in one of our Opal Geo subsidiaries, which owns the McGinness Hills Phases 1 and 2 geothermal power plants, the Tuscarora and Jersey Valley power plants and the second phase of the Don A. Campbell power plant, all located in Nevada. In the table above, we list these power plants as being 100% owned because all of the generating capacity is owned by Opal and we control the operation of the power plants. The nature of the equity interests held by the financial institution is described below in Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the headings “Opal Transaction”.
Notwithstanding our approximate 60% equity interest in the Bouillante power plant and 63.25% direct equity interest in the Puna, the first phase of Don A. Campbell, OREG 1, OREG 2 and OREG 3 power plants as well as the indirect interest in the second phase of the Don A. Campbell power plant owned by our subsidiary, ORPD, we list 100% of the generating capacity of the Bouillante power plant and the power plants in the ORPD portfolio in the table above because we control their operation. We list our 12.75% share of the generating capacity of the Sarulla power plant as we own a 12.75% minority interest. The revenues from the Sarulla project are not consolidated and are presented under “Equity in earnings (losses) of investees, net” in our financial statements.
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References to generating capacity generally refer to the gross generating capacity less auxiliary power in the case of all of our existing power plants, except the Zunil power plant. We determine the generating capacity figures in these power plants by taking into account resource and power plant capabilities. In the case of the Zunil power plant, revenues are calculated based on a 24 MW capacity unrelated to the actual performance of the reservoir. This column represents our net ownership of such generating capacity.
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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.
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The McGinness Hills complex includes 48MW of phase 3 that reached commercial operation in December 2018.
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We own 63.75%, CDC owns 21.25% and Sageos own 15%, of the Bouillante power plant.
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The Olkaria complex includes a 11MW repowering addition that reached commercial operation on June 2, 2018.
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The OREG 4 power plant is not operating at full capacity because of low run time of the compressor station that serves as the power plant’s heat source. This results in lower power generation.
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The Neal Hot Springs, Raft River and San Emidio are power plants that we acquired in April 2018 while acquiring US Geothermal Inc.
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We own 60% and Enbridge own 40% of the Neal Hot Springs power plant.
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The Puna geothermal power plant was shut down since May 3, 2018, when the Kilauea volcano located in close proximity to it erupted following a significant increase in seismic activity in the area. We are working to bring the power plant back to operation.
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The total availability of the geothermal power plants excludes the Zunil power plant as its generating capacity is determined unrelated to its performance and the Puna power plant that is not in operation, both as discussed above.
All of the revenues that we derive from the sale of electricity are pursuant to long-term PPAs. Approximately 34.9% of our total revenues in the year ended December 31, 2018 were derived from the sale of electricity by our power plants to power purchasers that currently have investment grade credit ratings. The purchasers of electricity from our foreign power plants are mainly state-owned entities.
New Power Plants
We are currently in various stages of construction of new power plants and expansion of existing power plants. Our construction and expansion plan include 37 MW in generating capacity from geothermal and Solar PV power plants in the United States that we fully released for construction. In addition, we have several geothermal and Solar PV projects in the U.S. and Guadeloupe that are either under initial stages of construction or under different stages of development with an aggregate capacity of between 130 MW and 150 MW.
We have substantial land positions across 38 prospects, 28 prospects in the U.S., and 10 prospects in Ethiopia, Guadeloupe, Guatemala, Honduras, Indonesia and New Zealand that we expect will support future geothermal development and on which we have started or plan to start exploration activity. These land positions are comprised of various leases, exploration concessions for geothermal resources and an option to enter into leases.
In addition, we are currently developing a storage system in Georgetown, Texas.
Our Product Business (Product Segment)
We design, manufacture and sell products for electricity generation and provide the related services described below. We primarily manufacture products to fill customer orders, but in some situations, we may manufacture products as inventory for future projects that we will own and for future third party projects.
Power Units for Geothermal Power Plants
We design, manufacture and sell power units for geothermal electricity generation, which we refer to as OECs. In geothermal power plants using OECs, geothermal fluid (either hot water, also called brine, or steam or both) is extracted from the underground reservoir and flows from the wellhead to a vaporizer that heats a secondary working fluid, which is vaporized and used to drive the turbine. The secondary fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer. The cooled geothermal fluid is then reinjected back into the reservoir. Our customers include contractors, geothermal power plant developers, 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 serve as an EPC contractor for 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 our target customers for the sale of our recovered energy-based power units as described above. Unlike many other companies that provide EPC services, we believe that our competitive advantage is in using equipment that we manufacture and thus have better quality and better control over the timing and delivery of required equipment and their related costs.
Remote Power Units and Other Generators
We design, manufacture and sell fossil fuel powered turbo-generators with capacities ranging from 200 watts to 5,000 watts, which operate unattended in extreme hot or cold climate conditions. Our customers include contractors who install gas pipelines in remote areas and offshore platforms operators and contractors. In addition, we design, manufacture, and sell generators, including heavy duty direct-current generators, for various other uses. We are in the process of winding down these activities.
Our New Activity (Our Other Segment)
Our storage business currently manages, through the Viridity platform, curtailable customer loads of over 875 MW across 3,000 sites under contracts with leading U.S. retail energy providers and directly with large C&I customers, including management of a portfolio of non-utility storage assets located in the northeastern U.S. with over 80,000 operational market hours. We serve our distributed customers through a NOC, which is operated 24/7 using our VPowerTM software platform and a SCADA platform. VPowerTM services are provided to customers using a SaaS model under which we receive license fees and/or a portion of the revenue and savings that are achieved for our Viridity customers.
We expect that the ecosystem we created, combining our Viridity capabilities and our legacy Ormat capabilities, including among others, our global presence, experience in technology and system integration, development and EPC of power generation projects, flexible business models, and our reputation and experience in the geothermal and recovered energy sectors, will enable us to expand in the growing energy storage sector.
Our Viridity business obtained and maintains authorization from FERC to make wholesale purchase and sales of energy, capacity, and ancillary services at market-based rates, and we have confirmed membership status with eligibility to serve designated contractual functions within each of the following ISOs and RTOs: PJM, NYISO, and the ERCOT. Additionally, during the fourth quarter of 2017, we received formal notice of membership in MISO and ISO New England Inc. and have filed for membership in IESO - Ontario Canada. In the future, we may need to obtain and maintain similar membership and eligibility status with other ISO and RTO markets in which our Viridity business will operate.
In 2018, we successfully brought on line our first two Ormat/Viridity-owned BESS projects: 1 MW / 1 MWh in Atlantic City, NJ and 20 MW / 20 MWh in Plumsted, NJ. We also started construction of another 20 MW/ 20 MWh project in Alpha, NJ and continued developing a 10 MW / 12.5 MWh project in Georgetown, Texas. We plan to continue and leverage our worldwide experience in project development and finance, as well as relationships with utilities and other market participants, to develop additional such BESS projects in the U.S. and internationally.
History
Ormat Technologies, Inc. was formed as a Delaware corporation in 1994 by our former parent company Ormat Industries. 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. On February 12, 2015, we successfully completed the acquisition of Ormat Industries in an all-stock merger, eliminating its majority ownership and control of Ormat Technologies.
Industry Background
Geothermal Energy
There are several different sources or methods of obtaining 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. Geothermal production wells are normally located within several miles of the power plant, as it is not economically viable to transport geothermal fluids over longer distances due to heat and pressure loss. The geothermal reservoir is a renewable source of energy if: (i) 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 (ii) the well field is properly operated. Geothermal energy power plants typically have higher capital costs (primarily because 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.
EGS - An EGS is a subsurface system that may be artificially created to extract heat from hot rock where the permeability and aquifers required for a hydrothermal system are insufficient or non-existent. A geothermal power plant that uses EGS techniques recovers 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 as a by-product of oil and gas extraction. When oil and gas wells are deep, the extracted fluids are often at high temperatures and if the water volume associated with the extracted fluids 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 briefly 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 vaporizer that heats a secondary working fluid. This is typically an organic fluid, such as pentane or butane, which is vaporized and is used to drive the turbine. The organic fluid is then condensed in a condenser, which may be cooled directly by air or by water from a cooling tower and sent back to the vaporizer through a pump. The cooled geothermal fluid is then reinjected back into the reservoir. The operation of our air-cooled binary geothermal power plant is depicted in the diagram 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, where any remaining water droplets are removed. This produces a stream of dry saturated steam, which drives a steam 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 by means of a vacuum system in order to maintain the performance of the steam condenser. The resulting condensate is used to provide make-up water for the cooling tower. The hot brine remaining after separation of steam is injected (either directly or after passing through a binary plant to produce additional power from the residual heat remaining in the brine) back into the geothermal resource through a series of injection wells. The flash technology is depicted in the diagram below.
In some instances, the wells directly produce dry steam and the steam is fed directly to the steam turbine with the rest of the system similar to the flash technology described above.
Our Proprietary Technology
Our proprietary technology may be used either in power plants operating according to the ORC alone or in combination with various other commonly used thermodynamic technologies that convert heat to mechanical power, such as gas and steam turbines. 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 which are non-ozone-depleting substances). By using advanced computational fluid dynamics techniques 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. We are always examining ways to increase the output of our plants by utilizing evaporative cooling, cold reinjection, configuration optimization, and topping turbines. In the geothermal as well as the recovered energy (waste heat) areas, we are examining two-level and three-level energy systems and other thermodynamic cycle alternations along with new motive fluids.
We also developed, patented and constructed GCCU 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 Geothermal Combined Cycle technology is depicted in the diagram below.
In the conversion of geothermal energy into electricity, our technology has a number of advantages over conventional geothermal steam turbine plants. A conventional geothermal steam turbine plant consumes significant quantities of water, causing depletion of the aquifer and requiring cooling water treatment with chemicals and consequently 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 towers, especially during cold weather. By contrast, our binary and combined cycle geothermal power plants have a low profile with minimal 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 maintenance and higher yearly availability. For instance, the OEC employs a low speed and high efficiency organic vapor turbine directly coupled to the generator, eliminating the need for reduction gear. In addition, with our binary design, there is no contact between the turbine blade and geothermal fluids, which can often be very erosive and corrosive. Instead, the geothermal fluids pass through a heat exchanger, which is less susceptible to erosion and can adapt much better to corrosive fluids. In addition, with the organic vapor condensed above atmospheric pressure, no vacuum system is required.
We use the same elements of our technology in our recovered energy products. The heat source may be exhaust gases from a Brayton cycle gas turbine, low-pressure steam, or medium temperature liquid found in the process industries such as oil refining and cement manufacturing. In most cases, we attach an additional heat exchanger in which we circulate thermal oil or water 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 that of the OECs used in our geothermal power plants and enjoys the same advantages of using the ORC. In addition, our technology allows for better load following than conventional steam turbines, requires no water treatment (since it is air cooled and organic fluid motivated), and does not require the continuous presence of a licensed steam boiler operator on site.
Our REG technology is depicted in the diagram below.
Patents
We have 77 U.S. patents that are in force (and have nine U.S. patents pending). These patents and patent applications cover our products (mainly power units based on the ORC) and systems (mainly geothermal power plants and industrial waste heat recovery plants for electricity production). The products-related patents cover components that include turbines, heat exchangers, seals and controls as well as control of operation of geothermal production well pumps. The system-related patents cover not only particular components but also the overall energy conversion system from the “fuel supply” (e.g., geothermal fluid, waste heat, biomass or solar) to electricity production.
The system-related patents also cover subjects such as waste heat recovery related to gas pipeline compressors and industrial waste heat, solar power systems, disposal of non-condensable gases present in geothermal fluids, reinjection of other geothermal fluids ensuring geothermal resource sustainability, power plants for very high-pressure geothermal resources, two-phase fluids, low temperature geothermal brine as well as processes related to EGS. A number of our patents cover 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. The remaining terms of our patents range from one year to 16 years. The loss of any single patent would not have a material effect on our business or results of operations.
Research and Development
We conduct research and development activities intended to improve plant performance, reduce costs, and increase the breadth of our product offerings. The primary focus of our research and development efforts is targeting power plant conceptual thermodynamic cycle and major equipment including continued performance, cost and land usage improvements to our condensing equipment, and development of new higher efficiency and higher power output turbines.
Our Viridity business continues to develop new optimization algorithms to optimize the life of a battery energy storage system (BESS), to optimize our and our customers’ economic return and to forecast the trends surrounding our customers’ electricity consumption and the electric grid including times of peak demands and the usage of ancillary services.
We have also focused our development efforts on the engineering and design of improved energy storage systems. These development efforts include, among others, building of an energy storage lab for testing of various batteries, inverters and the integration of both. Further development of the control hardware and software for energy storage systems to follow electric grid and market signals and to optimize their delivery of energy into the markets using our VPowerTM software and SCADA platform to accelerate system optimization through cloud base algorithms.
We have developed, and continue to develop, system integration capabilities that match the appropriate system and system sizing with the appropriate battery chemistry, electrical and physical components to accommodate our needs or needs of the customers that will own such energy storage systems in light of the markets in which they will operate. We are searching for alternative chemistries, products and combinations of hybrid solutions to best address our energy storage product customers’ needs.
Additionally, we are continuing to evaluate investment opportunities in new companies with technology and/or product offerings for renewable energy and energy storage solutions.
Market Opportunities
Geothermal Market Opportunities
Renewable energy in general provides a sustainable alternative to the existing solutions to two major global issues: global warming and diminishing fossil fuel reserves. Renewable energy is sustainable and clean, as it emits no or negligible amounts of CO2. These environmental benefits have led major countries to focus their efforts on the development of renewable energy sources in general and geothermal specifically.
Today, based on an announcement by the IGA on February 2019, geothermal power is generated in 27 countries with a total installed power generation capacity of 14,600 MW at the end of 2018. The leading countries are the U.S., Indonesia, Philippines, Turkey and New Zealand. The IGA expects that 4,100 MW will be added by 2023.
Having realized the importance of renewable energy including geothermal alternatives, various governments have been preparing regulatory frameworks and policies, and providing incentives to develop the sector.
United States
RPSs or quota obligations, and FITs are the two most prominent support mechanisms that have been aiding the development of the renewable energy market in the U.S. With the identification of these mechanisms, most of the countries have framed their policies incorporating these measures.
Interest in geothermal energy in the U.S. remains strong for numerous reasons, including the legislative support, RPS goals (as described below), coal and nuclear base-load retirements, and an increasing awareness of the positive value of geothermal characteristics as compared to intermittent renewable technologies.
Today, electricity generation from geothermal resources is concentrated mainly in California, Nevada, Hawaii, Idaho, Oregon, and Utah, and we believe there are opportunities for development in other states such as New Mexico due to the potential of their geothermal resources.
Geothermal energy provides numerous benefits to the U.S. grid and economy, according to a GEA report issued in January 2017. Geothermal development and operation bring economic benefits in the form of taxes and long term high-paying jobs, and it currently has one of the lowest LCOE of all power sources in the U.S. Additionally, improvements in geothermal production make it possible to provide ancillary and on-demand services. This helps load serving entities avoid additional costs from purchasing and then balancing intermittent resources with storage or new transmission.
Federal tax initiatives
The U.S. federal government encourages production of electricity from geothermal resources or solar energy through certain tax subsidies:
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PTC - the PTC provides per kWh credit on tax paid by power producers for power produced from geothermal resources and certain other renewable energy sources and sold to an unrelated person during a taxable year. The PTC was first introduced in 1992 and has since been revised a number of times. The ARRA, which came into effect in February 2009, contains a number of important measures related to the US renewable energy industry aimed at encouraging continued growth. The PTC, which in 2018 was 2.4 cents per kWh, is adjusted annually for inflation and may be claimed for 10 years on the net electricity output sold to third parties after the project is first placed in service. Any project that started construction by December 31, 2018 must ordinarily be put in service within four years after the end of the year in which construction started or show continued construction to qualify for tax credits at these rates. The PTC is not available for power produced from geothermal resources for projects that started construction on or after January 1, 2018.
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ITC - the ITC has been amended a number of times. For a new geothermal power plant in the United States that started construction after 2017, we are permitted to claim an ITC of 10 percent of the project cost. New solar projects that are under construction by December 2019 will qualify for a 30 percent ITC. The credit will fall to 26 percent for Solar PV projects starting construction in 2020 and 22 percent for Solar PV projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December 31, 2023 to qualify for an investment tax credit at these rates. Solar projects placed in service after December 31, 2023 will only qualify for a 10 percent ITC. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.
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On December 22, 2017, the U.S. President signed into law the Tax Act, which made changes that have some impact on the renewable energy industry. Some of the key changes are as follows:
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The U.S. corporate income tax rate was reduced from 35% to 21% beginning in 2018.
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Bonus depreciation was increased from 40% expensing of qualified projects in year one to 100% beginning in on September 27, 2017. The 100% expensing is valid through 2022 and then declines through 2026.
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The BEAT provision is a new tax intended to apply to companies that significantly reduce their U.S. tax liability by making cross-border payments to affiliates. The provision aims to circumvent earnings stripping by imposing a minimum tax of 10% of taxable income. ITC and PTC can be used to offset approximately 80% BEAT. See the discussion under Item 1A
ITEM 1A. RISK FACTORS
The following risk factors should be read carefully in connection with evaluating us and this Annual Report on Form 10-K. Certain statements in “Risk Factor” are forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” elsewhere in the report:
Risks Related to the Company’s Business and Operation
Our financial performance depends on the successful operation of our geothermal and REG power plants, which are subject to various operational risks.
Our financial performance depends on the successful operation of our geothermal and REG power plants. In connection with such operations, we derived 70.9% of our total revenues for the year ended December 31, 2018 from the sale of electricity. The cost of operation and maintenance and the operating performance of our geothermal power and REG plants may be adversely affected by a variety of factors, including 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, volcanic activity, landslides, floods, releases of hazardous materials, severe weather storms, or similar occurrences affecting our power plants or any of the power purchasers or other third parties providing services to our power plants, such as the recent volcanic eruption that occurred in Hawaii's Big Island that impacted our Puna project, as discussed elsewhere in this Report; and
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the aging of power plants (which 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 flows.
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 exploration sites where we have conducted tests, acquired land rights, and drilled test wells, which would adversely affect our development of geothermal power plants. Further, since the commencement of their operations, several of our power plants have experienced geothermal resource cooling, uncontrolled flow and/or reservoir pressure decline in the normal course of operations. Because geothermal reservoirs are complex geological structures, we can only estimate their geographic area and sustainable output. The viability of geothermal 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. 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. Costs 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 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. Also, volcanic eruptions and lava flows may happen in Hawaii, Guatemala and Indonesia. Serious seismic disturbances, volcanic eruptions and lava flows are possible and could result in damage to our power plants (or transmission lines used by customers who buy electricity from us) 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, volcanic eruptions and lava flows, 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, volcanic eruptions and lava flows.
On May 3, 2018, the Kilauea volcano located in close proximity to our Puna 38 MW geothermal power plant in the Puna district of Hawaii's Big Island erupted following a significant increase in seismic activity in the area. Before it recently stopped flowing, the lava covered the wellheads of three geothermal wells, monitoring wells and the substation of the Puna complex and an adjacent warehouse that stored a drilling rig that was also consumed by the lava. The insurance policy coverage for property and business interruption is provided by a consortium of insurers. All the insurers accepted and started paying for the costs to rebuild the destroyed substation, and as of December 31, 2018 we received $3.3 million. However only some of the insurers accepted that the business interruption coverage started in May 2018 and as of December 31, 2018 we recorded $12.1 million of such proceeds. We are still in discussions to reach an understanding with all insurers to start paying for the business interruption as of May 2018. The Company is still assessing the damages in the Puna facilities and continue to coordinate with HELCO and local authorities to bring the power plant back to operation. The Company continues to assess the accounting implications of this event on the assets and liabilities on its balance sheet and whether an impairment will be required. Any significant physical damage to the geothermal resource or continued shut-down following the recent stop of the lava of the Puna facilities could have an adverse impact on the power plant's electricity generation and availability, which in turn could have a material adverse impact on our business and results of operations.
In addition to our power plant in Puna, Hawaii, our power plant in Amatitlan, Guatemala is located in proximity to an active volcano. As a result of recent events impacting our Puna facility, we cannot be certain how investors will assess the risks to which our facilities are subject and whether this assessment will adversely impact perceptions of our business and our share price.
Furthermore, absent additional geologic/hydrologic studies, any increase in power generation from our geothermal power plants, 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 decline in value over time and may adversely affect our ability to generate power from the relevant power plant.
We may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan, and the plan as implemented may not achieve its goal of enhancing shareholder value through long-term growth of the Company
We adopted a multi-year strategic plan to:
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expand our geographic base;
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expand into new technologies, such as energy storage and solar PV electric power generation both in large “utility scale” projects and smaller C&I projects for commercial, industrial, governmental, educational and other institutional customers; and
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expand our customer base.
There are uncertainties and risks associated with the plan, both as to implementation and outcome. We may decide to change, or to not implement, one or more elements of the plan over time or we may not be successful in implementing one or more elements of the plan, in each case for a number of reasons. For example, we may face significant challenges and risks expanding into new technologies (or expanding our geographical or customer base for those new technologies), including:
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our ability to compete with the large number of other companies pursuing similar business opportunities in energy storage and solar PV power generation, many of which already have established businesses in these areas and/or have greater financial, strategic, technological or other resources than we have;
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our ability to obtain financing on terms we consider acceptable, or at all, which we may need, for example, to obtain any technology, personnel, intellectual property, or to acquire one or more existing businesses as a platform for our expansion, or to fund internal research and development, for energy storage and solar PV electric power generation products and services;
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our ability to provide energy storage or solar electric power generation products or services that keep pace with rapidly changing technology, customer preferences, equipment costs, market conditions and other factors that are unknown to us now that will impact these markets;
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our ability to devote the amount of management time and other resources required to implement this plan, while continuing to grow our core geothermal and recovered energy businesses; and
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our ability to recruit appropriate employees.
Expanding our geothermal and recovered energy businesses to new customers and geographical areas will have many of the same risks and uncertainties as those outlined above.
Implementing the plan may also involve various costs, including, among other things:
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opportunity costs associated with foregone alternative uses of our resources;
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various expense items that will impact our current financial results; and
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asset revaluations (for example, businesses or other assets acquired for new energy storage or solar PV power generation products or services may suffer impairment charges, as a result of rapidly changing technology, market conditions or otherwise).
These costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs, or the failure to implement successfully one or more elements of the plan, could adversely affect our reputation and the reputation of our subsidiaries and could materially and adversely affect our business, financial condition, future results and cash flow.
Apart from the risks associated with implementing the plan, the plan itself will expose us to other risks and uncertainties once implemented. Expanding our customer base may expose us to different credit profile customers than our current customers. Expanding our geographic base will subject us to risks associated with doing business in new foreign countries in which we will have to learn the business and political environment. In addition, expanding into new technologies will expose us to new risks and uncertainties that are unknown to us now in addition to the risks and uncertainties that may be similar to those we now face. The success of the plan, once implemented, will depend, among other things, on our ability to manage these risks effectively.
The trading price of our common stock could decline if securities, industry analysts or our investors disagree with our strategic plan or the way we implement it accordingly, there is no assurance that the plan will enhance shareholder value through long-term growth of the Company to the extent currently anticipated by our management or at all.
Concentration of customers and regions may expose us to heightened financial exposure.
Our businesses often rely on a single customer to purchase all or a significant portion of a facility’s output. The financial performance of these facilities depends on such customer continuing to perform its obligations under a long-term agreement between the parties. A facility’s financial results could be materially and adversely affected if any of our customers fail to fulfill its contractual obligations and we are unable to find other customers to purchase at the same level of profitability. We cannot assure that such performance failures by our customers will not occur, or that if they do occur, such failures will not adversely affect the cash flows or profitability of our businesses.
For example, in the Electricity segment, we are exposed to the credit and financial condition of KPLC that buy the power generated from our Olkaria III in Kenya. In 2018, KPLC accounted for 16.6% of our total revenues. Any change in KPLC's financial condition may adversely affect us. Another example, we are exposed to the credit and financial condition of SCPPA and its municipal utility members that account for 15.2% of our total revenues, as customers that buy the output from seven of our geothermal power plants. Because our contracts with SCPPA are long-term, we may be adversely affected if the credit quality of any of these customers were to decline or if their respective financial conditions were to deteriorate or if they are otherwise unable to perform their obligations under our long-term contracts.
Another example, Pacific Gas & Electric who accounted for approximately 1.9% of our total revenues, is facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. If Pacific Gas & Electric is found liable for the wildfires, its potential liabilities could exceed $30B. As a result, on January 29, 2019, Pacific Gas & Electric filed for reorganization under Chapter 11 bankruptcy. We are closely monitoring our Pacific Gas & Electric account to ensure cash receipts are received timely each month. However, we cannot estimate at this stage the impact that this Chapter 11 reorganization may have on us.
In the Product segment, 23.5% and 83.6% of our 2018 total revenues and Products segment revenue, respectively, derived from our operation in Turkey and we rely on the continued geothermal development growth and government support for geothermal development in the country. Our revenue exposure to the Turkish market increased in 2018 and expects to remain significant in 2019, as we signed a number of new contracts in Turkey. Adverse political developments in the relationship between Turkey and the U.S., adverse economic developments in this region including the latest failed coup, devaluation of the Turkish Lira, a general slowdown in the Turkish economy and an inability to obtain project and bank financing or a decline in government support for the development of geothermal power in the country could materially and adversely affect regional demand for the geothermal equipment and services we provide in the Turkish market or the prices we may charge for such equipment and services, which in turn could materially and adversely affect our Product segment profit margins and, consequently, our business, financial condition, future results and cash flows.
Ormat established a facility in Turkey in order to locally produce several power plant components that entitle our customer for increased incentives under the renewable energy laws. The use of local equipment in renewable energy based generating facilities in Turkey entitles such facilities to significant benefits under Turkish law, provided such facilities have obtained an RER Certificate from EMRA, which requires the issuance of a local certificate. If we do not obtain the local certificate, then some of our customers under the relevant supply agreements in Turkey may not be issued a RER Certificate based on the equipment we supply to them, and we will be required to make a payment to such customers equal to the amount of the expected lost benefit
Our international operations expose us to risks related to the application of foreign laws and regulations, any of which may adversely affect our business, financial condition, future results and cash flows.
Our foreign operations in Kenya, Turkey, Guadeloupe, Guatemala, Honduras and other countries 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 the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our operations in the U.S., which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. The systems of some of these countries can be characterized by:
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selective or inconsistent enforcement of laws or regulations, sometimes in ways that have been perceived as being motivated by political or financial considerations;
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a perceived lack of judicial and prosecutorial independence from political, social and commercial forces;
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a high degree of discretion on the part of the judiciary and governmental authorities;
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legal and bureaucratic obstacles and corruption; and
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rapid evolution of legal systems in ways that may not always coincide with market developments.
These characteristics give rise to investment risks that do not exist in countries with more established legal systems in more developed economies.
We face additional risks inherent in conducting business internationally, including compliance with laws and regulations of many jurisdictions that apply to our international operations. These laws and regulations include data privacy requirements, labor relations laws, tax laws, competition regulations, import and trade restrictions, economic sanctions, export requirements, the Foreign Corrupt Practices Act, and other local laws that prohibit corrupt payments to governmental officials or certain payments or remunerations to customers. Given the high level of complexity of these laws, there is a risk that some provisions may be breached by us, for example through fraudulent or negligent behavior of individual employees (or third parties acting on our behalf), our failure to comply with certain formal documentation requirements, or otherwise. Violations of these laws and regulations could result in fines, criminal sanctions against us, our officers or our employees, requirements to obtain export licenses, cessation of business activities in sanctioned countries, implementation of compliance programs and prohibitions on the conduct of our business. Any such violation could include prohibitions on our ability to offer our products in one or more countries and could materially damage our reputation, our brand, our ability to attract and retain employees, our business, our financial condition and our results of 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, or our ability to import our products into such countries.
Political and economic conditions in the emerging economies where we operate may subject us to greater risk than in the developed U.S. economy, which may have a materially adverse effect on our business.
We have substantial operations outside of the U.S., both in our Electricity segment and our Product segment. In 2018, 54% of our total revenues were derived from international operations, and our international operations were significantly more profitable than our U.S. operations. A substantial portion of international revenues came from Kenya and Turkey and, to a lesser extent, from Guadeloupe, Guatemala and Honduras and other countries. Thus, disturbances to and challenges facing our foreign operations, especially in Kenya and Turkey, could have impacts on our business ranging from moderate to severe. Our foreign operations subject us 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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the adoption or expansion of trade restrictions, the occurrence or escalation of a “trade war,” or other governmental action related to tariffs or trade agreements or policies among the governments of the United States and countries where we operate;
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changes in labor relations;
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political instability and civil unrest, and risk of war;
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changes in the local electricity and/or geothermal markets;
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difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
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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, including without adequate compensation.
Electricity Segment. In 2018, the international operations of the Electricity segment accounted for 28% of our revenues, but accounted for 53% of our gross profit, 77% of our net income and 53% of our EBITDA. A substantial portion of Electricity segment international revenues came from Kenya (which also contributed disproportionately to our gross profit and net income) and, to a lesser extent, from Guadeloupe, Guatemala and Honduras. In Kenya, any break-up or potential privatization of KPLC, the power purchase for our power plants located in Kenya, may adversely affect our Olkaria III complex and our overall results of operations. Additionally, 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.
Product Segment. With respect to our Product segment, 93% of our Product segment revenues in 2018 came from international sales, primarily Turkey. Since we primarily engage in sales in those markets where there is a geothermal reservoir, any such change might adversely affect geothermal developers in those markets and, subsequently, the ability of such developers to purchase our products.
Generally. Outbreaks of civil and political unrest and acts of terrorism have also occurred in several countries in Africa, the Middle East and Latin America, where we have significant operations, such as Kenya and Turkey. For instance, Kenya experienced numerous terrorist attacks in 2014 and 2015, and has experienced an upsurge in attacks in more recent years, including in early 2019, from extremist groups. Continued or escalated civil and political unrest and acts of terrorism in the countries in which we operate could result in our curtailing operations. In the event that countries in which we operate experience civil or political unrest or acts of terrorism, especially in events where such unrest leads to an unseating of the established government, our operations in such countries could be materially impaired. 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. Any or all of the changes discussed above could materially and adversely affect our business, financial condition, future results and cash flow.
Two of our facilities accounts for 26% of our revenues and contribute significantly to our profitability.
Our business relies significantly on the performance of our two largest projects, the McGinness Hills complex in East Nevada and Olkaria III Complex in Kenya, which together account for more than 30% of the total generating capacity of our Electricity segment. These two facilities accounted for 26% of our total revenues for the year ended December 31, 2018. Just over one third of the generating capacity at McGinness Hills reached commercial operation in December 2018 and its contribution to our results may therefore be higher in the future. Any disruption to the operation of these facilities would have a disproportionately adverse effect on our revenues and on our profitability compared to our other facilities.
Conditions in and around Israel, where the majority of our senior management and our main 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.
The majority of our senior management and our main production and manufacturing facilities are located in Israel approximately 26 miles from the border with the Gaza Strip. As such, political, economic and security conditions in Israel directly affect our operations.
The political instability and civil unrest in the Middle East and North Africa (including the ongoing civil war in Syria) as well as the increased tension between Iran and Israel 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.
These events and conditions could disrupt our operations in Israel, which could materially and adversely affect our business, financial condition, future results, and cash flow.
We have significant operations globally, including in countries that may be adversely affected by political or economic instability, major hostilities or acts of terrorism, which exposes us to risks and challenges associated with conducting business internationally.
We have substantial operations outside of the U.S., both in our Electricity segment and our Product segment. Terrorist acts or other similar events could harm our business by limiting our ability to generate or transmit power and by delaying the development and construction of new generating facilities and capital improvements to existing facilities. These events, and governmental actions in response, could result in a material decrease in revenues and significant additional costs to repair and insure our assets, and could adversely affect operations by contributing to the disruption of supplies and markets for geothermal and recovered energy. Such events could also impair our ability to raise capital by contributing to financial instability and lower economic activity.
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 (approximately 249,000 acres) 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, may 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 could 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.
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 in the process of developing and constructing a number of new power plants. Our success in developing a project is contingent upon, among other things, negotiation of satisfactory engineering and construction agreements and obtaining PPAs and transmission services agreements, receipt of required governmental permits, obtaining adequate financing, and the timely implementation and satisfactory completion of field development, testing and power plant construction and commissioning. 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 and applicable transmission services agreements, obtaining all required governmental permits and approvals and arranging, in certain cases, adequate financing prior to the commencement of construction, the development of a power project may require us to incur significant expenses for preliminary engineering, permitting and legal and other expenses before we can determine whether a project is feasible, economically attractive or capable of being financed.
Currently, we have geothermal projects and prospects under exploration, development or construction in the U.S., as well as in Ethiopia, Guadeloupe, Guatemala, Honduras, Indonesia and New Zealand, 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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inability to secure a PPA;
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inability to secure transmission services agreements;
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inability to secure the required financing;
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cost increases and delays due to unanticipated shortages of adequate resources to execute the project such as equipment, material and labor;
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work stoppages resulting from force majeure event including riots, strikes and whether conditions;
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inability to obtain permits, licenses and other regulatory approvals;
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failure to secure sufficient land positions for the wellfield, power plant and rights of way;
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failure by key contractors and vendors to timely and properly perform, including where we use equipment manufactured by others;
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inability to secure or delays in securing the required transmission line and/or capacity;
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adverse environmental and geological conditions (including inclement weather conditions);
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adverse local business law; and
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our attention to other projects and activities, including those in the solar energy and energy storage sectors.
Any one of these 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, of if there is a failure that requires long shutdown for repair, or if curtailment is required due to load and inefficiency system, 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.
Our use of joint ventures may limit our flexibility with jointly owned investments.
We have partners in several of our plants and we may continue in the future to develop and/or acquire and/or hold properties in joint ventures with other entities when circumstances warrant the use of these structures. Ownership of assets in joint ventures is subject to risks that may not be present with other methods of ownership, including:
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we could experience an impasse on certain decisions because we do not have sole decision-making authority, which could require us to expend additional resources on resolving such impasses or potential disputes, including arbitration or litigation;
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our joint venture partners could have investment goals that are not consistent with our investment objectives, including the timing, terms and strategies for any investments in the projects that are owned by the joint ventures, which could affect decisions about future capital expenditures, major operational expenditures and retirement of assets, among other things;
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our ability to transfer our interest in a joint venture to a third party may be restricted and the market for our interest may be limited;
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our joint venture partners may be structured differently than us for tax purposes, and this could impact our ability to fully take advantage of federal tax incentives available for renewable energy projects;
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our joint venture partners might become bankrupt, fail to fund their share of required capital contributions or fail to fulfill their obligations as a joint venture partner, which may require us to infuse our own capital into the venture on behalf of the partner despite other competing uses for such capital; and
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our joint venture partners may have competing interests in our markets and investments in companies that compete directly or indirectly with us that could create conflict of interest issues.
Seasonal variations may cause 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 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.
Storage projects that we are currently developing or plan to develop in the future may operate as "merchant" facilities without long-term power services agreements for some or all of their generating capacity and output and therefore such projects will be exposed to market fluctuations.
Storage projects that we own and operate, as well others we are currently developing or plan to develop in the future, may operate as "merchant" facilities without long-term sales agreements for some or all of their generating capacity and output and therefore such projects are exposed to market fluctuations. Without the benefit of long-term services agreements for these assets, we cannot be sure that we will be able to sell any or all of the power and ancillary services generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of our property, plant and equipment or to the closing of certain of our storage facilities, resulting in economic losses and liabilities, which could have a material adverse effect on our results of operations, financial condition or cash flows.
We may not be able to successfully integrate companies, which we acquired and 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, this 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 and/or renew long-term 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.
We face increasing competition from other companies engaged in the solar, energy storage, demand response and energy management sectors.
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 panels, 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. Our limited experience in the Solar PV sector may affect our ability to successfully develop, construct, finance, and operate Solar PV power projects.
We are experiencing intense competition in the energy storage, demand response and energy management markets. Our competitors in the energy storage, demand response and energy management markets include utilities, independent power producers, developers, new start-ups, and third-party investors, who compete more successfully in these markets than our Viridity business. If we are unable, as a result of increased competition, to expand our customer base or increase our market share in these rapidly growing markets, our business, financial condition, future results and cash flow could be materially and adversely affected.
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 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 such as hydroelectric systems, fuel cells, microturbines, wind turbines, energy storage systems and solar PV systems. Some of these alternative technologies currently produce electricity at a higher average price than our geothermal plants while others produce electricity at a lower average price, It is possible that technological advances and economies of scale will further reduce the cost of alternate methods of power generation. It is also possible that energy technologies will compete with our basic premise of a firm (non-intermittent) renewable baseload power source by combining renewable technologies with energy storage to provide an alternative to firm baseload energy. If this were to happen, the competitive advantage of our power plants may be significantly impaired.
Our intellectual property rights may not be adequate to protect our business.
Our existing intellectual property rights, including those we acquired in connection with the acquisition of our Viridity business, may not be adequate to protect our business. While we occasionally file patent applications, patents may not be issued on the basis of such applications or, if patents are issued, they may not be sufficiently broad to protect our technology. In addition, any patents issued to us or for which we have use rights may be challenged, invalidated or circumvented.
In order to safeguard our unpatented proprietary know-how, trade secrets and technology, we rely primarily upon trade secret protection and non-disclosure provisions in agreements with employees and others having access to confidential information. These measures may not adequately protect us from disclosure or misappropriation of our proprietary information.
Even if we adequately protect our intellectual property rights, litigation may be necessary to enforce these rights, which could result in substantial costs to us and a substantial diversion of management attention. Also, while we have attempted to ensure that our technology and the operation of our business do not infringe other parties’ patents and proprietary rights, our competitors or other parties may assert that certain aspects of our business or technology may be covered by patents held by them. Infringement or other intellectual property claims, regardless of merit or ultimate outcome, can be expensive and time-consuming and can divert management’s attention from our core business.
We previously identified a material weakness in our internal control over financial reporting and subsequently restated certain of our financial statements as a result of factors related to that weakness. This may adversely affect the accuracy and reliability of our financial statements and impact our reputation, business and the price of our common stock, as well as lead to a loss of investor confidence in us.
In connection with the change in our repatriation strategy and the related release of the U.S. income tax valuation allowance in the second quarter of 2017, we did not perform an effective risk assessment related to our internal controls over the accounting for income taxes. As a result, we identified a deficiency in the design of our internal control over financial reporting related to our accounting for income taxes, which affected the recording of income tax accounts by us in our interim and annual consolidated financial statements during 2017. Our management previously concluded that this deficiency constituted a material weakness in our internal control over financial reporting and, accordingly, our internal control over financial reporting and our disclosure controls and procedures were not effective as of December 31, 2017. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements will not be prevented or detected on a timely basis.
On May 16, 2018, we concluded that we would restate our previously issued consolidated financial statements as of and for the year ended December 31, 2017 to correct for (i) errors in our income tax provision, primarily related to our ability to utilize foreign tax credits in the United States (“U.S.”) prior to their expiration starting in 2027 and the resulting impact on the deferred tax asset valuation allowance, and (ii) the inappropriate netting of certain deferred income tax assets and deferred income tax liabilities across different tax jurisdictions that was not permissible under U.S. generally accepted accounting principles. In addition, we also concluded that we would revise our previously issued consolidated financial statements as of and for the years ended December 31, 2016 and December 31, 2015 to correct for errors in our income tax provision primarily related to the translation of deferred tax liabilities in a foreign subsidiary. These tax and tax-related errors also resulted in the restatement, for 2017, and revision, for 2016, of the Company’s previously issued unaudited condensed consolidated financial statements for the three months ended March 31, 2017, for the three and six months ended June 30, 2017 and 2016 and for the three and nine months ended September 30, 2017 and 2016.
While we have developed and are in the process of implementing a plan to remediate this material weakness, there can be no assurance that this will occur within 2019. We may identify additional material weaknesses in our internal control over financial reporting in the future. If we are unable to remediate this material weakness or we identify additional material weaknesses in our internal control over financial reporting in the future, our ability to analyze, record and report financial information accurately, to prepare our financial statements within the time periods specified by the rules and forms of the SEC and to otherwise comply with our reporting obligations under the federal securities laws, and in relation to covenants in certain debt facilities will likely be adversely affected. The occurrence of, or failure to remediate, and any future material weaknesses in our internal control over financial reporting may adversely affect the accuracy and reliability of our financial statements, and our reputation, business and the price of our Common Stock or any other securities we may issue, as well as lead to a loss of investor confidence in us.
Our failure to prepare and timely file our periodic reports with the SEC limits our access to the public markets to raise debt or equity capital.
We did not file our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 within the timeframe required by the SEC, meaning we were not current in our reporting requirements with the SEC. Even though we have regained compliance with our SEC reporting obligations, we will be not be eligible to use a short-form registration statement on Form S-3 that would allow us to incorporate by reference our SEC reports into the registration statement, or to use “shelf” registration statements, until one year from the date we regained and maintain status as a current filer. If we wish to pursue a public offering during this time period, we would be required to file a long-form registration statement on Form S-1 and have it reviewed and declared effective by the SEC. Doing so would likely take significantly longer than using a short-form registration statement on Form S-3, increase transaction costs and adversely impact our ability to raise capital or complete acquisitions of other companies in a timely manner.
Risks Related to Governmental Regulations, Laws and Taxation
Our financial performance could be adversely affected by changes in the legal and regulatory environment affecting our operations.
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. We or our power purchasers may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
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.
Regulations related to conflict minerals, adopted by the SEC and requires us to disclose the use of “conflict minerals” (including tantalum, tin, tungsten and gold) in our products, may force us to incur additional expenses and may damage our relationship with certain customers. If we utilize any of these minerals and they are necessary to the production or functionality of any of our products or products we are contracted to manufacture, we will need to conduct specified due diligence activities and file with the SEC a report disclosing, among other things, whether such minerals originate from the Democratic Republic of Congo or adjoining countries. The implementation of these SEC rules could adversely affect the sourcing, availability and pricing of minerals used in the manufacture of certain components incorporated in our products. In addition, we expect to incur additional costs to comply with the disclosure requirements, including costs related to determining the source of any of the relevant minerals and metals used in our products, and possibly additional expenses related to any changes to our products we may decide are advisable based upon our due diligence findings. Since our supply chain is complex, we may not be able to sufficiently verify the origins for these minerals and metals used in our products through the diligence procedures that we implement, which may harm our reputation. In such event, we may also face difficulties in satisfying customers who require that all of the components of our products are certified as conflict mineral free.
Pursuant to the terms of some of our PPAs with investor-owned electric utilities and publicly-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.
Pursuant to the terms of certain of our PPAs, we may be required to make payments to the relevant power purchaser under certain conditions, such as shortfall in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in delivery or performance requirements and is recorded in the period the shortfall occurs. In addition, if we do not meet certain minimum performance requirements, the capacity of the relevant power plant may be permanently reduced. Any or all of these considerations could materially and adversely affect our business, financial condition, future results and cash flow.
The SRAC 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 two of the PPAs for our power plants in California, the price that Southern California Edison pays is based upon its SRAC, which are the incremental costs that it would have incurred had it generated the relevant electricity itself or purchased such electricity 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 was fixed through April 2012, but since then is based on Southern California Edison’s SRAC, as determined by the CPUC. The SRAC 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 SRAC prices paid by Southern California Edison may decline following the expiration of the settlement agreements in, 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.
Under the terms of a global settlement approved by CPUC (Global Settlement) SRAC for our Heber 2 and Mammoth G2 PPAs are tied to a formula with energy market heat rates. The Global Settlement further provides that after July 1, 2015 if the term of any of the PPAs we have for these power plants expires, Southern California Edison would have no obligation to purchase power from any of these plants that has a generating capacity in excess of 20 MW, which would apply to the PPAs for our Heber 2 power plant (37 MW contract capacity) with Southern California Edison. Our Mammoth G2 plant (10.5 MW contract capacity) 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 agreed that the utilities can request from FERC a waiver of the mandatory purchase obligation under PURPA for Qualifying Facilities above 20 MW and FERC has granted such waiver for these California utilities.
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 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.
If a domestic power plant were to lose its Qualifying Facility status, it would become subject to full regulation as a public utility under the FPA, and the rates charged by such power plant pursuant to its PPAs may 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 the affected domestic power plant refund amounts previously paid by the relevant power purchaser to such power plant. Even if a power plant does not lose its Qualifying Facility status, pursuant to regulations issued by FERC for Qualifying Facility 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 also has the 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. Our existing PPAs between a Qualifying Facility and a utility are not affected. If, in addition to the California utilities’ waiver of the mandatory purchase obligation for QF projects that exceed 20 MW described in the risk factor above, the utilities in the other 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. Moreover, FERC has the authority to modify its regulations relating to the utility’s mandatory purchase obligation under PURPA, which could result in the reduction in the purchase obligation of California and other utilities to a level below 20 MW, or the elimination of the purchase obligation. If that were to occur it could materially and adversely affect our business, financial condition, future results and cash flow.
The PURPA and QF described risks identified above are not likely to affect our Nevada based facilities that entered into PPAs with NV Energy as the off-taker after Nevada initially adopted its RPS in 2001. Those PPAs and the related rates agreed to for such facilities by the off-taker were not based upon PURPA or a QF mandated rate but were instead adopted as a result of a competitive bidding process and approved as part of the off-taker’s integrated resource planning process and in order for the off-taker to comply with Nevada’s RPS. While those PPAS were initially required to file for QF or EWG status with the FERC, the PPAs and their related prices for the term of the PPA were not approved by the FERC pursuant to PURPA. The PURPA and QF risks described above also are not likely to affect our Nevada and California based projects that have their PPAs with the SCPPA because SCPPA is not a regulated public utility under PURPA.
The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows.
Construction and operation of our geothermal power plants and recovered energy-based power plants has benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects in regions and countries where we operate. Such policies and incentives include PTCs (that are applicable for projects that started construction by the end of 2017) and ITCs, accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, rebates, and mandated feed-in-tariffs, and may include similar or other incentives to end users, distributors, system integrators and manufacturers of geothermal, solar and other power products. Some of these measures have been implemented at the federal level, while others have been implemented by different states within the U.S. or countries outside the U.S. where we operate.
The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development program and continued construction of new geothermal, recovered energy-based, Solar PV power plants and, recently, energy storage projects. Any changes to such public policies, or any reduction in or elimination or expiration of such government incentives could affect us in different ways. For example, any reduction in, termination or expiration of renewable portfolio standards may result in less demand for generation from our geothermal and recovered energy-based, power plants. Any reductions in, termination or expiration of other government incentives could reduce the economic viability of, and cause us to reduce, the construction of new geothermal, recovered energy-based, Solar PV or any other power plants. Similarly, any such changes that affect the geothermal energy industry in a manner that is different from other sources of renewable energy, such as wind or solar, may put us at a competitive disadvantage compared to businesses engaged in the development, construction and operation of renewable power projects using such other resources. Any of the foregoing outcomes could have a material adverse effect on our business, financial condition, future results, and cash flows.
We are a holding company and our cash depends substantially on the performance of our subsidiaries and the power plants they operate, most of which is 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 some 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. In all of the foreign countries where our existing power plants are located, dividend payments to us may also be subject to withholding taxes. Each of the events described above may reduce or eliminate the aggregate amount of cash we can receive from our subsidiaries.
The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation may increase in the future and these costs (as well as any fines or penalties that may be imposed upon us in the event of any non-compliance with such laws or regulations) could materially and adversely affect our business, financial condition, future results and cash flow.
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. In addition, 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. 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. We have not yet obtained certain permits and government approvals required for the completion and successful operation of power plants under construction or enhancement. 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. Finally, 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.
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 butane, pentane, 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 U.S., 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.
Current and future urbanizing activities and related residential, commercial, and industrial developments may encroach on or limit geothermal or Solar PV 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 or construction and operation of Solar PV facilities, thereby affecting our ability to utilize, access, inject, and/or transport geothermal resources on or underneath the affected surface areas or build Solar PV facilities, which require large areas of relatively flat land. 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 Calexico. 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 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 plans for the construction of a new casino hotel and other commercial or industrial developments on land in the vicinity of our Steamboat complex.
Possible application of the new base erosion and anti-abuse tax in the U.S. may adversely affect us.
The recently enacted Tax Act in the U.S. included BEAT, that could apply to us and, more importantly, could reduce the amount of tax equity that can be raised on geothermal projects on which PTCs will be claimed. The aim of the base erosion tax is to prevent multinational companies from reducing their U.S. taxes by “stripping” earnings across the U.S. border by making payments to foreign affiliates that can be deducted in the U.S. An example of such a payment is interest on an intercompany loan or a payment to a back office in a foreign country for equipment or services. The goal of the BEAT is to ensure that multinational companies do not use cross-border payments to reduce their U.S. taxes to less than 10 percent (5 percent for 2018) of an expanded definition of taxable income. BEAT requires an annual calculation. Generally, the tax only applies to certain corporations with at least $500 million in average annual gross receipts for the United States for the three prior taxable years before the calculation and with base erosion payments that account for at least 3 percent (2 percent for certain corporations) of their deductions for the taxable year. If the tax applies to us, our tax equity raised on geothermal projects on which PTCs can be claimed may be reduced, which in turn may materially and adversely affect our business, financial condition, future results and cash flow.
The Israeli Tax Ruling we obtained in connection with our acquisition of Ormat Industries imposes conditions that may limit our flexibility in operating our business and our ability to enter into certain corporate transactions.
The Israeli Tax Ruling we obtained in connection with the acquisition of Ormat Industries imposes a number of conditions that limit our flexibility in operating our business and in engaging in certain corporate transactions. Until the end of 2018, we agreed to maintain (and, to the extent that our operations expand, likewise expand) the production activities we currently carry out in Israel. Under certain circumstances, these conditions may not allow us the flexibility that we need to operate our business and may prevent us from taking advantage of strategic opportunities that would benefit our business and our stockholders.
Risks Related to Economic and Financial Conditions
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.
Most of our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse or limited recourse debt obligations. 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 on 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, 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 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.
We may also need additional financing to implement our strategic plan. For example, our cash flow from operations and existing liquidity facilities may not be adequate to finance any acquisitions we may want to pursue or new technologies we may want to develop or acquire. Financing for acquisitions or technology development activities may not be available on the non-recourse or limited recourse basis we have historically used for our business, or on other terms we find acceptable.
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 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 electricity revenues 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 revenues is attributable to electricity our power plants sell to power purchasers under the relevant PPAs. There is a risk that any one or more of the power purchasers may not fulfill their respective payment obligations under their PPAs. If any of the power purchasers fails to meet its payment obligations under its PPA(s), such failure could materially and adversely affect our business, financial condition, future results and cash flow.
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. 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. 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. 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.
Possible fluctuations in the cost of construction, raw materials, commodities 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, commodities and industrial equipment components that we use. We currently obtain all such raw materials, commodities 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, commodities and equipment, to the extent not otherwise passed along to our customers, could adversely affect our profit margins.
Risks Related to Force Majeure
The existence of a prolonged force majeure event or a forced outage affecting a power plant, or the transmission systems 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, volcanic eruptions, lava flow or other similar events. If a power plant experiences an occurrence resulting in a force majeure event, although our subsidiary that owns that power plant would be excused from its obligations under the relevant PPA the relevant power purchaser may not be required to make any capacity and/or energy payments with respect to the affected power plant for as 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, and if as a result the power plant fails to attain certain performance requirements under certain of our PPAs, the power 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.
Threats of terrorism and catastrophic events that could result from, cyber-attacks, or individuals and/or groups attempting to disrupt our business, or the businesses of third parties, may impact our operations in unpredictable ways and could adversely affect our business, financial condition, future results and cash flow.
We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyber-attacks, including, among others, malware, viruses and attachments to e-mails, and other disruptive activities of individuals or groups. Our generation and transmission facilities, information technology systems and other infrastructure facilities, systems and physical assets, including our Viridity business’s VPowerTM software platform, could be directly or indirectly affected by such activities.
We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, all of our technology systems (and any programs or data stored thereon or therein) are vulnerable to security breaches, failures, data leakage or unauthorized access due to such activities. Those breaches and events may result from acts of our employees, contractors or third parties. If our technology systems were to fail or be breached and we were unable to recover in a timely way, we would be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised, which could adversely affect our business, financial condition, future results and cash flow.
The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could adversely affect our business, financial condition, future results and cash flow. In addition, such events could require significant management attention and resources and could adversely affect our reputation among customers and the public.
A disruption of transmission or the transmission infrastructure facilities of third parties could negatively impact our business. Because generation and transmission systems are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the impact of an event on the interconnected system within our systems or within a neighboring system. Any such disruption could adversely affect our business, financial condition, future results and cash flow.
U.S. federal income tax reform could adversely affect us.
On December 22, 2017, U.S. federal tax legislation, commonly referred to as the Tax Act was signed into law, significantly reforming the U.S. Internal Revenue Code. The Tax Act, among other things, reduces the U.S. federal corporate tax rate from the previous top marginal rate of 35% to a flat rate of 21%, imposes significant additional limitations on the deductibility of interest, allows for the expensing of capital expenditures, puts into effect the migration from a “worldwide” system of taxation to a territorial system and modifies or repeals many business deductions and credits, including the treatment of net operating losses.
Under the Tax Act, the deductibility of “net interest” for a business is limited to 30% of adjusted taxable income. The new proposed regulations issued by Treasury applies regardless of whether the interest payment is made to a US or foreign person, whether the interest recipient is related, or whether the interest recipient is exempt from US tax. Further, any interest that cannot be deducted in a year can be carried forward indefinitely. The Company has not early adopted these proposed regulations and intends to adopt during the 2019 tax year. For the year ended December 31, 2018, we have evaluated the impact and determined there is no limit on our interest deductibility for federal income tax purposes for the current period, but anticipates there could be significant limitations upon adoption.
We continue to examine the impact the Tax Act may have on our business. Notwithstanding the reduction in the corporate income tax rate, the overall impact of the Tax Act is uncertain, and our business, financial condition, future results and cash flow, as well as our stock price, could be adversely affected.
Risks Related to Our Stock
A substantial percentage of our common stock is held by stockholders whose interests may conflict with the interests of our other stockholders.
On July 26, 2017, ORIX purchased approximately 22% of our shares of common stock outstanding. Pursuant to the Governance Agreement between the Company and ORIX entered into in connection with this stock purchase transaction, ORIX has the right to designate three directors to our Board for as long as ORIX and its affiliates collectively hold at least 18% of the voting power of all of the outstanding voting securities of the Company as well as the right to representation on certain committees of our Board. ORIX may also exercise certain registration rights pursuant to the Registration Rights Agreement between the Company and ORIX.
As a result of these rights and ORIX’s beneficial ownership of our common stock, ORIX could exert influence through its Board representation on the business, operations and management of the Company and its subsidiaries, including our strategic plans, or, as a significant stockholder, on matters submitted to a vote of our stockholders, including mergers, consolidations and the sale of all or substantially all of our assets. This concentration of ownership of our common stock could delay or prevent proxy contests, mergers, tender offers, or other purchases of our common stock that might otherwise give our stockholders the opportunity to realize a premium over the then-prevailing market price for our shares. If ORIX exercises its registration rights to require the Company to register for sale the common stock held by ORIX or ORIX otherwise sells its common stock in the public markets, the price of our common stock may decline. This concentration of ownership may also adversely affect the liquidity of our common stock.
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 segment-based revenues or variations from year-to-year in our Product segment-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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our ability to integrate acquisitions;
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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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restatements of historical financial results and changes in financial forecasts;
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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;
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the trading of our common stock on multiple trading markets, which takes place in different currencies and at different times; 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, such as the recent class action filed on June 2018 by Mac Costas and discussed elsewhere in this report, 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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
We currently lease corporate offices at 6140 Plumas street Reno, Nevada 89519 to which we moved in the second quarter of 2018. We also occupy an approximately 807,000 square foot office and manufacturing facility located in the Industrial Park of Yavne, Israel, which we lease from the Israel Land Administration. 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 offices and manufacturing facilities 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
The information required with respect to this item can be found under “Commitments and Contingencies” in Note 22 of notes to the consolidated financial statements contained in this annual report and is incorporated by reference into this Item 8.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock has traded on the NYSE under the symbol “ORA” since November 11, 2004. Prior to November 11, 2004, there was no public market for our common stock. Effective on February 10, 2015, our common stock also began trading on the TASE under the same symbol.
As of February 26, 2019, there were 16 record holders of our common stock. On February 26, 2019, the closing price of our common stock as reported on the NYSE was $56.72 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 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 would prevent us from meeting such business plan or obligations.
Stock Performance Graph
The following performance graph represents the cumulative total shareholder return for the period December 30, 2013 through December 31, 2018 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 December 30, 2013 through December 31, 2018
* IPP Peers are The AES Corporation, NRG Energy Inc. and Covanta Holding Corp.
** Renewable Energy (Renewable) Peers is Acciona S.A.
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, 2018, 2017 and 2016 and as of December 31, 2018 and 2017 from our audited consolidated financial statements set forth in Item 8 of this annual report. We have derived the selected consolidated financial data for the years ended December 31, 2015 and 2014 and as of December 31, 2016, 2015 and 2014 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 of Fiscal Year 2018 Revenues
For the year ended December 31, 2018, our total revenues increased by 3.8% (from $692.8 million to $719.3 million) over the previous year.
For the year ended December 31, 2018, Electricity segment revenues were $509.9 million, compared to $465.6 million for the year ended December 31, 2017, an increase of 9.5%. Product segment revenues for the year ended December 31, 2018 were $201.7 million, compared to $224.5 million for the year ended December 31, 2017, a decrease of 10.1%. Other segment revenues for the year ended December 31, 2018 were $7.6 million, compared to $2.7 million for the year ended December 31, 2017.
During the years ended December 31, 2018 and 2017, our consolidated power plants generated 5,857,963 MWh and 5,489,234 MWh, respectively, an increase of 6.7%
For the year ended December 31, 2018, our Electricity segment generated 70.9% of our total revenues (67.2% in 2017), while our Product segment generated 28.0% of our total revenues (32.4% in 2017), and our Other segment generated 1.1% of our total revenues (0.4% in 2017)
For the year ended December 31, 2018, approximately 94.8% of our Electricity segment revenues were from PPAs with fixed energy rates which are not affected by fluctuations in energy commodity prices. We have variable price PPAs in California and Hawaii, which provide for payments based on the local utilities’ avoided cost, which is the incremental cost that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others, as follows:
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the energy rates under the PPAs in California for each of Heber 2 power plant in the Heber Complex and the G2 power plant in the Mammoth Complex, a total of between 30 to 40 MW, change primarily based on fluctuations in natural gas prices; and
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the prices paid for the electricity pursuant to the 25 MW PPA for the Puna Complex in Hawaii change primarily as a result of variations in the price of oil as well as other commodities.
To comply with obligations under their respective PPAs, certain of our project subsidiaries are structured as special purpose, bankruptcy remote entities and their assets and liabilities are ring-fenced. Such assets are not generally available to pay our debt, other than debt at the respective project subsidiary level. However, these project subsidiaries are allowed to pay dividends and make distributions of cash flows generated by their assets to us, subject in some cases to restrictions in debt instruments, as described below.
Electricity segment revenues are also subject to seasonal variations and can be affected by higher-than-average ambient temperatures, as described below under “Seasonality”.
Revenues attributable to our Product segment are based on the sale of equipment, EPC contracts and the provision of various services to our customers. Product segment revenues may vary from period to period because of the timing of our receipt of purchase orders and the progress of our equipment manufacturing and execution of the relevant project.
Revenues attributable to our Others segment are mainly derived from BSAAS systems, demand response and energy management services and may fluctuate between period to period. Pricing of such services and products are dependent on market supply and demand trends, market volatility, the need and price for ancillary services and other factors that may change over time.
Our management assesses the performance of our operating segments differently. In the case of our Electricity segment, when making decisions about potential acquisitions or the development of new projects, management typically focuses on the internal rate of return of the relevant investment, technical and geological matters and other business considerations. Management evaluates our operating power plants based on revenues, expenses, and EBITDA, and our projects that are under development based on costs attributable to each such project. Management evaluates the performance of our Product segment based on the timely delivery of our products, performance quality of our products, revenues and costs actually incurred to complete customer orders compared to the costs originally budgeted for such orders. We evaluate Other segment performance similar to the Electricity segment with respect to projects that we own and operate and similar to the Product segment when we provide services to third parties.
Trends and Uncertainties
Different trends, factors and uncertainties may impact our operations and financial condition, including many that we do not or cannot foresee. However, we believe that our results of operations and financial condition for the foreseeable future will be primarily affected by the following trends, factors and uncertainties that are from time to time also subject to market cycles:
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There has been increased demand for energy generated from geothermal and other renewable resources in the U.S. as costs for electricity generated from renewable resources have become more competitive. Much of this is attributable to legislative and regulatory requirements and incentives, such as state RPS and federal tax credits such as PTCs or ITCs (which are discussed in more detail in the section entitled “Government Grants and Tax Benefits” below). We believe that future demand for energy generated from geothermal and other renewable resources in the U.S. will be driven primarily by further commitment and implementation of state RPS and greenhouse gas initiatives.
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We accelerated our efforts to expand business development activities in developing countries where geothermal is considered a local resource that can provide a stable and cost effective solution to increase access to power. We expect that a variety of local governmental initiatives will create new opportunities for the development of new projects with the potential to realize higher returns on our equity as well as to 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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PG&E which accounts for 1.9% of our total revenues, is facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. If PG&E is found liable for the wildfires, its potential liabilities could exceed $30B. As a result, PG&E filed for reorganization under Chapter 11 bankruptcy. We are closely monitoring our PG&E account to ensure cash receipts are received timely each month and the payments due in January 2019 were received by Ormat and PG&E’s account is current. However, we cannot estimate at this stage the impact PG&E's current situation may have on us in the future.
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In the Electricity segment, we expect intense domestic competition from the solar and wind power generation industries to continue and increase as well as increased competition from the solar combined with storage projects. While we believe the expected demand for renewable energy will be large enough to accommodate increased competition, any such increase in competition, including increasing amounts of renewable energy under contract as well as any further decline in natural gas prices attributable to increased production and reduction in energy storage costs are contributing to a reduction in electricity prices. However, despite increased competition from the solar and wind power generation industries, we believe that firm and flexible, base-load electricity, such as geothermal-based energy, will continue to be an important source of renewable energy in areas with commercially viable geothermal resources.
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In the Product segment, we see new opportunities in Turkey, New Zealand, the U.S., Asia Pacific and Central and South America. We have experienced increased competition from binary power plant equipment suppliers including the major steam turbine manufacturers. While we believe that we have a distinct competitive advantage based on our technology, accumulated experience and current worldwide share of installed binary generation capacity, an increase in competition may impact our ability to secure new purchase orders from potential customers. The increased competition also leads to further reductions in the prices that we are able to charge for our binary equipment, as we recently experienced in Turkey, which in turn reduces our profitability. We are experiencing such competition in other locations where we operate which may have an adverse impact on the prices we can charge and our profitability.
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The 38 MW Puna Complex has three PPAs, one of which (a 25 MW PPA) has a monthly variable energy rate based on the local utility’s avoided costs. A decrease in the price of oil as well as in other commodities 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. In order to reduce our exposure to oil we signed fixed rate PPAs for the remaining 13 MW. The Puna power plant was shut-down on May 3, 2018 due to the volcano eruption in the Big Island, Hawaii (see further discussion under Recent Developments above).
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The pricing under our PPAs for the G2 power plant in the Mammoth Complex and Heber 2 power plant in the Heber Complex for a total of between 30 MW and 40 MW are variable rates based on SRAC pricing that is impacted by natural gas prices.
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The amounts that we are paid under our PPAs for electricity, capacity and other energy attributes vary for a number of reasons, including:
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market conditions when the PPA is signed;
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the competitive environment in the power market where the power plant is located and the power and other energy attributes are sold; and
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in the case of contracts described in the prior bullets with variable pricing components, current oil and natural gas prices.
This means, among other things, that the average price per MWh, which is one of the metrics some investors may use to evaluate power plant revenues, can fluctuate from period to period. Based on total Electricity segment, we earned, on average, $87.0 and $84.8 per MWh in 2018 and 2017, respectively. Oil and natural gas prices, together with other factors that affect our Electricity segment revenues, could cause changes in our average price per MWh in the future.
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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 and injection 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 that we face in connection with our growth expectations.
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As our power plants (including their respective well fields) 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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Turkey’s geothermal market is one of the fastest growing markets in the geothermal industry worldwide, mainly due to governmental and regulatory support. Turkey is ranked fourth globally with an installed geothermal capacity of over 1,300 MW. Since 2006, we have supplied and in the progress of supplying our state of the art binary equipment to approximately 40 projects in Turkey, which account for over 47% of the total installed geothermal capacity in Turkey as of December 2018. As a major equipment supplier in the Turkish geothermal market we are involved in a number of projects that are currently under construction and plan to continue our marketing efforts to secure new contracts. Our revenue exposure to the Turkish market increased in 2018 and expects to remain significant in 2019, as we signed a number of new contracts in Turkey. The continued deterioration in the Turkish economy, devaluation in the Turkish Lira and increase in local interest rates or a decline in government support for the development of geothermal power in the country could affect local demand for the geothermal equipment and services we provide, collection from our customers or the prices we may charge for such equipment and services. We are monitoring any change in the political and business environments that may affect our future business and operations in the country.
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Ormat established a facility in Turkey in order to locally produce several power plant components that entitle our customer for increased incentives under the renewable energy laws. The use of local equipment in renewable energy based generating facilities in Turkey entitles such facilities to significant benefits under Turkish law, provided such facilities have obtained an RER Certificate from EMRA, which requires the issuance of a local certificate. If we do not obtain the local certificate, then some of our customers under the relevant supply agreements in Turkey may not be issued a RER Certificate based on the equipment we supply to them, and we will be required to make a payment to such customers equal to the amount of the expected lost benefit.
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While the recently enacted Tax Act reduces the corporate tax rate, it is also expected to increase the cost of capital for renewable energy projects. Such projects often rely on "tax equity" as a core financing tool. Tax equity is a form of financing that is repaid partly or wholly in tax benefits and sometimes partly in cash. There are two types of federal income tax benefits on renewable energy projects: a tax credit and depreciation, or the ability to deduct the cost of the project. The reduction in the corporate tax rate from 35 percent to 21 percent reduces the value of the depreciation. Therefore, less tax equity can be raised on projects. The gap in the capital structure must be filled with debt and/or more expensive sponsor equity. The Tax Act allowed the full cost of equipment acquired after September 27, 2017 to be deducted immediately. However, the tax equity market is not expected to be interested in this tax benefit and, in fact, because of the way tax equity works, the Company has had in some tax equity deals to take depreciation on a straight-line basis over 12 years rather than on a front-loaded basis over five years, which leads to some further erosion in the present value of the depreciation. Other effects of the Tax Act were discussed earlier under Note 18 - Income Taxes to our consolidated financial statements.
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 and the sale of BSAAS systems and demand response and energy management services.
Revenues attributable to our Electricity segment are derived from the sale of electricity from our power plants pursuant to long-term PPAs. While approximately 94.8% of our Electricity revenues for the year ended December 31, 2018 were derived from PPAs with fixed price components, we have variable price PPAs in California and Hawaii. Accordingly, our revenues from those power plants may fluctuate.
Our Electricity segment revenues are also subject to seasonal variations, as more fully described in “Seasonality” below.
Our PPAs generally provide for 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 capacity levels and the potential forfeiture of payments if we fail to meet certain minimum target capacity 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. Our more recent PPAs generally provide for energy payments alone with an obligation to compensate the off-taker for its incremental costs as a result of shortfalls in our supply.
Revenues attributable to our Product segment fluctuate between periods, primarily based on our ability to receive customer orders, the status and timing of such orders, delivery of raw materials and the completion of manufacturing. Larger customer orders for our products are typically the result of our sales efforts, our participation in, and winning tenders or requests for proposals issued by potential customers in connection with projects they are developing and orders by returning customers. Such projects often take a significant amount of time to design and develop and are subject to various contingencies, such as the customer’s ability to raise the necessary financing for a project. Consequently, 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, revenues from our Product segment fluctuate (sometimes extensively) from period to period.
Revenues attributable to our Others segment are mainly derived from BSAAS systems, demand response and energy management services and may fluctuate period to period.
Revenues attributable to our demand response and energy management services are derived by two methods. The first method is a fixed monthly or annual recurring fee for managing the customer’s energy assets and monetizing them in either the energy markets or through reducing the customer’s charges from their utility. The second method is through sharing the revenues or savings generated from monetizing their flexible electricity in the energy markets (revenue) or through reducing the customer’s bill from the utility (savings). The second method is subject to energy price fluctuations and the available flexible electricity.
Revenues attributable to our Software as a Service are based on a fixed monthly or annual fee for energy management information and analytical services. Contract periods are typically 12 months or more. To date, we have experienced minimal customer churn.
BSAAS are battery storage deals that are financed, owned and operated by the Company. BSAAS revenues are a combination of sales of the electricity back to the utilities and energy markets based on the prevailing market price for the electricity or for the energy or ancillary services. The energy and ancillary services revenue includes frequency regulation, standby capacity, synchronized reserve, reactive power and other related services. Additionally, when providing a “behind the customer meter solution” we also generate revenue from sharing savings generated from reducing the customer’s utility bill. We also act as a general contractor on turnkey BESS for customers. BESS systems are owned by the customer and we provide the EPC for the project, delivering to the customer a fully operational system. Along with the BESS we also provide the management and operation of the battery for the customer for the life of the system which is typically 10 to 20 years. The EPC portion of the turnkey BESS revenue is a one-time charge and usually will be based on mile-stones or upon delivery.
The following table sets forth a breakdown of our revenues for the years indicated:
Geographic Breakdown of Results of Operations
The following table sets forth the geographic breakdown of the revenues attributable to our Electricity, Product and Other segments for the years indicated:
In 2018, 2017 and 2016, 54%, 57% and 54% of our revenues were derived from international operations, respectively, and our international operations were more profitable than our U.S. operations. A substantial portion of international revenues came from Kenya and Turkey and, to a lesser extent, from Guadeloupe, Guatemala and Honduras and other countries. Our operations in Kenya contributed disproportionately to gross profit and net income. The contribution of our domestic and foreign operations within our Electricity segment and Product segment to combined pre-tax income differ in a number of ways.
Electricity Segment. Our Electricity segment domestic revenues were approximately 60%, 63% and 66% of our total Electricity segment for the years ended December 31, 2018, 2017 and 2016, respectively. However, domestic operations in our Electricity segment have higher costs of revenues and expenses than the foreign operations in our Electricity segment. Our foreign power plants are located in lower-cost regions, like Kenya, Guatemala, Honduras and Guadeloupe, which favorably impact payroll and maintenance expenses among other items. They are also newer than most of our domestic power plants and therefore tend to have lower maintenance costs and higher availability factors than our domestic power plants. Consequently, in 2018 the international operations of the segment accounted for 53% of our total gross profits, 77% of our net income and 53% of our EBITDA.
Product Segment. Our Product segment foreign revenues were 93%, 99% and 92% of our total Product segment revenues for the years ended December 31, 2018, 2017 and 2016, respectively. Our Product segment foreign activity also benefits from lower costs of revenues and expenses than Product segment domestic activity such as labor and transportation costs. Accordingly, our Product segment foreign activity contributes more than our Product segment domestic activity to our pre-tax income from operations.
Seasonality
Electricity generation from some of our geothermal power plants is subject to seasonal variations; in the winter, our power plants produce more energy primarily attributable to the lower ambient temperature, which has a favorable impact on the energy component of our Electricity segment revenues and the prices under many of our contracts are fixed throughout the year with no time-of-use impact. The prices (primarily for capacity) paid for electricity under the PPAs with Southern California Edison and PG&E in California for the Heber 2 power plant in the Heber Complex, the Mammoth Complex and the North Brawley power plant are higher in the months of June through September. The higher payments payable by Southern California Edison and PG&E in the summer months partially offset the negative impact on our revenues from lower generation in the summer attributable to the lower ambient temperature. As a result, we expect the revenues in the winter months to be higher than the revenues in the summer months.
Breakdown of Cost of Revenues
Electricity Segment
The principal cost of revenues attributable to our operating power plants are operation and maintenance expenses comprised of 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, insurance and, for some of our projects, purchases of make-up water for use in our cooling towers and also depreciation and amortization. In our California power plants, our principal cost of revenues also includes transmission charges and scheduling charges. In some of our Nevada power plants we also incur transmission and wheeling charges. 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 power plants from quarter to quarter. Payments made to government agencies and private entities on account of site leases where power 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. Royalties constituted approximately 4.2% and 4.1% of Electricity segment revenues for the years ended December 31, 2018 and December 31, 2017, respectively.
Product Segment
The principal cost of revenues attributable to our Product segment are materials, salaries and related employee benefits, expenses related to subcontracting activities, and transportation expenses. Sales commissions to sales representatives are included in selling and marketing expenses. 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.
Other Segment
The principal cost of revenues attributable to our Other segment are direct costs attributable to providing services and equipment to our Viridity’s customers, direct costs associated with software development and the direct cost of operating batteries that are owned by Viridity. Direct costs include labor costs of our network operations center, the labor costs for engineering and implementation of services to customers, consulting services provided to customers and developing software and the labor associated with operations and maintenance for customer and our Viridity owned energy assets. Cost of revenues attributable to our Other segment also include cost of equipment sold to customers in delivering our automated demand response and software services at a customer’s location, the cost of batteries or other associated equipment that is sold to customers and for any third party related costs such as local construction, local engineering or other similar costs incurred in implementing and managing the customers’ energy assets.
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Our cash and cash equivalents and restricted cash and cash equivalents, increased to $177.5 million as of December 31, 2018, from $96.6 million as of December 31, 2017. This increase was attributable to: (i) $145.8 million derived from operating activities during the year ended December 31, 2018; (ii) $114.7 million of proceeds from a limited and non-recourse loan; (iii) net proceeds of $107.5 million from our revolving credit lines with commercial banks; (iv) $100.0 million of proceeds from a senior unsecured loan; (v) proceeds from sale of limited liability company interest in Tungsten, net of transaction costs of $32.2 million; (vi) restricted cash held by USG at acquisition date of $27.0 million; and (vii) cash received from insurance recoveries of $10.4 million. This increase was partially offset by: (i) our use of $258.5 million to fund capital expenditures; (ii) cash paid for acquisition of controlling interest in USG, net of cash acquired of $95.1 million; (iii) repayment of $62.8 million of long-term debt; (iv) a $26.8 million dividend paid; (v) $13.1 million paid to noncontrolling interest; and (vi) an investment in an unconsolidated company of $3.8 million. As described below in “Liquidity and Capital Resources”, our corporate borrowing capacity under committed lines of credit with different commercial banks as of December 31, 2018 was $468.0 million, as described below in “Liquidity and Capital Resources”. As of December 31, 2018, we had utilized $365.4 million of our corporate borrowing capacity of which $144.9 million was utilized for cash withdrawals and the remainder for other letters of credit.
Critical Accounting Estimates and Assumptions
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 an understanding of our financial position and results of operations. In applying these critical accounting estimates and assumptions, 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 REG 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. 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-based power plant equipment and other equipment on behalf of third parties (product revenues) are recognized using the percentage of completion method, which 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 at least on an annual basis 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 two to three 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. This payment and other related costs 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 will have to write off costs associated with the project that were previously capitalized. For example, during the years ended December 31, 2018 and 2017, we determined that the geothermal resource at one and four of our exploration projects, respectively, would not support commercial operations and as such, we discontinued exploration activities at those sites. As a result of this determination, we expensed $0.1 million and $1.8 million of capitalized costs during the years ended December 31, 2018 and 2017, 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 $71.0 million and $63.9 million at December 31, 2018 and 2017, respectively. Included in these amounts at December 31, 2018 and 2017, respectively, are $ $17.0 million in each year that relate to up-front bonus payments.
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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 and construction-in-process 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 management combined operation generally with one central control room that controls 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 of 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 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 for the year ended December 31, 2018, no impairment exists for any of our 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.
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Goodwill. Goodwill represents the excess of the fair value of consideration transferred in the business combination transactions over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisitions. Goodwill is not amortized but rather subject to a periodic impairment testing on an annual basis (on December 31 of each year) or if an event occurs or circumstances change that would more likely than not reduce the fair value of reporting unit below its carrying amount. Additionally, we are permitted to first assess qualitative factors to determine whether a quantitative goodwill impairment test is necessary. Further testing is only required if the entity determines, based on the qualitative assessment, that it is more likely than not that a reporting unit’s fair value is less than its carrying amount. Otherwise, no further impairment testing is required. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to step one of the quantitative goodwill impairment test. This would not preclude the entity from performing the qualitative assessment in any subsequent period. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. An entity should recognize an impairment charge for the amount by which the carrying amount of the reporting unit exceeds its fair value as calculated under step one described above. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit.
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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. These liabilities 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 either settle the obligation for its recorded amount or 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, a valuation allowance is recorded.
We evaluate our ability to utilize the deferred tax assets quarterly and assess the need for the valuation allowance. In assessing the need for a valuation allowance, we estimate future taxable income, including the impacts of the passing of the recently enacted Tax Act, considering the feasibility of ongoing tax planning strategies and the realization of tax credits and 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. We have recorded a partial valuation allowance related to our U.S. deferred tax assets. In the future, if there is sufficient evidence that we will be able to generate sufficient future taxable income in the U.S., we may be required to reduce this valuation allowance, resulting in income tax benefits in our consolidated statement of operations.
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, which is greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information, we recognize between 0 to 100% of the tax benefit. For those income tax positions where it is not more likely than not that a tax benefit will be sustained, we do not recognize any tax benefit in the consolidated financial statements. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations.
New Accounting Pronouncements
See Note 1 to our consolidated financial statements set forth in Item 8 of this annual report for information regarding new accounting pronouncements.
Results of Operations
Our historical operating results in dollars and as a percentage of total revenues are presented below. A comparison of the different years described below may be of limited utility due to (i) our recent construction or disposition of power plants and enhancement of acquired power plants and (ii) fluctuation in revenues from our Product segment, and (iii) the impact of the lava eruption on our Puna plant in Hawaii.
Results as a percentage of revenues
Comparison of the Year Ended December 31, 2018 and the Year Ended December 31, 2017
Total Revenues
Total revenues for the year ended December 31, 2018 were $719.3 million, compared to $692.8 million for the year ended December 31, 2017, representing a 3.8% increase from the prior period. This increase was attributable to our Electricity segment, in which revenues increased by $44.3 million or 9.5% compared to the corresponding period in 2017, and our Other segment in which revenues increased by $4.9 million or 179.4%, as a result of revenues generated by our Viridity business from the provision of energy storage, demand response and energy management services. This increase was partially offset by a decrease of $22.8 million, or 10.1% in our Product segment revenues compared to the corresponding period in 2017.
Electricity Segment
Revenues attributable to our Electricity segment for the year ended December 31, 2018 were $509.9 million, compared to $465.6 million for the year ended December 31, 2017, representing a 9.5% increase from the prior period. This increase was primarily attributable to: (i) the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017, with revenues of $34.4 million for the year ended December 31, 2018 compared to $10.0 million for the year ended December 31, 2017; (ii) the consolidation of USG which was acquired on April 24, 2018, with revenues of $21.4 million for year ended December 31, 2018. (iii) the commencement of commercial operation of our Tungsten Mountain power plant in Nevada, effective December 2017, with revenues of $15.7 million for the year ended December 31, 2018 compared to $2.2 million for the year ended December 31, 2017; (iv) the commencement of commercial operation of our Plant 1 expansion project in the Olkaria III Complex in Kenya, effective June 2018; and (v) higher energy rates under the new Ormesa 1 PPA commencing in December 2017. The increase was partially offset due to (i) a decrease in revenues at our Puna power plant that was shut down immediately following the Kilauea volcanic eruption on May 3, 2018 and (ii) a decrease in generation at some of our other power plants that were taken offline to address maintenance issues and enhancements, high ambient temperature and curtailments.
Power generation in our power plants increased by 6.7% from 5,489,234 MWh in the year ended December 31, 2017 to 5,857,963 MWh in the year ended December 31, 2018, primarily because of an increase in generation due to the commencement of commercial operations of our Platanares power plant in Honduras, Tungsten Mountain power plant in Nevada, and Plant 1 expansion in Kenya and due to the acquisition of USG. The increase was partially offset by a decrease in generation at (i) our Puna power plant due to the Kilauea Volcanic Eruption and (ii) some of our other power plants mainly due to maintenance issues and high ambient temperature.
Product Segment
Revenues attributable to our Product segment for the year ended December 31, 2018 were $201.7 million, compared to $224.5 million for the year ended December 31, 2017, representing a 10.1% decrease from the prior period. The decrease in our Product segment revenues was attributable to the timing of revenue recognition. We recognized approximately $31.4 million and $23.1 million in revenues, from the New Zealand and China projects, respectively, in the year ended December 31, 2017, compared to $8.8 million and $0.5 million in the year ended December 31, 2018. The projects were completed in 2018. The decrease in our Product segment revenues was also attributable to other projects in Turkey, which were completed in 2017, and by a decrease in revenues as a result of completion of our contracts for geothermal projects in Chile and the Sarulla Project. The decrease was partially offset by the start of new projects in Turkey, which provided $154.3 million in revenue recognized during the year ended December 31, 2018.
Other Segment
Revenues attributable to our Other segment for the year ended December 31, 2018 were $7.6 million compared to $2.7 million for the year ended December 31, 2017. The other segment includes revenues from the provision of energy storage demand response and energy management services by our Viridity business following the acquisition of substantially all of the business and assets of Viridity Energy, Inc. on March 15, 2017.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2018 was $448.8 million, compared to $424.4 million for the year ended December 31, 2017, representing a 5.8% increase from the prior period. This increase was attributable to an increase of $31.4 million, or 11.8%, in cost of revenues from our Electricity segment and an increase of $4.5 million, or 82.1%, in cost of revenues from our Other segment generated by our Viridity business. This increase was partially offset by a 7.5% decrease in our Product segment cost of revenues compared to the corresponding period in 2017. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2018 increased to 62.4%, compared to 61.3% for the year ended December 31, 2017.
Electricity Segment
Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2018 was $298.3 million, compared to $266.8 million for the year ended December 31, 2017, representing a 11.8% increase from the prior period. This increase was primarily attributable to additional cost of revenues from the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017, our Tungsten Mountain power plant in Nevada, effective December 2017 and commencement of commercial operation of our Plant 1 expansion project in the Olkaria III Complex in Kenya, effective June 2018, (ii) approximately $8.0 million higher costs compared to the same period 2017 related to pump failures that we had to replace in some of our power plants and (iii) the consolidation of USG which we acquired on April 24, 2018. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2018 was 58.5%, compared to 57.3% for the year ended December 31, 2017. The cost of revenues attributable to our international power plants was 24.7% of our Electricity segment cost of revenues.
Product Segment
Total cost of revenues attributable to our Product segment for the year ended December 31, 2018 was $140.7 million, compared to $152.1 million for the year ended December 31, 2017, representing a 7.5% decrease from the prior period. This decrease was primarily attributable to decrease in Product segment revenues, as discussed above. As a percentage of total Product segment revenues, for the year ended December 31, 2018 was 69.7%, compared to 67.8% for the year ended December 31, 2017. This increase was primarily attributable to the higher competition, different product scope and different margins in the various sales contracts we entered into for the Product segment during these periods.
Other Segment
Cost of revenues attributable to our Other segment for the year ended December 31, 2018 were $9.9 million as compared to $5.4 million in the year ended December 31, 2017. The Other segment includes cost of revenues related to the provision of energy storage, demand response and energy management services by our Viridity business.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2018 were $4.2 million, compared to $3.2 million for the year ended December 31, 2017.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2018 were $19.8 million, compared to $15.6 million for the year ended December 31, 2017. This increase was primarily due to the $5.0 million termination fee paid to NV Energy related to the termination of the Galena 2 PPA. The increase was partially offset as a result of lower sales commissions related to our Product segment due to lower revenues and lower commissions due to the nature of the contracts. Selling and marketing expenses for the year ended December 31, 2018 excluding the termination fee constituted 2.1% of total revenues for such year, compared to 2.3% for the year ended December 31, 2017.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2018 were $47.8 million, compared to $42.9 million for the year ended December 31, 2017.
This increase was primarily attributable to (i) general and administrative expenses resulting from first time inclusion of USG, (ii) general and administrative expenses from our Viridity business which we acquired on March 15, 2017; and (iii) an increase in costs associated with our identification of a material weakness related to taxes in the fourth quarter of 2017 and the additional work and controls to compensate for such material weakness as well as the restatement of second, third and fourth quarter financial statements and its full-year 2017 financial statements and related expenses. The increase was partially offset due to a $10.3 million adjustment in respect of an earn out related to the acquisition of our Viridity business. General and administrative expenses for the year ended December 31, 2017 included $2.1 million charge for stock-based compensation expense associated with the acceleration of the vesting period of the stock options previously held by our CEO and CFO and exercised in connection with ORIX’s acquisition of 22% of the Company.
Goodwill Impairment Charge
Goodwill impairment charge for the year ended December 31, 2018 was $13.5 million related to the acquisition of our Viridity business. There was no goodwill impairment charge for the year ended December 31, 2017.
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year ended December 31, 2018 was $0.1 million compared to $1.8 million for the year ended December 31, 2017. The write-off of unsuccessful exploration activities for the year ended December 31, 2017, included costs related to the Glass Buttes site in Oregon, which we determined in the fourth quarter of 2017, would not support commercial operations.
Operating Income
Operating income for the year ended December 31, 2018 was $185.1 million, compared to $205.0 million for the year ended December 31, 2017, representing a 9.7% decrease from the prior period. The decrease in operating income was primarily attributable to the $13.5 million goodwill impairment charge, the decrease in our Product segment gross margin, the $5.0 million termination fee of the Galena 2 PPA, and the increase in general and administrative expenses, as discussed above. The decrease was partially offset by an increase in our gross margin in our Electricity segment, also discussed above. Operating income attributable to our Electricity segment for the year ended December 31, 2018 was $155.5 million, compared to $157.6 million for the year ended December 31, 2017. Operating income attributable to our Product segment for the year ended December 31, 2018 was $38.1 million, compared to $50.5 million for the year ended December 31, 2017. Operating loss attributable to our Other segment for the year ended December 31, 2018 was $8.5 million compared to a loss of $3.1 million for the year ended December 31, 2017.
Interest Expense, Net
Interest expense, net, for the year ended December 31, 2018 was $70.9 million, compared to $54.1 million for the year ended December 31, 2017, representing a 31.0% increase from the prior period. This increase was primarily due to: (i) $100.0 million of proceeds from a senior unsecured loan received on March 22, 2018; (ii) net increase in our revolving credit lines with commercial banks; and (iii) a $3.5 million increase related to a decrease in interest capitalized to projects; (iv) additional debt as part of the acquisition of USG, and (v) $4.3 million increase in interest related to the sale of tax benefits; and (vi) $114.7 million of proceeds from a limited recourse loan received on October 29, 2018 from OPIC for financing the Honduras power plant, offset partially due to lower interest expense as a result of principal payments of long term debt.
Derivatives and Foreign Currency Transaction Gains (Losses)
Derivatives and foreign currency transaction losses for the year ended December 31, 2018 were $4.8 million, compared to gains of $2.7 million for the year ended December 31, 2017. Derivatives and foreign currency transaction losses for the year ended December 31, 2018 were attributable primarily to losses from foreign currency forward contracts, which were not accounted for as hedge transactions. Derivatives and foreign currency transaction gains for the year ended December 31, 2017 were primarily attributable to gains from foreign currency forward contracts, which were not accounted for as hedge transactions.
Income Attributable to Sale of Tax Benefits
Tax equity is a form of financing used for renewable energy projects. In such financings, the Company may realize income when the financing is put in place or over time as a consequence of how the financing is structured. Income attributable to such financings (as described below under “Opal Transaction”, “Tungsten Transaction”) for the year ended December 31, 2018 was $19.0 million, compared to $17.9 million for the year ended December 31, 2017. This income primarily represents the value of PTCs and taxable income or loss generated by Opal Geo and Tungsten allocated to the investor in the year ended December 31, 2018 compared to the value of PTCs and taxable income or loss generated by Opal Geo allocated to the investors in the year ended December 31, 2017.
Other Non-Operating Income (Expense), Net
Other non-operating income, net for the year ended December 31, 2018 was $7.8 million, compared to Other non-operating expense, net of $1.7 million for the year ended December 31, 2017. Other non-operating income, net for the year ended December 31, 2018 includes an income of $7.2 million insurance settlement of our Puna power plant rig which was damaged by the Kilauea volcanic eruption. Other non-operating expense, net for the year ended December 31, 2017 includes a make whole premium of $1.9 million resulting from the prepayment of $14.3 million aggregate principal amount of our OFC Senior Secured Notes and $11.8 million aggregate principal amount of our DEG Loan.
Income from operations, before income taxes and equity in losses of investees
Income from operations, before income taxes and equity in losses of investees for the year ended December 31, 2018 was $137.2 million, compared to $170.7 million for the year ended December 31, 2017, representing a 19.7% decrease from the prior period. The income is primarily attributable to our foreign operations. This decrease was driven by the decrease in our domestic operations resulting mainly from the goodwill impairment charge relating to our Viridity business, the $5.0 million termination fee of the Galena 2 PPA, and the increase in general and administrative expenses, partially offset by an income of $7.2 million insurance settlement of our Puna power plant rig in the year ended December 31, 2018, as described above.
Income Taxes
Income tax provision for the year ended December 31, 2018, was $34.7 million, an increase of $13.0 million compared to an income tax provision of $21.7 million for the year ended December 31, 2017. The increase in income tax provision primarily resulted from the tax on global intangible low-tax income (“GILTI”), partially offset by a decrease in withholding tax on distribution of earnings, and the exclusion of other impacts of U.S. federal tax reform that resulted in a one-time tax impact for the year ended December 31, 2017. Our effective tax rate for the years ended December 31, 2018 and 2017, was 25.3% and 12.7%, respectively. Our effective tax rate at December 31, 2018 is principally based upon the composition of the income in different countries, tax on GILTI, accounting for intra-entity transfers of assets other than inventory, and changes related to valuation allowances. Our aggregate effective tax rate is higher than the 21% U.S federal statutory tax rate due to: (i) the impact of the newly enacted GILTI; (ii) higher tax rate in Kenya of 37.5% and Guadeloupe of 33.33% partially offset by a lower tax rate in Israel of 16 %; and (iii) withholding taxes on future distributions (see Note 18 - Income Taxes to the consolidated financial statements set forth in Item 8 of this annual report for further details regarding the Company's income tax provision and the Tax Act).
For the years ended December 31, 2018 and 2017, we recorded a valuation allowance in the amount of approximately $22.4 million and $77.6 million, respectively, against our unutilized tax credits (FTCs and PTCs) and U.S. deferred tax assets related to state net operating loss (NOL) carryforwards. As of December 31, 2018, we had U.S. federal NOLs in the amount of approximately $230.5 million, state NOLs in the amount of approximately $269.1 million, and unutilized federal tax credits of approximately $149.0 million, some of which can be carried forward for 10-20 years. In addition, we had unutilized state tax credits of approximately 0.8 million, which can be carried forward for indefinite period. The related deferred tax assets totaled approximately $192.4 million after valuation allowance. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income in the U.S. prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income, estimated impacts of tax reform and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of $22.4 million was recorded against the U.S. deferred tax assets as of December 31, 2018 because we believe it is more likely than not that the deferred tax assets will not be realized. If sufficient additional evidence of our ability to generate taxable income is established, we may be required to reduce or fully release the valuation allowance, resulting in income tax benefits in our consolidated statement of operations.
On December 22, 2017, the U.S. government signed into law the Tax Act. The Tax Act makes significant changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate income tax rate from 35 percent to 21 percent; (2) the transition of U.S. international taxation from a worldwide tax system to a territorial system (GILTI, BEAT, Dividends Received Deduction); (3) one-time transition tax on undistributed earnings of foreign subsidiaries as of December 31, 2017; (4) eliminating the corporate alternative minimum tax (5) creating a new limitation on deductible interest expense; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017.
The Company applied the guidance of SAB 118 for the effects of the Tax Act in 2017 and throughout 2018. The Deemed Repatriation Tax (“Transition Tax”) is a tax on previously untaxed accumulated and current earnings and profits (E&P) of certain foreign subsidiaries. To determine the amount of the Transition Tax, we determined, in addition to other factors, the amount of post-1986 E&P of the relevant subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. As a result of our initial analysis of the impact of the Act, we recorded a provisional amount of $71.6 million (gross) with respect to the inclusion of the transition tax at December 31, 2017. In addition, at December 31, 2017, the Company recorded a provisional benefit of $22.6 million relating to the remeasurement of deferred taxes from 35% to 21%.
As of December 31, 2018, we have completed our accounting for the tax effects of the Tax Reform Act. . Subsequent adjustments to these amounts resulted in a reduction of $7.8 million the inclusion to the transition tax and a decreased tax benefit of $3.5 million to the remeasurement of deferred taxes.
Under the Tax Act, the deductibility of “net interest” for a business is limited to 30% of adjusted taxable income. The new proposed regulations issued by Treasury applies regardless of whether the interest payment is made to a US or foreign person, whether the interest recipient is related, or whether the interest recipient is exempt from US tax. Further, any interest that cannot be deducted in a year can be carried forward indefinitely. The Company has not early adopted these proposed regulations and intends to adopt during the 2019 tax year. For the year ended December 31, 2018, we have evaluated the impact and determined there is no limit on our interest deductibility for federal income tax purposes for the current period, but anticipates there could be significant limitations upon adoption.
The Company is also required to elect to either treat taxes due on future GILTI inclusions in U.S. taxable income as a current period expense when incurred or reflect such portion of the future GILTI inclusions in U.S. taxable income that relate to existing basis differences in the Company’s current measurement of deferred taxes. The Company has elected to treat the taxes due on future U.S. inclusions in taxable income under GILTI as a period cost when incurred. The Company has elected and applied the tax law ordering approach when considering GILTI as part of the Company’s valuation allowance.
We continue to monitor the impact of any additional guidance issued by Treasury. Notwithstanding the reduction in the corporate income tax rate, the overall impact of the Tax Act is uncertain, and our business, financial condition, future results and cash flow, as well as our stock price, could be adversely affected.
Equity in Earnings (losses) of investees, net
Equity in earnings (losses) of investees, net in the year ended December 31, 2018 was a profit of $7.7 million, compared to a loss of $2.0 million in the year ended December 31, 2017. Equity in earnings (losses) of investees, net derived from our 12.75% share in the earnings (losses) of the Sarulla project and from profits elimination. The increase was mainly attributable to utilization of carryforward losses and full year of commercial operations of SIL and NIL 1 and commercial operation of NIL 2 from May 2018.
Net Income
Net income for the year ended December 31, 2018 was $110.1 million, compared to $147.1 million for the year ended December 31, 2017, representing a decrease of $37.0 million from the prior period. This decrease in net income was primarily attributable to a decrease in operating income of $19.9 million, an increase of $16.8 million in interest expense, net and a decrease of $7.4 million in derivatives and foreign currency transaction gains and $13.1 million increase in income tax provision, partially offset due to an increase in Other non-operating income, net of $9.4 million, and an increase in equity in earnings of investees, net of $9.6 million, all as discussed above.
Net Income attributable to the Company’s Stockholders
Net income attributable to the Company’s stockholders for the year ended December 31, 2018 was $98.0 million, compared to $132.4 million for the year ended December 31, 2017, which represents a decrease of $34.4 million. This decrease was attributable to the decrease in net income of $37.0 million, offset partially by a decrease of $2.6 million in net income attributable to noncontrolling interest mainly due to the shutdown of the Puna power plant in Hawaii, all as discussed above.
Comparison of the Year Ended December 31, 2017 and the Year Ended December 31, 2016
Total Revenues
Total revenues for the year ended December 31, 2017 were $692.8 million, compared to $662.6 million for the year ended December 31, 2016, representing a 4.6% increase from the prior period. This increase was attributable to our Electricity segment, in which revenues increased by 7.3% compared to the corresponding period in 2016.
Electricity Segment
Revenues attributable to our Electricity segment for the year ended December 31, 2017, were $465.6 million, compared to $436.3 million for the year ended December 31, 2016, representing a 6.7% increase from the prior period. This increase was primarily attributable to: (i) the full year consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, with revenues of $21.7 million for the year ended December 31, 2017, compared to $8.1 million for the year ended December 31, 2016; (ii) the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017, with revenues of $10.0 million for the year ended December 31, 2017 and of our Tungsten Mountain power plant in Nevada, effective December 2017, with revenues of $2.2 million for the year ended December 31, 2017 and ; (iii) an increase in generation at our Puna power plant attributable to successful improvement of the resource performance. The increase was partially offset by a decrease in generation at some of our power plants that we had scheduled to take offline to address maintenance issues.
Power generation in our power plants increased by 1.7% from 5,396,959 MWh in the year ended December 31, 2016 to 5,489,234 MWh in the year ended December 31, 2017, primarily because of an increase in generation at our Puna power plant, the consolidation of our Bouillante power plant in Guadeloupe, and the commencement of operations of our Platanares power plant in Honduras and Tungsten Mountain power plant in Nevada, partially offset by a decrease in generation in some of our power plants mainly due to scheduled outages.
Product Segment
Revenues attributable to our Product segment for the year ended December 31, 2017 were $224.5 million, compared to $226.3 million for the year ended December 31, 2016, representing a 0.8% decrease from the prior period. The slight decrease in our Product segment revenues was primarily attributable to completion or near-completion of our contracts for the Cerro Pabellon geothermal power plant in Chile, the Sarulla geothermal power plant in Indonesia, and other projects in Turkey, which were completed during 2016. This decrease was partially offset by revenue recognized from two new geothermal projects in New Zealand and China (on which we started construction in the first quarter of 2017) and new projects in Turkey in the amounts of $31.7 million, $23.1 million and $121.3 million, respectively.
Other Segment
Revenues attributable to our Other segment for the year ended December 31, 2017 were $2.7 million. The other segment includes revenues from the provision of energy storage demand response and energy management services by our Viridity business following the acquisition of substantially all of the business and assets of Viridity Energy, Inc. on March 15, 2017.
Total Cost of Revenues
Total cost of revenues for the year ended December 31, 2017 was $424.4 million, compared to $391.8 million for the year ended December 31, 2016, representing an 8.3% increase from the prior period. This increase was attributable to an increase of $5.3 million, or 2.0%, in cost of revenues from our Electricity segment and an increase of $21.9 million, or 16.8% from our Product segments. As a percentage of total revenues, our total cost of revenues for the year ended December 31, 2017 increased to 61.3%, compared to 59.1% for the year ended December 31, 2016. This increase was mainly attributable to an increase in cost of revenues as a percentage of total revenues in our Product segment.
Electricity Segment
Total cost of revenues attributable to our Electricity segment for the year ended December 31, 2017 was $266.8 million, compared to $261.6 million for the year ended December 31, 2016, representing a 2.0% increase from the prior period. This increase was primarily attributable to additional cost of revenues from the consolidation of our Bouillante power plant in Guadeloupe, effective July 5, 2016, the commencement of commercial operation of our Platanares power plant in Honduras, effective September 2017. As a percentage of total Electricity segment revenues, the total cost of revenues attributable to our Electricity segment for the year ended December 31, 2017 was 57.3%, compared to 60.0% for the year ended December 31, 2016. This decrease was primarily attributable to higher efficiency in some of our operating power plants.
Product Segment
Total cost of revenues attributable to our Product segment for the year ended December 31, 2017 was $152.1 million, compared to $130.2 million for the year ended December 31, 2016, representing a 16.8% increase from the prior period. This increase was primarily attributable to additional costs associated with our project in Chile, as well as a different product mix and different margins in the various sales contracts we entered into for the Product segment during these periods. As a percentage of total Product segment revenues, our total cost of revenues attributable to the Product segment for the year ended December 31, 2017 was 67.8%, compared to 57.5% for the year ended December 31, 2016.
Other Segment
Cost of revenues attributable to our Other segment for the year ended December 31, 2018 were $5.4 million in the year ended December 31, 2017. The Other segment includes cost of revenues related to the provision of energy storage, demand response and energy management services by our Viridity business.
Research and Development Expenses
Research and development expenses for the year ended December 31, 2017 were $3.2 million, compared to $2.8 million for the year ended December 31, 2016.
Selling and Marketing Expenses
Selling and marketing expenses for the year ended December 31, 2017 were $15.6 million, compared to $16.4 million for the year ended December 31, 2016. This decrease was primarily due to lower sales commissions related to our Product segment because of a different commission mix. Selling and marketing expenses for the year ended December 31, 2017 constituted 2.3% of total revenues for such year, compared to 2.5% of such revenues for the year ended December 31, 2016.
General and Administrative Expenses
General and administrative expenses for the year ended December 31, 2017 were $42.9 million, compared to $46.7 million for the year ended December 31, 2016. This decrease was mainly due to (i) $11.0 million of expenses in the year ended December 31, 2016 related to the settlement of a qui tam claim and (ii) a $2.1 million adjustment in respect of an earn out related to the acquisition of our Viridity business, partially offset by (i) a $2.1 million charge for stock-based compensation expense associated with the acceleration of the vesting period of the stock options previously held by our CEO and CFO and exercised in connection with ORIX’s acquisition of approximately 22% of our shares of common stock; (ii) general and administrative expenses related to our Viridity business; and (iii) $2.5 million in costs associated with the ORIX transaction and other acquisitions and sales activities in the year ended December 31, 2017. General and administrative expenses for the year ended December 31, 2017, excluding the one-time charge of $2.1 million for stock-based compensation, constituted 5.9% of total revenues for the year ended December 31, 2017, compared to 5.5%, excluding the one-time charge of $11.0 million related to the settlement mentioned above, of total revenues for the year ended December 31, 2016.
Write-off of Unsuccessful Exploration Activities
Write-off of unsuccessful exploration activities for the year ended December 31, 2017 was $1.8 million, compared to $3.0 million for the year ended December 31, 2016. The write-off of unsuccessful exploration activities for the year ended December 31, 2017 included costs related to the Glass Buttes site in Oregon, which we determined in the fourth quarter of 2017 would not support commercial operations. The majority of the write-off of unsuccessful exploration activities for the year ended December 31, 2016 consisted of costs related to the Twilight site in Oregon and a concession in Chile, which we determined would not support commercial operations.
Operating Income
Operating income for the year ended December 31, 2017 was $205.0 million, compared to $201.9 million for the year ended December 31, 2016, representing a 1.6% increase from the prior period. The increase in operating income was primarily attributable to the increase in our gross margin in our Electricity segment primarily as a result of the increase in revenues and higher efficiency in some of our operating power plants, and the decrease in general and administrative expenses, as discussed above. The increase was partially offset by a decrease in our gross margin in our Product segment, also discussed above. Operating income attributable to our Electricity segment for the year ended December 31, 2017 was $157.6 million, compared to $126.8 million for the year ended December 31, 2016. Operating income attributable to our Product segment for the year ended December 31, 2017 was $50.5 million, compared to $75.1 million for the year ended December 31, 2016. Operating loss attributable to our Other segment for the year ended December 31, 2017 was $3.1 million for the year ended December 31, 2017.
Interest Expense, Net
Interest expense, net, for the year ended December 31, 2017 was $54.1 million, compared to $67.4 million for the year ended December 31, 2016, representing a 19.7% decrease from the prior period. This decrease was primarily due to: (i) the repayment, in September 2016, of $250 million of our senior unsecured bonds which bore interest at a fixed rate of 7% per annum, through the issuance of $67 million and $137 million, respectively of two new series of senior unsecured bonds, which bear interest at a fixed rate of 3.7% and 4.45% per annum, respectively, as discussed below; (ii) lower interest expense as a result of principal payments of long term debt and revolving credit lines with banks; and (iii) a $3.9 million decrease related to an increase in interest capitalized to projects, partially offset by the December 2016 issuance of senior secured notes issued by our subsidiary that owns phase 1 of the Don A. Campbell power plant.
Derivatives and Foreign Currency Transaction Losses
Derivatives and foreign currency transaction gains for the year ended December 31, 2017 were $2.7 million, compared to losses of $5.5 million for the year ended December 31, 2016. Derivatives and foreign currency transaction gains for the year ended December 31, 2017 were attributable primarily to gains from foreign currency forward contracts, which were not accounted for as hedge transactions. Derivatives and foreign currency transaction losses for the year ended December 31, 2016 were primarily attributable to $2.6 million in losses from future contracts entered into to reduce our economic exposure to fluctuations in prices of natural gas and oil under our SO#4 and Puna PPAs, which were not accounted for as hedge transactions, and $1.5 million in losses due to changes in the fair value of the contract obligation in relating to the acquisition of our interest in the Bouillante power plant in Guadeloupe.
Income Attributable to Sale of Tax Benefits
Income attributable to the sale of tax benefits to institutional equity investors (as described in our financial statements below under “OPC Transaction”, “ORTP Transaction” and “Opal Geo Transaction”) for the year ended December 31, 2017 was $17.9 million, compared to $16.5 million for the year ended December 31, 2016. This income primarily represents the value of PTCs and taxable income or loss generated by Opal Geo and ORTP and allocated to investors in the year ended December 31, 2017 compared to PTCs and taxable income or loss generated by ORTP and OPC and allocated to investors in the year ended December 31, 2016.
Other Non-Operating Income (loss)
Other non-operating expense, net for the year ended December 31, 2017 was $1.7 million, compared to $5.4 million for the year ended December 31, 2016. Other non-operating expense, net for the year ended December 31, 2017 includes a make whole premium of $1.9 million resulting from the prepayment of $14.3 million aggregate principal amount of our OFC Senior Secured Notes and $11.8 million aggregate principal amount of our DEG Loan (as described below). Other non-operating expense, net for the year ended December 31, 2016 includes: (i) prepayment fees of approximately $5.0 million due to the repayment of our senior unsecured bonds in September 2016 and (ii) a make whole premium of $0.6 million resulting from the repurchase of $6.8 million aggregate principal amount of our OFC Senior Secured Notes.
Income from operations, before income taxes and equity in losses of investees
Income from operations, before income taxes and equity in losses of investees for the year ended December 31, 2017 was $170.7 million, compared to $141.1 million for the year ended December 31, 2016, representing a 21.0% increase from the prior period. The income is primarily attributable to our foreign operations. This increase was driven by the increase in our domestic operations resulting mainly from the $11.0 million one-time expense in the year ended December 31, 2016 related to the settlement of a qui tam claim, approximately $5.0 million due to the repayment of the senior unsecured bonds in September 2016 and the associated decrease in interest expense, as described above.
Income Taxes
Income tax provision for the year ended December 31, 2017, was $21.7 million, a decrease of $15.4 million compared to an income tax provision of $37.1 million for the year ended December 31, 2016. The decrease in income tax provision primarily resulted from the changes in valuation allowance and the impact of the U.S. tax reform legislation and partially offset by increase in income before taxes in jurisdictions outside of the U.S. and withholding tax on distribution of earnings. Our effective tax rate for the years ended December 31, 2017 and 2016, was 12.7% and 26.3%, respectively. Our effective tax rate at December 31, 2017 is principally based upon the composition of the income in different countries, the impact of U.S. tax reform legislation and changes related to valuation allowances. Our aggregate effective tax rate is lower than the 35% U.S federal statutory tax rate due to: (i) as a substantial portion of our income is derived in Israel which is taxed at the corporate tax rate of 16%, partially offset by taxes on earnings in Kenya which are taxed at statutory rate of 37.5%; (ii) a tax credit and tax exemption related to the Company’s subsidiaries in Guatemala and Honduras; (iii) a partial valuation allowance release against the Company’s U.S. deferred tax assets offset by withholding taxes; and (iv) impacts of U.S. tax reform legislation, specifically the remeasurement of deferred taxes and the inclusion in taxable income of the amount on certain repatriated earnings of foreign subsidiaries (see Note 18- Income Taxes to the consolidated financial statements set forth in Item 8 of this annual report for further details regarding the Company's income tax provision and the Tax Act).
For the years ended December 31, 2017 and 2016, we recorded a valuation allowance in the amount of approximately $77.6 million and $116.2 million, respectively, against our unutilized tax credits (FTCs, PTCs and ITCs) and U.S. deferred tax assets related to net operating loss (NOL) carryforwards. As of December 31, 2017, we had U.S. federal NOLs in the amount of approximately $207.2 million, state NOLs in the amount of approximately $238.6 million, and unutilized tax credits of approximately $172.2 million, all of which can be carried forward for 10-20 years. The related deferred tax assets totaled approximately $135.0 million. Realization of these deferred tax assets and tax credits is dependent on generating sufficient taxable income in the U.S. prior to expiration of the NOL carryforwards and tax credits. The scheduled reversal of deferred tax liabilities, projected future taxable income, estimated impacts of tax reform and tax planning strategies were considered in determining the amount of valuation allowance. A valuation allowance in the amount of $77.6 million was recorded against the U.S. deferred tax assets as of December 31, 2017 because we believe it is more likely than not that the deferred tax assets will not be realized. If sufficient additional evidence of our ability to generate taxable income is established, we may be required to reduce or fully release the valuation allowance, resulting in income tax benefits in our consolidated statement of operations.
Equity in losses of investees, net
Equity in losses of investees, net in the year ended December 31, 2017 was $2.0 million, compared to $7.7 million in the year ended December 31, 2016. Equity in losses of investees, net derived from our 12.75% share in the losses of the Sarulla project and from profits elimination.
Net Income
Net income for the year ended December 31, 2017 was $147.1 million, compared to $96.3 million for the year ended December 31, 2016, representing an increase of $50.8 million from the prior period. This increase in net income was primarily attributable to $11.0 million in one-time general and administrative expenses in the year ended December 31, 2016 related to the settlement of a qui tam claim, a decrease in interest expense of $13.2 million and a decrease in income taxes of $15.4 million, each as discussed above.
Liquidity and Capital Resources
Our principal sources of liquidity have been derived from cash flows from operations, proceeds from third party debt such as borrowings under our credit facilities, private offerings and issuances of debt securities, project financing and tax monetization transactions, short term borrowing under our lines of credit, and proceeds from the sale of equity interests in one or more of our projects. We have utilized this cash to develop and construct power plants, fund our acquisitions, pay down existing outstanding indebtedness, and meet our other cash and liquidity needs.
As of December 31, 2018, we had access to: (i) $98.8 million in cash and cash equivalents, of which $67.9 million was held by our foreign subsidiaries; and (ii) $78.8 million of unused corporate borrowing capacity under existing lines of credit with different commercial banks.
Our estimated capital needs for 2019 include approximately $250.0 million for capital expenditures on new projects under development or construction including storage projects, exploration activity and maintenance capital expenditures for our existing projects, as well as $68.2 million for debt repayment.
As of December 31, 2018, $229.6 million in the aggregate was outstanding under credit agreements with several banks as detailed below under “Credit Agreements”.
We expect to finance these requirements with the sources of liquidity described above. Management believes that, based on the current stage of implementation of our strategic plan, the sources of liquidity and capital resources described above will address our anticipated liquidity, capital expenditures, and other investment requirements.
Although we plan to repatriate undistributed earnings related to Ormat Systems to support expected capital expenditure requirements in the U.S., based upon our plans to increase operations outside of the U.S. it is our intention to reinvest undistributed earnings of its other foreign subsidiaries and thereby indefinitely postpone their remittance given that we require existing and future cash to fund our anticipated investment and development activities as well as debt service requirements in those jurisdictions. In addition, we believe that existing and anticipated cash flows as well as borrowing capacity in the U.S. and cash to be remitted to the U.S. from Ormat Systems will be sufficient to meet our needs in the U.S. If plans change, we may be required to accrue and pay withholding taxes as part of repatriating these funds.
Third-Party Debt
Our third-party debt consists of (i) non-recourse and limited-recourse project finance debt or acquisition financing that we or our subsidiaries have obtained for the purpose of developing and constructing, refinancing or acquiring our various projects and (ii) full-recourse debt incurred by us or our subsidiaries for general corporate purposes.
Non-Recourse and Limited-Recourse Third-Party Debt
Full-Recourse Third-Party Debt
Letters of Credits under the Credit Agreements
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.
Credit Agreements
Restrictive covenants
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 term 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, which are measured quarterly, such as: (i) equity of at least $600 million and in no event less than 25% of total assets; (ii) 12-month debt, net of cash, cash equivalents, and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6.0; and (iii) dividend distributions not to exceed 35% of net income in any calendar year. As of December 31, 2018: (i) total equity was $1,445.1 million and the actual equity to total assets ratio was 46.3% and (ii) the 12-month debt, net of cash, cash equivalents, to Adjusted EBITDA ratio was 3.21. During the year ended December 31, 2018, we distributed interim dividends in an aggregate amount of $26.8 million. 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.
As described above, 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 operations.
Future minimum payments
Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks and lease payments under the Puna lease transaction described below, as of December 31, 2018, are as follows:
Puna Power Plant Lease Transactions
In May 2005, our Hawaiian subsidiary, PGV, entered into a transaction involving the original geothermal power plant of the Puna Complex located on the Big Island (the Puna Power Plant).
Pursuant to a 31-year head lease (the Head Lease), PGV leased the Puna Power Plant to an unrelated lessor (the Puna lessor) in return for prepaid lease payments in the total amount of $83.0 million. The carrying value of the leased assets as of December 31, 2018 amounted to $19.7 million, net of accumulated depreciation of $33.1 million. The Puna 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 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 Puna Lessor as part of the Head Lease but are part of the Puna Lessor’s security package.
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 the 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.
There are various restrictive covenants under the lease agreement, including a requirement to have certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $1.3 million and $7.9 million as of December 31, 2018 and December 31, 2017, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.
Opal Geo Transaction
On December 16, 2016, Ormat Nevada entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM with respect to Opal Geo. Also on December 16, 2016, OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize PTCs and certain other tax benefits relating to the operation of five geothermal power plants located in Nevada.
Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the Don A. Campbell 2 and McGinness Hills Phase II power plants which are eligible for the federal PTC. We expect the aggregate amount of JPM’s deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.
JPM’s $62.1 million capital contribution to Opal Geo was recorded as a $3.7 million allocation to noncontrolling interests and a $58.5 million allocation to Liabilities associated with sale of tax benefits as described in Note 1 to our consolidated financial statements set forth in Item 8 of this annual report.
Further details on the Opal Geo Transaction are provided under Note 13 of our Financial Statements.
Liquidity Impact of Uncertain Tax Positions
As discussed in Note 18 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 $11.8 million as of December 31, 2018. 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.
Dividends
The following are the dividends declared by us 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, 2018
Net cash provided by operating activities for the year ended December 31, 2018 was $145.8 million, compared to $245.6 million for the year ended December 31, 2017. This decrease of $99.8 million resulted primarily from a decrease in accounts payable and accrued expenses of $56.7 million in the year ended December 31, 2018, compared to an increase of $51.6 million in the year ended December 31, 2017, mainly due to a withholding tax payment of approximately $44 million due to a distribution from OSL as a result of the change in our assertion on unrepatriated earnings of OSL to the U.S., in the second quarter of 2017, as discussed above, offset partially by approximately $14 million due to a distribution from OSL in 2018. The decrease was also due to timing of payments to our suppliers.
Net cash used in investing activities for the year ended December 31, 2018 was $342.4 million, compared to $345.5 million for the year ended December 31, 2017. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2018 were: (i) capital expenditures of $258.5 million, primarily for our facilities under construction; (ii) cash paid for acquisition of controlling interest in USG, net of cash acquired of $95.1 million; (iii) and an investment in an unconsolidated company of $3.8 million.
Net cash provided by financing activities for the year ended December 31, 2018 was $251.1 million, compared to $67.9 million used for the year ended December 31, 2017. The principal factors that affected the net cash provided by financing activities during the year ended December 31, 2018 were: (i) $100.0 million of proceeds from a senior unsecured loan, (ii) $114.7 million of proceeds from a limited and non-recourse loan; (iii) net proceeds of $107.5 million from our revolving credit lines with commercial banks which were used for capital expenditures, and (iv) proceeds from the sale of a limited liability company interest in Tungsten, net of transaction costs of $32.2 million, partially offset by: (i) the repayment of long-term debt in the amount of $62.8 million; (ii) a $26.8 million cash dividend paid; and (iii) $13.1 million of cash paid to noncontrolling interests.
For the Year Ended December 31, 2017
Net cash provided by operating activities for the year ended December 31, 2017 was $245.6 million, compared to $159.3 million for the year ended December 31, 2016. This increase of $86.3 million resulted primarily from (i) an increase in receivables of $24.0 million in the year ended December 31, 2017, compared to $33.3 million in the year ended December 31, 2016, as a result of timing of collections from our customers; and (ii) a decrease of $0.1 million in billing in excess of costs and estimated earnings on uncompleted contracts, net in our Product segment in the year ended December 31, 2017, compared to $29.3 million in the year ended December 31, 2016, as a result of timing in billing of our customers; and (iii) an increase in accounts payable and accrued expenses of $51.6 million in the year ended December 31, 2017, compared to a decrease of $1.4 million in the year ended December 31, 2016, as a result of timing of payments to our suppliers.
Net cash used in investing activities for the year ended December 31, 2017 was $345.5 million, compared to $173.8 million for the year ended December 31, 2016. The principal factors that affected our net cash used in investing activities during the year ended December 31, 2017 were: (i) capital expenditures of $259.2 million, primarily for our facilities under construction; (ii) $35.3 million net cash paid for the acquisition of our Viridity business; and (iii) an investment in an unconsolidated company of $46.3 million.
Net cash used in financing activities for the year ended December 31, 2017 was $67.9 million, compared to $43.5 million provided by for the year ended December 31, 2016. The principal factors that affected the net cash used in financing activities during the year ended December 31, 2017 were: (i) the repayment of long-term debt in the amount of $66.2 million; (ii) a $20.5 million cash dividend paid; (iii) $21.3 million of cash paid to noncontrolling interests; and (iv) $14.3 million of cash paid to repurchase our OFC Senior Secured Notes, partially offset by a net increase of $51.5 million against our revolving lines of credit with commercial banks.
EBITDA and Adjusted EBITDA
We calculate EBITDA as net income before interest, taxes, depreciation and amortization. We calculate Adjusted EBITDA as net income before interest, taxes, depreciation and amortization, adjusted for (i) termination fees, (ii) impairment of long-lived assets, (iii) write-off of unsuccessful exploration activities, (iv) any mark-to-market gains or losses from accounting for derivatives, (v) merger and acquisition transaction costs, (vi) stock-based compensation, (vii) gain or loss from extinguishment of liabilities, (viii) gain or loss on sale of subsidiary and property, plant and equipment and (ix) other unusual or non-recurring items. EBITDA and Adjusted EBITDA are not measurements of financial performance or liquidity under accounting principles generally accepted in the U.S., or U.S. 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 U.S. 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 from, or as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP or other non-GAAP financial measures.
Adjusted EBITDA for the year ended December 31, 2018 was $368.0 million, compared to $343.8 million for the year ended December 31, 2017 and $323.8 million for the year ended December 31, 2016.
The following table reconciles Net income to EBITDA and adjusted EBITDA, for the years ended December 31, 2018, 2017, and 2016:
EBITDA includes the proportionate share (12.75%) of net depreciation, interest and tax expenses from our unconsolidated investment in the Sarulla project that is accounted for under the equity method.
On May 2014, the Sarulla consortium (“SOL”) closed $1,170 million in financing. As of December 31, 2018, the credit facility has an outstanding balance of $1,142.3 million. Our proportionate share in SOL credit facility is $145.6 million.
Capital Expenditures
Our capital expenditures primarily relate to the enhancement of our existing power plants and the exploration, development and construction of new power plants.
We have budgeted approximately $268.5 million in capital expenditures for construction of new projects and enhancements to our existing power plants, of which we have invested approximately $34.7 million as of December 31, 2018. We expect to invest $159.1 million in 2019 and the remaining $74.7 million thereafter.
In addition, we estimate approximately $90.9 million in additional capital expenditures in 2019 to be allocated as follows: (i) $56.7 million for maintenance of capital expenditures to our operating power plants including drilling in our Puna power plant; (ii) $10.9 million for continued exploration activity under various geothermal prospects where we have already started exploration activity; (iii) $14.1 million for the construction and development of storage projects; and (iv) $9.2 million for enhancements to our production facilities.
In the aggregate, we estimate our total capital expenditures for 2019 to be approximately $250.0 million.
Exposure to Market Risks
Based on current conditions, we believe that we have sufficient financial resources to fund our activities and execute our business plans. However, the cost of obtaining financing for our project needs may increase significantly or such financing may be difficult to obtain.
We, like other power plant operators, are exposed to electricity price volatility risk. Our exposure to such market risk is currently limited because many of our long-term PPAs (except for the 25 MW PPA for the Puna Complex and the between 30 MW and 40 MW PPAs in the aggregate for the Heber 2 power plant in the Heber Complex and the G2 power plant in the Mammoth Complex) have fixed or escalating rate provisions that limit our exposure to changes in electricity prices. The energy payments under the PPAs of the Heber 2 power plant in the Heber Complex and the G2 power plant in Mammoth Complex are determined by reference to the relevant power purchaser’s SRAC. A decline 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, or by reducing the price of purchasing its electrical energy needs from natural gas power plants, which in turn will reduce the energy payments that we may charge under the relevant PPA for these power plants. The Puna Complex is currently benefiting from energy prices which are higher than the floor under the 25 MW PPA for the Puna Complex as a result of the high fuel costs that impact HELCO’s avoided costs.
As of December 31, 2018, 96.8% of our consolidated long-term debt was fixed rate debt and therefore was not subject to interest rate volatility risk and 3.2 % of our long-term debt was floating rate debt, exposing us to interest rate risk in connection therewith. As of December 31, 2018, $36.0 million of our long-term debt remained subject to some interest rate risk.
We currently maintain our surplus cash in short-term, interest-bearing bank deposits, money market securities and commercial paper with a minimum investment grade rating of AA by Standard & Poor’s Ratings Services.
Our cash equivalents are subject to interest rate risk. Fixed rate securities may have their market value adversely impacted by a rise in interest rates, while floating rate securities may produce less income than expected if interest rates fall. As a result of these factors, our future investment income may fall short of expectations because of changes in interest rates, or we may suffer losses in principal if we are forced to sell securities that decline in market value because of changes in interest rates.
We are also exposed to foreign currency exchange risk, in particular the fluctuation of the U.S. dollar versus the NIS. Risks attributable to fluctuations in currency exchange rates can arise when we or 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. 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 except for our operations on Guadeloupe, where we own and operate the Boulliante power plant which sells its power under a Euro-denominated PPA with Électricité de France S.A. 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 contract in the currency in which the expenses are incurred. Currently, we have forward contracts in place to reduce our foreign currency exposure and expect to continue to use currency exchange and other derivative instruments to the extent we deem such instruments to be the appropriate tool for managing such exposure. We do not believe that our exchange rate exposure has or will have a material adverse effect on our financial condition, results of operations or cash flows.
We performed a sensitivity analysis on the fair values of our long-term debt obligations, and foreign currency exchange forward contracts. The foreign currency exchange forward contracts listed below principally relate to trading activities. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2018 and 2017 by a hypothetical 10% and calculating the resulting change in the fair values.
At this time, the development of our new strategic plan has not exposed us to any additional market risk. However, as the implementation of the plan progresses, we may be exposed to additional or different market risks.
The results of the sensitivity analysis calculations as of December 31, 2018 and 2017 are presented below:
(1) The application of a 10% increase and/or decrease to the interest rate did not exceed the minimum rate as set forth in the loan agreement.
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 provisions that mitigate inflation risk.
In connection with the Electricity segment, none of our U.S. PPAs, including the SCPPA Portfolio PPA, are directly linked to the CPI. Inflation may directly impact an expense we incur for the operation of our projects, thereby increasing our overall operating costs and reducing our profit and gross margin. 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 our PPAs for some of our power plants such as the Brady power plant, the Steamboat 2 and 3 power plants and the McGinness Complex, 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 calculated 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, thereby increasing our operating costs in the Product segment. We are more likely to be able to offset all or part of this inflationary impact through our project pricing. With respect to power plants that we build 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.
Contractual Obligations and Commercial Commitments
The following tables set forth our material contractual obligations as of December 31, 2018 (in thousands):
(1)
Interest on the OrCal Senior Secured Notes due in 2020 is fixed at a rate of 6.21%. Interest on the OFC 2 Senior Secured Notes Series A due in 2032 is fixed at a rate of 4.687%. Interest on the DAC 1 Senior Secured Notes due in 2033 is fixed at a rate of 4.03%. Interest on the OPIC Loan - Olkaria III Complex due in 2030 is fixed at an average rate of 6.29%. Interest on the DEG 2 Loan due in 2028 is fixed at a rate of 6.28%. Interest on the Senior Unsecured Bonds due in 2020 is fixed at a rate of 3.7%. Interest on the Senior Unsecured Bonds due in 2022 is fixed at a rate of 4.45%. Interest on the Midgal Loan due in 2029 is fixed at a rate of 6.8%. Interest on the OPIC Loan - Platanares power plant - due in 2032 is fixed at a rate of 7.02%. Interest on the USG Prudential - NV due in 2037 is fixed at a rate of 6.75%. Interest on the USG Prudential - ID due in 2023 is fixed at a rate of 5.8%. Interest on the USG DOE due in 2035 is fixed at a rate of 2.6%. Interest on the remaining debt is variable (based primarily on changes in LIBOR rates). For purposes of the above calculation of interest payments pertaining to variable rate debt, future LIBOR rates were based on 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 expected retirement date. These amounts do not include amounts that might be paid to employees that will cease working with us before reaching their expected 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, 2018, total obligations related to such supplier agreements were approximately $129.3 million (approximately $36.1 million of which relate to construction-in-process). All such obligations are payable in 2018.
The table above does not reflect unrecognized tax benefits of $11.8 million, the timing of which is uncertain. Refer to Note 18 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 $69.9 million, the timing of which is uncertain. Refer to Note 13 to our consolidated financial statements as set forth in Item 8 of this annual report for additional discussion of our liability associated with the sale of tax benefits.
Concentration of Credit Risk
Our credit risk is currently concentrated with the following major customers: Sierra Pacific Power Company and Nevada Power Company (subsidiaries of NV Energy), KPLC and SCPPA. If any of these electric utilities fail to make payments under its PPAs with us, such failure would have a material adverse impact on our financial condition. Also, by implementing our multi-year strategic plan we may be exposed, by expanding our customer base, to different credit profile customers than our current customers.
Sierra Pacific Power Company and Nevada Power Company accounted for 16.1%, 18.1%, and 19.2% of our total revenues for the three years ended December 31, 2018, 2017, and 2016, respectively.
KPLC accounted for 16.6%, 15.9%, and 16.5% of our total revenues for the three years ended December 31, 2018, 2017, and 2016, respectively.
SCPPA accounted for 15.2%, 10.1% and 10.2% of our total revenues for the three years ended December 31, 2018, 2017 and 2016, respectively.
We have historically been able to collect on substantially all of our receivable balances. Recently, we have been receiving late payments from KPLC in Kenya related to our Olkaria Complex and from ENNE in Honduras related to our Platanares power plant. As we believe we will be able to collect all past due amounts, no provision for doubtful accounts has been recorded.
Government Grants and Tax Benefits
The federal government encourages production of electricity from wind, solar and geothermal resources through certain tax subsidies. For a new geothermal power plant in the U.S. that started construction by December 31, 2017, we are permitted to claim an investment tax credit for 30 percent of the project cost in the year the project is put in service or production tax credits over time on the power produced. The production-based tax credits, which in 2017 were 2.4 cents per kWh, are adjusted annually for inflation and may be claimed for 10 years on the net electricity output sold to third parties after the project is first placed in service. Any project that started construction by December 2017 must ordinarily be put in service within four years after the end of the year in which construction started to qualify for tax credits at these rates. For a new geothermal power plant in the U.S. that started construction after 2017, we are permitted to claim an investment tax credit of 10 percent of the project cost. New solar projects that are under construction by December 2019 will qualify for a 30 percent investment tax credit. The credit will fall to 26 percent for projects starting construction in 2020 and 22 percent for projects starting construction in 2021. Projects that are under construction before these deadlines must be placed in service by December 31, 2023 to qualify for investment tax credits at these rates. Solar projects placed in service after December 31, 2023 will only qualify for a 10 percent investment tax credit, on par with the permanent credit provided to geothermal. Under current tax rules, any unused tax credit has a one-year carry back and a twenty-year carry forward.
We are also permitted to depreciate, or write off, most of the cost of the plant. In cases where we claim the one-time 30% (or 10%) tax credit, our tax basis in the plant that we can recover through depreciation is reduced by one-half of the tax credit. In cases where we claim the production tax credit, there is no reduction in the tax basis for depreciation. Projects that are placed in service in 2016 and 2017 are eligible for “bonus” depreciation and we will be permitted to write off 50% of the cost of that equipment in the year the power plant is placed in service. Projects placed in service in 2018 would qualify for a 40% bonus and projects placed in service in 2019 would qualify for a 30% bonus. 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. The Tax Act, as further discussed in the MD&A section allows full expensing for certain assets acquired and placed in service after September 27, 2017. We will continue to analyze this new provision under the Act and determine if an election is appropriate as it relates to our business needs.
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 through 2011. In January 2011, new legislation amending the Investment Law was enacted. Under the new legislation, a uniform rate of corporate tax will apply to all qualified income of certain industrial companies, as opposed to the previous law’s incentives that are limited to income from a “Benefited Enterprise” during their benefits period. As a result, we now pay a uniform corporate tax rate of 16% with respect to that qualified income.
Ormat Systems tax assessment for fiscal years 2010-2014 was finalized and settled in January 2017. The settlement resulted in no impact to income statement due to release of the related uncertain tax position liability.
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
Reports of Independent Registered Public Accounting Firm
Consolidated Financial Statements as of December 31, 2018 and 2017 and for Each of the Three Years in the Period Ended December 31, 2018:
Consolidated Balance Sheets
Consolidated Statements of Operations and Comprehensive Income (Loss)
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Ormat Technologies, Inc.:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet of Ormat Technologies, Inc. and its subsidiaries (the "Company") as of December 31, 2018 and the related consolidated statements of operations and comprehensive income (loss), of equity and of cash flows for the year then ended, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because a material weakness in internal control over financial reporting existed as of that date related to ineffective risk assessment over accounting for income taxes.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness referred to above is described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered this material weakness in determining the nature, timing, and extent of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements.
Basis for Opinions
The Company's management is responsible for these consolidated 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 referred to above. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
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/ Kesselman & Kesselman
Certified Public Accountants (Isr.)
A member firm of PricewaterhouseCoopers International Limited
Tel Aviv, Israel
March 1, 2019
We have served as the Company’s auditor since 2018.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Ormat Technologies, Inc.:
Opinion on the Financial Statements
We have audited the consolidated balance sheet of Ormat Technologies, Inc. and its subsidiaries (the “Company”) as of December 31, 2017, and the related consolidated statements of operations and comprehensive income (loss), of equity and of cash flows for each of the two years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
San Francisco, California
March 16, 2018, except for the effects of the restatement and revision discussed in Note 1 (not presented herein) to the consolidated financial statements appearing under Item 8 of the Company’s 2017 annual report on Form 10-K/A, as to which the date is June 19, 2018, and except for Note 1(a), as to which the date is March 1, 2019.
We served as the Company's auditor from 1988 to 2018.
The accompanying notes are an integral part of the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
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
The Company is primarily 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 U.S., Kenya, Guatemala, Guadeloupe and Honduras. The Company’s equipment manufacturing operations are located in Israel.
Most of the Company’s domestic power plant facilities are Qualifying Facilities under the PURPA. The PPAs for certain of such facilities are dependent upon their maintaining Qualifying Facility status. Management believes that all of the facilities located in the U.S. were in compliance with Qualifying Facility status requirements as of December 31, 2018.
Cash dividends
During the years ended December 31, 2018, 2017, and 2016, the Company’s Board of Directors (the “Board”) declared, approved, and authorized the payment of cash dividends in the aggregate amount of $26.8 million ($0.53 per share), $20.5 million ($0.41 per share), and $25.7 million ($0.52 per share), respectively. Such dividends were paid in the years declared.
Rounding
Dollar amounts, except per share data, in the notes to these financial statements are rounded to the closest $1,000, unless otherwise indicated.
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 or consolidated if they are a variable interest entity in which the Company has an interest and is the primary beneficiary. 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 or losses in investments accounted for under the equity method have been reflected as “equity in earnings (losses) of investees, net” on the Company’s consolidated statements of operations and comprehensive income (loss).
Cash and cash equivalents
The Company considers all highly liquid instruments, with an original maturity of three months or less, to be cash equivalents.
Restricted cash, cash equivalents, and marketable securities
Under the terms of certain long-term debt agreements, the Company is required to maintain certain debt service reserves, cash collateral and operating fund accounts that have been classified as restricted cash and cash equivalents. Funds that will be used to satisfy obligations due during the next twelve months are classified as current restricted cash and cash equivalents, with the remainder classified as non-current restricted cash and cash equivalents. Such amounts were invested primarily in money market accounts and commercial paper with a minimum investment grade of “AA”.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation of Cash and cash equivalents and Restricted cash and cash equivalents
The following table provides a reconciliation of Cash and cash equivalents and Restricted cash and cash equivalents reported on the balance sheet that sum to the total of the same amounts shown on the statement of cash flows:
Concentration of credit risk
Financial instruments which potentially subject the Company to concentration of credit risk consist principally of temporary cash investments and accounts receivable.
The Company places its temporary cash investments with high credit quality financial institutions located in the U.S. and in foreign countries. At December 31, 2018 and 2017, the Company had deposits totaling $31.3 million and $21.2 million, respectively, in ten U.S. financial institutions (seven such banks in the prior year) that were federally insured up to $250,000 per account. At December 31, 2018 and 2017, the Company’s deposits in foreign countries of approximately $93.9 million and $32.8 million, respectively, were not insured.
At December 31, 2018 and 2017, accounts receivable related to operations in foreign countries amounted to approximately $102.0 million and $78.1 million, respectively. At December 31, 2018, and 2017, accounts receivable from the Company’s major customers (see Note 19) amounted to approximately 56% and 57%, respectively, of the Company’s accounts receivable.
The Company has historically been able to collect on substantially all of its receivable balances and believes it will continue to be able to collect all amounts due. Accordingly, no provision for doubtful accounts has been made.
Additionally, one of our off-takers, PG&E, which accounts for approximately 1.9% of our total revenues, filed for reorganization under Chapter 11 bankruptcy. We are closely monitoring our PG&E account to ensure cash receipts are received timely each month and the payments due in January 2019 were received and PG&E’s account is current. However, we cannot estimate at this stage what the future impact of PG&E current situation may have on us.
Inventories
Inventories consist primarily of raw material parts and sub-assemblies for power units and are stated at the lower of cost or net realizable value, using the weighted-average cost method. Inventories are reduced by a provision for slow-moving and obsolete inventories. This provision was not material at December 31, 2018 and 2017.
Deposits and other
Deposits and other consist primarily of performance bonds for construction projects, long-term insurance contract and receivables, and derivative instruments.
Deferred charges
Deferred charges represent prepaid income taxes on intercompany sales. Such amounts were amortized using the straight-line method and included in income tax provision over the life of the related property, plant and equipment. The Company adopted Accounting Standards Update 2016-16, Income Taxes on Intercompany Transfers in its consolidated financial statements for the first quarter of 2018 using the modified retrospective approach. As a result, there was an adjustment to deferred charges with a corresponding adjustment to deferred income taxes of $49.8 million with an immaterial amount recorded to retained earnings. For additional information on the new accounting standard related to tax effects associated with intra-company transfers of assets please see "New accounting pronouncements effective in the year ended December 31, 2018" below.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property, plant and equipment, net
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 15 to 30 years. The other assets are depreciated using the straight-line method over the following estimated useful lives of the assets:
The cost and accumulated depreciation of items sold or retired are removed from the accounts. Any resulting gain or loss is recognized currently and recorded in the accompanying statements of operations.
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 $3.7 million, $7.2 million, and $3.3 million for the years ended December 31, 2018, 2017, and 2016, respectively.
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 (loss). Such costs were immaterial during the years ended December 31, 2018, 2017 and 2016. It normally takes two to three 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. However, in certain sites the process may take longer due to permitting delays, transmission constraints or any other commercial milestones that are required to be reached in order to pursue the development process.
In most cases, the Company obtains the right to conduct the geothermal development and operations on land owned by the 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 (loss). Upon commencement of power generation on the leased land, the Company begins to pay to the lessor’s 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 (loss).
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 be converted to a full-size commercial well, used either for extraction or re-injection of geothermal fluids, or be 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.
When deciding whether to continue holding lease rights and/or to pursue exploration activity, we diligently prioritize our prospective investments, taking into account resource and probability assessments in order to make informed decisions about whether a particular project will support commercial operation. As a result, write-off of unsuccessful activities for the year ended December 31, 2018, 2017 and 2016 was $0.1 million, $1.8 million, and $3.0 million. In 2017, the write-offs included exploration costs related to the Company’s exploration activities in Oregon, and in 2016, the write-offs included the exploration costs related to the Company’s exploration activities in Nevada and Chile, after which the Company determined that the applicable sites would no longer support commercial operation.
Grants received from the U.S. DOE are offset against the related exploration and development costs. There were no such grants for the years ended December 31, 2018 and 2017. The amount of such grants for the year ended December 31, 2016 was $0.3 million.
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. The Company periodically reassess the assumptions used to estimate the expected cash flows required to settle the asset retirement obligation, including changes in estimated probabilities, amounts, and timing of the settlement of the asset retirement obligation, as well as changes in the legal requirements of an obligation and revises the previously recorded asset retirement obligation accordingly. 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 (loss). Accumulated amortization related to deferred financing costs amounted to $21.8 million and $31.0 million at December 31, 2018 and 2017, respectively. Amortization expense for the years ended December 31, 2018, 2017, and 2016 amounted to $4.6 million, $5.7 million, and $6.9 million, respectively. During the years ended December 31, 2018, 2017 and 2016, amounts of $0.0 million, $0.6 million and $0.1 million, respectively, were written-off as a result of the extinguishment of liability.
Deferred transaction costs relating to the Puna operating lease (see Note 12) in the amount of $4.2 million 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 (loss). Accumulated amortization related to deferred lease costs amounted to $2.5 million and $2.3 million at December 31, 2018 and 2017, respectively. Amortization expense for each of the years ended December 31, 2018, 2017, and 2016 amounted to $0.2 million.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Goodwill
Goodwill represents the excess of the fair value of consideration transferred in the business combination transactions of Guadeloupe, Viridity and USG over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and the fair value of any noncontrolling interest in the acquisitions. Goodwill is not amortized but rather subject to a periodic impairment testing on an annual basis (on December 31 of each year) or if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. Additionally, an entity is permitted to first assess qualitative factors to determine whether a quantitative goodwill impairment test is necessary. Further testing is only required if the entity determines, based on the qualitative assessment, that it is more likely than not that a reporting unit’s fair value is less than its carrying amount. Otherwise, no further impairment testing is required. An entity has the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to step one of the quantitative goodwill impairment test. This would not preclude the entity from performing the qualitative assessment in any subsequent period. The first step compares the fair value of the reporting unit to its carrying value, including goodwill. In January 2017, the FASB issued ASU 2017-04, Intangibles - Goodwill and Other (Topic 350), which was early adopted by the Company in 2018, under which step two of the goodwill impairment test is eliminated. Step two measured a goodwill impairment test by comparing the implied fair value of reporting unit’s goodwill with the carrying amount of that goodwill. For additional information on this new accounting standard please see "New accounting pronouncements effective in the year ended December 31, 2018" below. Under ASU 2017-04, Intangibles - Goodwill and Other, an entity should recognize an impairment charge for the amount by which the carrying amount of the reporting unit exceeds its fair value as calculated under step one described above. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. For further information relating to goodwill see Note 9 - Intangible assets and goodwill to the consolidated financial statements.
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 (see Note 9) as well as acquisition cost allocation related to Viridity’s storage activities that are amortized over a weighted average amortization period of 19 years. Intangible assets are tested for recoverability whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. In case there is no such events or change in circumstances, there is no need to perform the impairment testing. The recoverability is tested by comparing the net carrying value of the intangible assets to the undiscounted net cash flows to be generated from the use and eventual disposition of that asset. If the carrying amount of a long-lived asset (or asset group) is not recoverable, the fair value of the asset (asset group) is measured and if the carrying amount exceeds the fair value, an impairment loss is recognized.
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 and construction-in-process 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 expected market rates thereafter 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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. If actual cash flows differ significantly from the Company’s current estimates, a material impairment charge may be required in the future.
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 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 may incorporates the use of swap contracts and put options on oil and natural gas prices, forward exchange contracts, interest rate swaps, and interest rate caps to minimize significant fluctuation in cash flows and/or earnings that are caused by oil and natural gas prices, 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 accumulated other comprehensive income or loss are subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Gains or losses on contracts that are not designated as a cash flow hedge are included currently in earnings.
Foreign currency translation
The U.S. dollar is the functional currency for all of the Company’s consolidated operations and those of its equity affiliates except for the Guadeloupe power plant. For those entities, all gains and losses from currency translations are included within the line item “Derivatives and foreign currency transaction gains (losses)” within the consolidated statements of operations and comprehensive income (loss). The Euro is the functional currency of the Guadeloupe power plant and thus gains and losses from currency translation adjustments related to Guadeloupe are included as currency translation adjustments in accumulated other comprehensive income in the consolidated statements of equity and in comprehensive income. The accumulated currency translation adjustments amounted to $0.0 million and $1.4 million as of December 31, 2018 and 2017, respectively.
Comprehensive income (loss) reporting
Comprehensive income (loss) includes net income or loss plus other comprehensive income (loss), which for the Company consists of changes in unrealized gains or losses in respect of the Company’s share in derivatives instruments of unconsolidated investment, foreign currency translation adjustments and amortization of unrealized gains in respect of derivative instruments designated as a cash flow hedge. The changes in foreign currency translation adjustments, amortization of unrealized gains and loss in respect of derivative instruments designated as a cash flow hedge during the years ended December 31, 2018, 2017 and 2016 were immaterial. The change in the Company’s share in derivative instruments of unconsolidated investment is disclosed under Note 5 - Investment in unconsolidated companies to the consolidated financial statements.
Revenues and cost of revenues
Revenues are primarily related to: (i) sale of electricity from geothermal and recovered energy-based power plants owned and operated by the Company; (ii) geothermal and recovered energy-based power plant equipment engineering, sale, construction and installation, and operating services and (iii) energy storage, demand-response and energy management services.
Electricity segment revenues: Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003, the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed 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 PPAs. PPAs with contingent rentals are recognized when earned. In the electricity segment, revenues for all but four power plants are accounted for under ASC 840 (Leases) as operating leases, and therefore equipment related to geothermal and recovered energy generation power plants as described in Note 8 is considered held for leasing. For power plants in the scope of ASC 606, the Company identified electricity as a separate performance obligation. Performance obligations identified were evaluated and determined to be satisfied over time and qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. The transaction price is determined based on the price per actual mega-watt output or available capacity as agreed to in the respective PPA. Customers are generally billed on a monthly basis and payment is typically due within 30 to 60 days after the issuance of the invoice.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Product segment revenues: Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based power plant equipment and other equipment to third parties are recognized over time since control is transferred continuously to our customers. The majority of our contracts include a single performance obligation which is essentially the promise to transfer the individual goods or services that are not separately identifiable from other promises in the contracts and therefore deemed as not distinct. Performance obligations are satisfied over-time if the customer receives the benefits as we perform work, if the customer controls the asset as it is being constructed, or if the product being produced for the customer has no alternative use and we have a contractual right to payment. In our Product segment, revenues are spread over a period of one to two years and are recognized over time based on the cost incurred to date in ratio to total estimated costs which represents the input method that best depicts the transfer of control over the performance obligation to the customer. Costs include direct material, labor, and indirect costs. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined.
In contracts for which we determine that control is not transferred continuously to the customer, we recognized revenues at the point in time when the customer obtains control of the asset. Revenues for such contracts are recorded upon delivery and acceptance by the customer. This generally is the case for the sale of spare parts, generators or similar products.
Accounting for product contracts that are satisfied over time includes use of several estimates such as variable consideration related to bonuses and penalties and total estimated cost for completing the contract. The estimated amount of variable consideration will be included in the transaction price only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. These estimates are based on historical experience, anticipated performance and our best judgment at the time.
The nature of our product contracts give rise to several modifications or change requests by our customers. Substantially all of the modifications are treated as cumulative catch-ups to revenues since the additional goods are not distinct from those already provided. We include the additional revenues related to the modifications in our transaction price when both parties to the contract approved the modification. As a significant change in one or more of these estimates could affect the profitability of our contracts, we review and update our contract-related estimates regularly. We recognize adjustments in Product revenues on contracts under the cumulative catch-up method. If at any time the estimate of contract profitability indicates an anticipated loss on the contract, we recognize the total loss in the period in which it is identified.
Other segment revenues: Energy storage, demand-response and energy management related services revenues are recorded based on energy management of load curtailment capacity delivered or service provided at rates specified under the relevant contract terms. The Company determined that such revenues are in the scope of ASC 606 and identified energy management as a separate performance obligation. Performance obligations are satisfied once the Company provides verification to the electric power grid operator or utility of its ability to meet the committed capacity or power curtailment requirements and thus entitled to cash proceeds. Such verification may be provided by the Company bi-weekly, monthly or under any other frequency as set by the related program and are typically followed by a payment shortly after. Performance obligations identified were evaluated and determined to be satisfied over time and qualified for the invoicing practical expedient since the amounts included in the verification document reasonably represent the value of performance obligations fulfilled to date. The transaction price is determined based on mechanisms specified in the contract with the customer.
For additional information please see “Revenues from Contracts with Customers” under “New accounting pronouncement” section below.
Our accounting policy for revenues included under the comparative periods were accounted under the previous accounting standard as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenues related to the sale of electricity from geothermal and recovered energy-based power plants and capacity payments are recorded based upon output delivered and capacity provided at rates specified under relevant contract terms. For PPAs agreed to, modified, or acquired in business combinations on or after July 1, 2003, the Company determines whether such PPAs contain a lease element requiring lease accounting. Revenue from such PPAs are accounted for in electricity revenues. The lease element of the PPAs is also assessed 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 PPAs. PPAs with contingent rentals are recognized when earned. In the electricity segment, revenues for all but two power plants are accounted for under ASC 840 (Leases) as operating leases, and therefore equipment related to geothermal and recovered energy generation power plants as described in Note 8 is considered held for leasing.
Revenues from engineering, operating services, and parts and product sales are recorded upon providing the service or delivery of the products and parts and when collectability is reasonably assured. Revenues from the supply and/or construction of geothermal and recovered energy-based 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.
In specific instances where there is a lack of dependable estimates or inherent risks cause forecast to be doubtful, then the completed-contract method is followed. Revenue is recognized when the contract is substantially complete and when collectability is reasonably assured. Costs that are closely associated with the project are deferred as contract costs and recognized similarly to the associated revenues.
Termination fee
Fees to terminate PPAs are recognized in the period incurred as selling and marketing expenses. During 2018, the Company signed a termination agreement with NV Energy, Inc. for the Galena 2 PPA under which it agreed to pay a termination fee of approximately $5 million which were recorded under Selling and marketing expenses in 2018. In 2017 and 2016, no termination fees were incurred.
Warranty on products sold
The Company generally provides a one to two years warranty against defects in workmanship and materials related to the sale of products for electricity generation. The Company considered the warranty as an assurance type warranty since the warranty provides the customer the assurance that the product complies with agreed-upon specifications. 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, 2018, 2017, and 2016.
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 DOE are offset against the related research and development expenses. There were no such grants for the years ended December 31, 2018, 2017, and 2016.
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). Starting in 2016, the Company uses the Exercise Multiple-Based Lattice SAR-Pricing Model to value the stock-based compensation awards to reflect accumulated historic data retained of behavioral parameters. Prior to 2016, the Company used the Black-Scholes formula to estimate the fair value of the stock-based compensation.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Tax monetization Transactions
The Company has two tax monetization transactions, Opal Geo and Tungsten as further described under Note 13 - tax monetization transactions to the consolidated financial statements. The OPC and ORTP tax monetization transactions closed during 2017 upon the Company’s partners reaching their target after-tax yield on their investment, as further described in Note 13. The purpose of these transactions is to form tax partnerships, whereby investors provide cash in exchange for equity interests that provide the holder a right to the majority of tax benefits associated with a renewable energy project. We account for a portion of the proceeds from the transaction as debt under ASC 470. Given that a portion of these transactions is structured as a purchase of an equity interest we also classify a portion as noncontrolling interest consistent with guidance in ASC 810. The portion recorded to noncontrolling interest is initially measured as the fair value of the discounted Tax Attributes and cash distributions which represents the partner's residual economic interest. The residual proceeds are recognized as the initial carrying value of the debt which is classified as a liability associated with sale tax benefits. We apply the effective interest rate method to the liability associated with the tax monetization transaction component as described by ASC 835 and CON 7. The tax benefits and cash distributions realized by the partner each period are treated as the debt servicing amounts, giving rise to income attributable to the sale of tax benefits. The deferred transaction costs have been capitalized and amortized using the effective interest method.
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. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Act. The Tax Act makes broad and complex changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35 percent to 21 percent; (2) requiring companies to include in taxable income an amount on certain repatriated earnings of foreign subsidiaries; (3) generally eliminating U.S. federal income taxes on dividends from foreign subsidiaries; (4) requiring a current inclusion in U.S. federal taxable income of certain earnings of controlled foreign corporations (GILTI); (5) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits can be realized; (6) creating BEAT, a new minimum tax; (7) creating a new limitation on deductible interest expense; and (8) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. See Note 18 to the consolidated financial statements for further details regarding the Company's income tax provision and the Tax Act. The Company accounts for investment tax credits and production tax credits as a reduction to income taxes in the year in which the credit arises. The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits that, based on available evidence, are more likely than not expected to be realized. A partial valuation allowance has been established to offset the Company’s U.S. deferred tax assets. 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. 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.
Earnings per share
Basic earnings per share attributable to the Company’s stockholders (“earnings per share”) is computed by dividing net income or loss 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.
The table below shows the reconciliation of the number of shares used in the computation of basic and diluted earnings per share:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 176.4 thousand, 42.9 thousand, and 102.8 thousand, respectively, for the years ended December 31, 2018, 2017, and 2016.
Use of estimates in preparation of financial statements
The preparation of financial statements in conformity with U.S. GAAP 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 goodwill and long-lived assets, including intangible assets, revenue recognition of product sales using the percentage of completion method, asset retirement obligations, and the provision for income taxes.
Puna Power Plant
On May 3, 2018, the Kilauea volcano located in close proximity to our Puna 38 MW geothermal power plant in the Puna district of Hawaii's Big Island erupted following a significant increase in seismic activity in the area. Before it recently stopped flowing, the lava covered the wellheads of three geothermal wells, monitoring wells and the substation of the Puna complex and an adjacent warehouse that stored a drilling rig that was also consumed by the lava. The insurance policy coverage for property and business interruption is provided by a consortium of insurers. All the insurers accepted and started paying for the costs to rebuild the destroyed substation, and as of December 31, 2018 we received $3.3 million. However only some of the insurers accepted that the business interruption coverage started in May 2018 and as of December 31, 2018 we recorded $12.1 million of such proceeds. The Company is still in discussions to reach an understanding with all insurers to start paying for the business interruption as of May 2018. The Company is still assessing the damages in the Puna facilities and continue to coordinate with HELCO and local authorities to bring the power plant back to operation. The Company continues to assess the accounting implications of this event on the assets and liabilities on its balance sheet and whether an impairment will be required. Any significant physical damage to the geothermal resource or continued shut-down following the recent stop of the lava of the Puna facilities could have an adverse impact on the power plant's electricity generation and availability, which in turn could have a material adverse impact on our business and results of operations.
New Accounting Pronouncements
New accounting pronouncements effective in the year ended December 31, 2018
Income Taxes
In March 2018, the Financial Accounting Standards Board ("FASB") issued ASU 2018-05, Income Taxes (Topic 740). The amendments in this update add several SEC paragraphs pursuant to the issuance of the SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”) in December 2017. The amendments in this update are effective immediately. For additional information, see in Note 18 to our consolidated financial statements set forth in Item 8 of this annual report.
Revenues from Contracts with Customers
In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers, Topic 606, which was a joint project of the FASB and the International Accounting Standards Board to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The update provides that an entity should recognize revenue in connection with the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Specifically, an entity is required to apply each of the following steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contracts; (3) determine the transaction price; (4) allocate the transaction price to the performance obligation in the contract; and (5) recognize revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 also prescribes additional financial presentations and disclosures. In March 2016, the FASB issued ASU 2016-08, Principal versus Agent Considerations. This update did not change the core principles of the guidance and was intended to clarify the implementation guidance on principal versus agent considerations. When another entity is involved in providing goods or services to a customer, an entity is required to determine if the nature of its promise is to provide the specific good or service itself (that is, the entity is a principal) or to arrange for that good or service to be provided by the other party (that is, the entity is an agent). The guidance included indicators to assist an entity in determining whether it acts as a principal or agent in a specified transaction.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company adopted this update effectively as of January 1, 2018 using the modified retrospective approach with a one-time cumulative adjustment to the opening balance of retained earnings as further described below and applied the five-step model described above on identified outstanding contracts at the date of adoption, under which revenues are generated. Under ASC 606, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations and recognize the revenue when the obligation is completed. A performance obligation is a promise in a contract to transfer a distinct good or service to the customer. A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The standard also requires disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts.
The adoption of ASC 606, Revenues from Contracts with Customers, as described above, did not have an impact on our Electricity, Product and Other segment revenues in 2018, however, the adoption did have an impact on our accounting for our investment in an unconsolidated company as further described in the following table and in the disclosure under the heading "Investment in an unconsolidated company" within this note below. Additionally, the following table below summarizes the impact of the adoption of ASC 606 on the Company’s consolidated financial statements as of January 1, 2018, followed by further information for each of the line items in the table:
For a detailed description of our Electricity, Products and Other revenues, please see “Revenues and cost of revenues” caption above.
Contract Assets and Liabilities related to our Product segment: Contract assets reflect revenue recognized and performance obligations satisfied in advance of customer billing. Contract liabilities relate to payments received in advance of the satisfaction of performance under the contract. We receive payments from customers based on the terms established in our contracts. Total contract assets and contract liabilities as of December 31, 2018 and December 31, 2017 are as follows:
(*) Contract assets and contract liabilities are presented as "Costs and estimated earnings in excess of billings on uncompleted contracts" and "Billings in excess of costs and estimated earnings on uncompleted contracts", respectively, on the consolidated balance sheet.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the significant changes in the contract assets and contract liabilities for the year ended December 31, 2018:
The timing of revenue recognition, billings and cash collections results in accounts receivable, contract assets and contract liabilities on the consolidated balance sheet. In our Products segment, amounts are billed as work progresses in accordance with agreed-upon contractual terms, or upon achievement of contractual milestones. Generally, billing occurs subsequent to the recognition of revenue, resulting in contract assets. However, we sometimes receive advances or deposits from our customers before revenue can be recognized, resulting in contract liabilities. These assets and liabilities are reported on the consolidated balance sheet on a contract-by-contract basis at the end of each reporting period. The timing of billing our customers and receiving advance payments vary from contract to contract. The majority of payments are received no later than the completion of the project and satisfaction of our performance obligation.
On December 31, 2018, we had approximately $188.1 million of remaining performance obligations not yet satisfied or partly satisfied related to our Product segment. We expect to recognize approximately 100% of this amount as Product revenues during the next 24 months.
The following schedule reconciles revenues accounted for under ASC 840, Leases, and ASC 606, Revenues from Contracts with Customers, to total consolidated revenues for the year ended December 31, 2018:
Disaggregated revenues from contracts with customers for the year ended December 31, 2018 are disclosed under Note 19 - Business Segments, to the consolidated financial statements.
Investment in an unconsolidated company: The Company also reviewed the impact of the adoption of ASC 606 on its investment in an unconsolidated company. As a result of the adoption, the Company recorded a one-time cumulative credit adjustment to the opening balance of retained earnings of approximately $24.0 million as of January 1, 2018. This impact is a result of the unconsolidated company’s variable consideration related to the construction of its power plant for which, under the new guidance, is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty is resolved. As such, the comparative information will not be restated and shall continue to be reported under the accounting standards in effect for those periods.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following schedule quantifies the impact of adopting ASC 606 on the statement of operations for the year ended December 31, 2018:
Compensation - Stock Compensation
In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718). The amendments in this update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in this update require that an entity should account for the effects of a modification unless all of the following are met: (1) The fair value of the modified award is the same as the fair value of the original award immediately before the original award is modified; (2) The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; (3) The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified. The current disclosure requirements under Topic 718 apply regardless of whether an entity is required to apply modification accounting under the amendments in this update. The amendments in this update are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.
Business Combinations
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805). The update clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update primarily provide a screen to determine when a set of assets and activities is not a business and by that reduces the number of transactions that need to be further evaluated. The amendments in this update should be applied prospectively and are effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of this guidance did not have an impact on the Company’s condensed consolidated financial statements.
Statement of Cash Flow
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) - Restricted Cash. The amendments in this update require that a statement of cash flows explain the changes during the period in total cash, cash equivalents, and the amounts generally described as restricted cash or cash equivalents. Therefore, amounts of restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments in this update should be applied retrospectively for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The Company adopted this guidance retrospectively in its consolidated financial statements for the year ended December 31, 2018 and adjusted its disclosure accordingly.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Intra-Entity Transfers of Assets Other than Inventory
In October 2016, the FASB issued ASU 2016-16, Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory. The amendments in this update require that the entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The new guidance does not apply to intra-entity transfers on inventory. The amendments in this update should be applied for each period presented and are effective for financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The modified retrospective approach is required for transition to the new guidance, with cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. The Company adopted this guidance in its consolidated financial statements for the year ended December 31, 2018 using the modified retrospective approach. As a result, there was an adjustment to deferred charges with a corresponding adjustment to deferred income taxes of $49.8 million with an immaterial amount recorded to retained earnings.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash payments (Topic 230)
In August 2016, the FASB issued ASU 2016-15, Statement of Cash-Flows (Topic 230). This update addresses eight specific cash flow classification issues with the objective of reducing diversity in practice. One of the issues addressed in this update is debt prepayment or debt extinguishment costs which under the new guidance should be classified as cash outflows for financing activities. Additionally, the update addressed contingent consideration payments made after a business combination. Such cash payments made soon after the acquisition date to settle a contingent consideration liability should be classified as cash outflows for investing activities. Payments made thereafter should be classified as cash outflows for financing activities up to the amount of the original contingent consideration liability. Payments made in excess of the amount of the original contingent consideration liability should be classified as cash outflows for operating activities. The amendments in this update are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The amendments in this update should be applied using a retrospective transition method to each period presented. The Company adopted this guidance in the year ended December 31, 2018 and accordingly reclassified approximately $8.0 million of cash paid for achievement of certain production thresholds in Guadeloupe during the fourth quarter of 2017 from cash outflows from investing activities to cash outflows from financing activities as required by this update.
Recognition and Measurement of Financial Assets and Financial Liabilities
In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The update primarily requires that an entity present separately, in other comprehensive income, the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The application of this update should be by means of cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments in this update are effective for financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The adoption of this update did not have a material impact on the Company’s consolidated financial statements.
Intangibles -Goodwill and Other
In January 2017, the FASB issued ASU 2017-04, Intangibles - Goodwill and Other (Topic 350). The amendments in this Update require the entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value, however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider the income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. This update, eliminated Step 2 from the goodwill impairment test under the current guidance. Step 2 measures a goodwill impairment loss by comparing the implied fair value of reporting unit’s goodwill with the carrying amount of that goodwill. The amendments in this Update should be applied on a prospective basis. An entity is also required to disclose the nature of and the reason for the change in accounting principal upon transition. That disclosure should be provided in the first annual period and the interim period within the first annual period when the entity initially adopts the amendments in this Update. The amendments in this Update are effective for the annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual impairment tests performed on testing dates after January 1, 2017. The Company adopted this Update in 2018 in connection with its goodwill impairment test of Viridity.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New accounting pronouncements effective in future periods
Derivatives and Hedging
In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities. The amendments in this Update better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. To meet that objective, the amendments expand and refine hedge accounting for both nonfinancial and financial risk components and align the recognition and presentation of the effects of the hedging instrument and the hedged item in the financial statements. The amendments in this Update are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early application is permitted in any interim period after issuance of the Update. The Company is currently evaluating the potential impact, if any, of the adoption of these amendments on its consolidated financial statements.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This update introduces a number of changes and simplifies previous guidance, primarily the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The update retains the distinction between finance leases and operating leases and the classification criteria between the two types remains substantially similar. Also, lessor accounting remains largely unchanged from previous guidance. However, key aspects of the update were aligned with the revenue recognition guidance in Topic 606. Additionally, the update defines a lease as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (a) the right to obtain substantially all of the economic benefits from the use of the asset and (b) the right to direct the use of the asset. This update requires the modified retrospective transition approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. The modified retrospective approach includes a number of optional practical expedients related to identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commenced before the effective date in accordance with the previous generally accepted accounting principles in the United States unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous generally accepted accounting principles in the United States. Since the issuance of the update in February 2016, the FASB issues several additional updates and amendments including ASU 2018-11, Leases, which was issued in July 2018 and provided an additional optional transition method for the adoption of the standard as well as additional codification improvements. Under this new transition method, an entity initially applies the new lease standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, the comparative periods presented in the financial statements in which the standard is adopted will continue to be in accordance with the current GAAP. The amendments in this update are effective for annual reporting periods beginning after December 15, 2018, including interim periods within those reporting periods.
The Company performed an evaluation of the impact from adopting the standard on its financial statements which included, among others, utilization of internal resources to lead the implementation efforts and supplement them with external resources and accounting professionals, review of the Company’s existing lease portfolio and assess the impact to its business processes and internal control over financial reporting. The Company will adopt this update on January 1, 2019, using the modified retrospective approach at the effective date with no adjustment to the comparative periods which will continue to be presented in accordance with the current GAAP. Additionally, the Company expects to elect the above-mentioned practical expedients as provided by the new standard and consequently will not recognize right-of-use assets and lease liabilities for arrangements with a term of less than one year and not separate lease and non-lease components for all classes of underlying assets other than real estate assets. The Company also expects to apply the portfolio approach under the update, primarily with respect to determination of incremental borrowing rate.
The Company has substantially completed its assessment of the potential impact that the implementation of this update will have on its consolidated financial statements and continues to finalize its efforts relative to the adoption of this update as of January 1, 2019. While our current evaluation and conclusions are subject to changes as our assessment has not yet been completed, the Company expects there will be an increase to assets and liabilities related to the recognition of a right-of-use asset and a lease liability on its existing lease portfolio in the amount within a range between approximately $27.0 million and $30.0 million, however, it does not expect the adoption of the update to have a material impact on its consolidated statement of operations and comprehensive income and consolidated statements of cash flows.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive income
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220). The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting for the Tax Act. The guidance is effective for the fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the potential impact of the adoption of these amendments on its consolidated financial statements, however, such impact, if any, is not expected to be material.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1(a) - Retrospective adjustments as a result of adoption of accounting policies and change in segments
As described above in Note 1, the Company adopted ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments and ASU 2016-18, Statement of Cash Flow that required retrospective adjustments to the years ended December 31, 2017 and 2016 to the Statement of Cash Flows. Further, as described in Note 19, in 2018, the Company started disclosing its energy storage and power load management business activity under the Other segment as such operations met the reportable segment criteria of ASC 280, Segment Reporting. This separate reportable segment required retrospective adjustment for comparative purposes for the year ended December 31, 2017.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2 -BUSINESS ACQUISITIONS AND OTHERS
USG transaction
On April 24, 2018, the Company completed the acquisition of USG. The total cash consideration (exclusive of transaction expenses) was approximately $110 million, comprised of approximately $106 million funded from available cash of Ormat Nevada Inc. (to acquire the outstanding shares of common stock of USG) and approximately $4 million funded from available cash of USG (to cash-settle outstanding in-the-money options for common stock of USG). As a result of the acquisition, USG became an indirect wholly owned subsidiary of Ormat, and Ormat indirectly acquired, among other things, interests held by USG and its subsidiaries in:
• three operating power plants at Neal Hot Springs, Oregon; San Emidio, Nevada; and Raft River, Idaho with a total net generating capacity of approximately 38 MW; and
• development assets which include a project at the Geysers, California; a second phase project at San Emidio, Nevada; a greenfield project in Crescent Valley, Nevada; and the El Ceibillo project located near Guatemala City, Guatemala.
As a result of the acquisition, the Company expanded its overall generation capacity and expects to improve the profitability of the purchased assets through cost reduction and synergies. The Company accounted for the transaction in accordance with Accounting Standard Codification ASC 805, Business Combinations and following the transaction, the Company consolidates USG, in accordance with Accounting Standard Codification ASC 810, Consolidation. Accounting guidance provides that the allocation of the purchase price may be modified for up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The Company deemed that the adoption of ASU 2017-01, Business Combinations, as further described under Note 1 to the consolidated financial statements, did not have an effect on the USG transaction.
The following table summarizes the purchase price allocation to the fair value of the assets acquired and liabilities assumed (in millions):
(1)
Intangible assets are primarily related to long-term electricity power purchase agreements and depreciated over an average of 19 years.
(2)
Goodwill is primarily related to the expected synergies in operations as a result of the purchase transaction. The goodwill is allocated to the Electricity segment and not deductible for tax purposes.
The fair value of the noncontrolling interest of $34.9 million reflects the 40% minority interests in the Neal Hot Springs project that was evaluated using the income approach. The fair value of the noncontrolling interest is based on the following significant inputs: (i) forecasted cash flows assumed to be generated in correspondence with the remaining life of the related power purchase agreement which is approximately 20 years; (ii) revenues were estimated in accordance with the price and generation capacity of the related power purchase agreement; (iii) assumed terminal value based on the realizable value of the project at the end of the power purchase agreement term; and (iv) assumed discount rate of approximately 9%.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Total Electricity revenues and operating profit related to the three USG power plants of approximately $21.4 million and $2.5 million, respectively, for the period started at the acquisition date to December 31, 2018 were included in the Company’s consolidated statements of operations and comprehensive income for the year ended December 31, 2018. The following unaudited pro forma summary presents consolidated information of the Company as if the business combination had occurred on January 1, 2017:
Viridity transaction
On March 15, 2017, the Company completed the acquisition of substantially all of the business and assets of Viridity Energy, Inc., a privately held Philadelphia-based company formerly engaged in the provision of demand response, energy management and energy storage services. At closing, Viridity Energy Solutions Inc. (“Viridity”), a wholly owned subsidiary of the Company, paid initial consideration of $35.3 million. Additional contingent consideration with an estimated fair value of $12.4 million was set upon the achievement of certain performance milestones to be measured at the end of fiscal years 2017 and 2020. The first performance milestone measured at the end of 2017 was not achieved and as a result, the Company reversed the related contingent consideration in the amount of $0.6 million which was recorded under general and administrative expenses. Additionally, as of December 31, 2018, the Company estimated that the second milestone to be measured at the end of fiscal year 2020 will not be achieved and consequently reversed the related contingent consideration in the amount of $10.3 million. The reversal of the contingent liability was recorded under general and administrative expenses for the year ended December 31, 2018.
Using proprietary software and solutions, Viridity serves primarily retail energy providers, utilities, and large commercial and industrial customers. Viridity’s offerings enable its customers to optimize and monetize their energy management, demand response and storage facilities potential by interacting on their behalf with regional transmission organizations and independent system operators.
The Company accounted for the transaction in accordance with Accounting Standard Codification 805, Business Combinations, and consequently recorded intangible assets of $34.7 million primarily relating to Viridity’s storage activities with a weighted-average amortization period of 19 years, approximately $0.4 million of working capital and fixed assets and $13.5 million of goodwill. Following the transaction, the Company consolidated Viridity in accordance with Accounting Standard Codification 810, Consolidation. The acquisition enabled the Company to enter the growing energy storage and demand response markets and expand its market presence.
During the fourth quarter of 2018, the Company recorded an impairment charge for the full amount of goodwill associated with its storage and energy management services in its consolidated statements of operations and comprehensive income (loss). Further information related to this impairment charge is disclosed in Note 9 - “Intangible assets and goodwill” to the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 - INVENTORIES
Inventories consist of the following:
NOTE 4 - COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS
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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - Investment in an unconsolidated company
Investment in an unconsolidated company mainly consist of the following:
The Sarulla Project
The Company holds a 12.75% equity interest in a consortium that developed the 330 MW Sarulla geothermal power plant project in Tapanuli Utara, North Sumatra, Indonesia. The Sarulla project is comprised of three separately constructed 110 MW units, the most recent of which, NIL 2, was completed in April 2018. The Sarulla project is owned and operated by the consortium members under the framework of a joint operating contract and energy sales contract that were both executed on April 4, 2013. Under the joint operating contract, PT Pertamina Geothermal Energy, the concession holder for the project, provided the consortium with the right to use the geothermal field, and under the energy sales contract, PT PLN, the state electric utility, is the off-taker at Sarulla for a period of 30 years.
During the years ended December 31, 2018 and 2017, the Company made additional cash equity investments in the Sarulla project of approximately $3.8 million and $46.3 million, respectively, for a total of $62.0 million since inception.
The Sarulla consortium entered into interest rate swap agreements with various international banks, effective as of June 4, 2014, and accounted for the interest rate swap as a cash flow hedge upon which changes in the fair value of the hedging instrument, relative to the effective portion, are recorded in other comprehensive income. The Company’s share of such gains (losses) recorded in other comprehensive income (loss) are as follows:
The related accumulated loss recorded by the Company in other comprehensive income (loss) as of December 31, 2018 is $2.9 million.
As further described above under Note 1 to the consolidated financial statements under the heading “New accounting pronouncement effective in the year ended December 31, 2018”, the Company adopted ASC 606, Revenue from Contracts with Customers, on January 1, 2018. The impact of the adoption of this standard on its investment in an unconsolidated company amounted to $24.0 million at January 1, 2018. This impact was a result of the unconsolidated company’s variable consideration related to the construction of its power plant for which, under the new guidance, is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty is resolved. The Company adopted the new standard using the modified retrospective approach with a one-time cumulative adjustment to the opening balance of retained earnings of approximately $24.0 million at January 1, 2018, the date of initial application.
NOTE 6 - VARIABLE INTEREST ENTITIES
The Company’s overall methodology for evaluating transactions and relationships under the variable interest entity (“VIE”) accounting and disclosure 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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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; and (ii) wholly owned subsidiaries with PPAs.
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, 2018 and 2017:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 upon selling an asset or paid upon transferring 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. The guidance establishes a fair value hierarchy that prioritizes the inputs to 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).
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth certain fair value information at December 31, 2018 and 2017 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.
(1) These amounts relate to contingent receivables and payables and warrants pertaining to the Viridity acquisition and Guadeloupe power plant purchase transaction, valued primarily based on unobservable inputs and are included within "Prepaid expenses and other", "Accounts Payable and accrued expenses" and "Other long-term liabilities" on December 31, 2018 and 2017 in the consolidated balance sheets with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.
(2) These amounts relate to currency forward contracts valued primarily based on observable inputs, including forward and spot prices for currencies, net of contracted rates and then multiplied by notional amounts, and are included within "Prepaid expenses and other" and "Accounts payable and accrued expenses", as applicable, on December 31, 2018 and December 31, 2017, in the consolidated balance sheet with the corresponding gain or loss being recognized within "Derivatives and foreign currency transaction gains (losses)" in the consolidated statement of operations and comprehensive income.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The amounts set forth in the tables above include investments in debt instruments and money market funds (which are included in cash equivalents). Those securities and deposits are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices in an active market.
The following table presents the amounts of gain (loss) recognized in the consolidated statements of operations and comprehensive income (loss) on derivative instruments not designated as hedges:
In January 2017, the Company entered into Henry Hub Natural Gas Future contracts under which it has bought a number of put options covering a notional quantity of approximately 4.1 million British Thermal Units (“MMBtu”) with exercise prices of $3 and expiration dates ranging from January 26, 2017 until November 27, 2017 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company paid an aggregate amount of approximately $0.7 million for these put options. The put option contracts have monthly expiration dates at which the options can be called and the transaction would be settled on a net cash basis.
On February 2, 2016, the Company entered into Henry Hub Natural Gas Future contracts under which it has written a number of call options covering a notional quantity of approximately 4.1 MMBtu with exercise prices of $2 and expiration dates ranging from February 24, 2016 until December 27, 2016 in order to reduce its exposure to fluctuations in natural gas prices under its PPAs with Southern California Edison. The Company received an aggregate premium of approximately $1.9 million from these call options. The call option contracts have monthly expiration dates at which the options can be called and the Company would have to settle its liability on a cash basis.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On February 24, 2016, the Company entered into Brent Oil Future contracts under which it has written a number of call options covering a notional quantity of approximately 185,000 barrels (“BBL”) of Brent with exercise prices of $32.80 to $35.50 and expiration dates ranging from March 24, 2016 until December 22, 2016 in order to reduce its exposure to fluctuations in Brent prices under its PPA with HELCO. The Company received an aggregate premium of approximately $1.1 million from these call options. The call option contracts have monthly expiration dates whereby the options can be called and the Company would have to settle its liability on a cash basis. Moreover, during March 2016, the Company rolled 2 existing call options covering a total notional quantity of 31,800 BBL of Brent in order to limit its exposure to $41 to $42.50 instead of $32.80 to $33.50. In addition, the Company entered into short risk reversal transactions (sell call and buy put options) by rolling existing call options covering notional quantities of 16,500 BBL and 17,000 BBL in order to limit its exposure from the outstanding call options originally entered into in February 2016 to a range of $28.50 to $37.50 and $28 to $38.50, respectively.
The foregoing future, forward and swap transactions have not been designated as hedge transactions and are marked to market with the corresponding gains or losses recognized within “Derivatives and foreign currency transaction gains (losses)” in the consolidated statements of operations and comprehensive income.
There were no transfers of assets or liabilities between Level 1, Level 2 and Level 3 during the year ended December 31, 2018.
The fair value of the Company’s long-term debt is as follows:
The fair value of the long-term debt is determined by a valuation model, which is based on a conventional discounted cash flow methodology and utilizes assumptions of current borrowing rates.The fair value of revolving lines of credit is determined using a comparison of market-based price sources that are reflective of similar credit ratings to those of the Company.
The carrying value of other financial instruments, such as revolving lines of credit and deposits approximates fair value.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value of financial instruments as of December 31, 2018:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value of financial instruments as of December 31, 2017:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2018, 2017, and 2016 amounted to $114.4 million, $98.8 million and $94.8 million, respectively. Depreciation expense for the years ended December 31, 2018, 2017 and 2016 is net of the impact of the cash grant in the amount of $6.4 million, $5.5 million and $5.5 million, respectively.
U.S. Operations
The net book value of the property, plant and equipment, including construction-in-process, located in the U.S. was approximately $1,696.4 million and $1,447.4 million as of December 31, 2018 and 2017, respectively. These amounts as of December 31, 2018 and 2017 are net of cash grants in the amount of $179.7 million and $133.2 million, respectively.
Foreign Operations
The net book value of property, plant and equipment, including construction-in-process, located outside of the U.S. was approximately $524.8 million and $580.8 million as of December 31, 2018 and 2017, 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 with the power plants was $302.0 million and $326.1 million as of December 31, 2018 and 2017, respectively. The Company sells the electricity produced by the power plants to Kenya Power and Lighting Co. Ltd. (“KPLC”) under a 20-year PPA.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company, through its wholly owned subsidiary, Orzunil I de Electricidad, Limitada (“Orzunil”), owns a power plant in Guatemala. On January 22, 2014, Orzunil signed an amendment to the PPA with INDE, a Guatemalan power company, for its Zunil geothermal power plant in Guatemala. The amendment extends the term of the PPA from 2019 to 2034. The PPA amendment also transfers operation and management responsibilities of the Zunil geothermal field from INDE to the Company for the term of the amended PPA in exchange for a tariff increase. Additionally, INDE exercised its right under the PPA to become a partner in the Zunil power plant with a 3% equity interest. The net book value of the assets related to the power plant was $14.6 million and $9.9 million at December 31, 2018 and 2017, 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 $43.5 million and $40.7 million at December 31, 2018 and 2017, respectively.
The Company, through its wholly owned subsidiary, GeoPlatanares, signed a BOT contract for the Platanares geothermal project in Honduras with ELCOSA, a privately owned Honduran energy company, for 15 years from the commercial operation date. Platanares sells the electricity produced by the power plants to ENEE, the national utility of Honduras under a 30-year PPA. The net book value of the assets related to the power plant was $105.7 million and $140.3 million at December 31, 2018 and 2017, respectively.
The Company, through its subsidiary, GB, owns a power plant in Guadeloupe. The net book value of the assets related to the power plant was $23.9 million and $24.9 million at December 31, 2018 and 2017, respectively. GB sells the electricity produced by the power plants to EDF, the French electric utility, under a 15-year PPA.
Construction-in-process
Construction-in-process consists of the following:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 - INTANGIBLE ASSETS AND GOODWILL
Intangible assets amounting to $199.9 million and $85.4 million consist mainly of the Company’s PPAs acquired in business combinations and Viridity’s storage activities, net of accumulated amortization of $61.5 million and $50.0 million as of December 31, 2018 and 2017, respectively. Intangible assets relating to our storage activities, as of December 31, 2018 and 2017, amounted to $32.2 million and $33.8 million, net of accumulated amortization of $3.4 million and $1.7 million, respectively. Amortization expense for the years ended December 31, 2018, 2017, and 2016 amounted to $11.2 million, $6.9 million, and $4.4 million, respectively. Additions to intangible assets for the years ended December 31, 2018, 2017 and 2016, amounted to $127.0 million, $35.6 million and $33.0 million, respectively. The additions to intangible assets in 2018, 2017 and 2016 primarily relate to the USG acquisition, Viridity acquisition and the purchase of the Guadeloupe plant, respectively. The Company tested the intangible assets for recoverability in December 2018 and 2017 and assessed whether there are events or change in circumstances which may indicate that the intangible assets are not recoverable. Our assessment resulted in that there were no write-offs of intangible assets in 2018, 2017 and 2016.
Estimated future amortization expense for the intangible assets as of December 31, 2018 is as follows:
Goodwill
Goodwill amounting to $20.0 million and $21.0 million as of December 31, 2018 and 2017, respectively, represents the excess of the fair value of considerations transferred in business combination transactions over the fair value of tangible and intangible assets acquired, net of the fair value of liabilities assumed and non-controlling interest (as applicable) in the acquisitions.
During the fourth quarter of 2018, the Company determined that certain qualitative indicators of a potential impairment existed in relation to its storage and energy management services reporting unit which required further quantitative assessment of goodwill impairment (step one as described in Note 1 to the consolidated financial statements under the caption “Goodwill”). The qualitative indicators included a significant update to the reporting unit’s business forecasts combined with a large-scale restructuring of the way the Company runs this reporting unit which were both executed during the fourth quarter of 2018. As a result of the quantitative assessment, the Company recorded a goodwill impairment charge of $13.5 million in the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2018. Following this impairment charge, the goodwill allocated to the storage and energy management services reporting unit is zero. The Company estimated the fair value of the storage and energy management services reporting unit by using the income approach based on discounted cash flows, which utilized Level 3 measurement that represent unobservable inputs into the Company’s valuation method.
Except as noted above, for the years 2018 and 2017, our impairment assessment related to the Company’s other reporting units for which goodwill is allocated to resulted in no impairment to goodwill.
Changes in the carrying amount of the Company’s goodwill for the years ended December 31, 2018 and 2017 were as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 10 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consist of the following:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11 - LONG-TERM DEBT AND CREDIT AGREEMENTS
Long-term debt consists of notes payable under the following agreements:
Loan Agreement with Banco Industrial S.A. and Westrust Bank (International) Limited
On July 31, 2015, Ortitlản, Limitada, the Company’s wholly owned subsidiary, obtained a 12-year secured term loan in the principal amount of $42.0 million for the 20 MW Amatitlan power plant in Guatemala. Under the credit agreement with Banco Industrial S.A. and Westrust Bank (International) Limited, we can expand the Amatitlan power plant with financing to be provided either via equity, additional debt from Banco Industrial S.A. or from other lenders, subject to certain limitations on expansion financing in the credit agreement.
The loan is payable in 48 quarterly payments commencing September 30, 2015. The loan bears interest at a rate per annum equal to of the sum of the LIBO Rate (which cannot be lower than 1.25%) plus a margin of (i) 4.35% as long as the Company’s guaranty of the loan (as described below) is outstanding or (ii) 4.75% otherwise. Interest is payable quarterly, on March 30, June 30, September 30 and December 30 of each year, on the stated maturity date of the loan and on any prepayment or payment of the loan. The loan must be prepaid on the occurrence of certain events, such as casualty, condemnation, asset sales and expansion financing not provided by the lenders under the credit agreement, among others. The loan may be voluntarily prepaid if certain conditions are satisfied, including payment of a premium (ranging from 100-50 basis points) if prepayment occurs prior to the eighth anniversary of the loan.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
There are various restrictive covenants under the Amatitlan credit agreement. These include, among others, (i) a financial covenant to maintain a Debt Service Coverage Ratio (as defined in the credit agreement) of not less than 1.15 to 1.00 as of the last day of any fiscal quarter and (ii) limitations on Restricted Payments (as defined in the credit agreement) that among other things would limit dividends that could be paid to us unless the historical and projected Debt Service Coverage Ratio is not less than 1.25 to 1.00 for the four fiscal quarterly periods (calculated as a single accounting period). As of December 31, 2018, the actual historical and projected 12-month Debt Service Coverage Ratio was 1.58 and 1.59, respectively. The credit agreement includes various events of default that would permit acceleration of the loan (subject in some cases to grace and cure periods). These include, among others, a Change of Control (as defined in the credit agreement) and failure to maintain certain required balances in debt service and maintenance reserve accounts. The credit agreement includes certain equity cure rights for failure to maintain the Debt Service Coverage Ratio and the minimum amounts required in the debt service and maintenance reserve accounts.
The loan is collateralized by substantially all the assets of the borrower and a pledge of all of the membership interests of the borrower.
The Company has guaranteed payment of all obligations under the credit agreement and related financing documents. The guaranty is limited in the sense that the Company is only required to pay the guaranteed obligations if a “trigger event” occurs. A trigger event is the occurrence and continuation of a default by INDE in its payment obligations under the PPA for the Amatitlàn power plant or a refusal by INDE to receive capacity and energy sold under that PPA. The Company’s obligations under the guaranty may be terminated prior to payment in full of the guaranteed obligations under certain circumstances described in the guaranty. If the guaranty is terminated early, the interest rate payable on the loan would increase as described above.
As of December 31, 2018, $29.8 million of this loan is outstanding.
Finance Agreement with OPIC (the Olkaria III Complex)
On August 23, 2012, OrPower 4, the Company’s wholly owned subsidiary, entered into a Finance Agreement with OPIC, an agency of the U.S. government, to provide limited-recourse senior secured debt financing in an aggregate principal amount of up to $310.0 million (the “OPIC Loan”) for the refinancing and financing of the Olkaria III geothermal power complex in Kenya. The Finance Agreement was amended on November 9, 2012.
The OPIC Loan is comprised of up to three tranches:
•
Tranche I in an aggregate principal amount of $85.0 million, which was drawn in November 2012, was used to prepay approximately $20.5 million (plus associated prepayment penalty and breakage costs of $1.5 million) of the DEG Loan, as described below. The remainder of Tranche I proceeds was used for reimbursement of prior capital costs and other corporate purposes.
•
Tranche II in an aggregate principal amount of $180.0 million was used to fund the construction and well field drilling for the expansion of the Olkaria III geothermal power complex (“Plant 2”). In November 2012, an amount of $135.0 million was disbursed under this Tranche II, and in February 2013, the remaining $45.0 million was distributed under this Tranche II.
•
Tranche III in an aggregate principal amount of $45.0 million was used to fund the construction of Plant 3 of the Olkaria III complex. In November 2013, an amount of $45.0 million was disbursed under this Tranche.
In July 2013, we completed the conversion of the interest rate applicable to both Tranche I and Tranche II from a floating interest rate to a fixed interest rate. The average fixed interest rate for Tranche I, which has an outstanding balance as of December 31, 2018 of $56.6 million and matures on December 15, 2030, and Tranche II, which has an outstanding balance as of December 31, 2018 of $121.8 million and matures on June 15, 2030, is 6.31%. In November 2013, we fixed the interest rate for Tranche III. The fixed interest rate for Tranche III, which has an outstanding balance as of December 31, 2018 of $32.2 million and matures on December 15, 2030, is 6.12%.
OrPower 4 has a right to make voluntary prepayments of all or a portion of the OPIC Loan subject to prior notice, minimum prepayment amounts, and a prepayment premium of 2.0% in the first two years after the Plant 2 commercial operation date, declining to 1% in the third year after the Plant 2 commercial operation date, and without premium thereafter, plus a redemption premium. In addition, the OPIC Loan is subject to customary mandatory prepayment in the event of certain reductions in generation capacity of the power plants, unless such reductions will not cause the projected ratio of cash flow to debt service to fall below 1.7.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The OPIC Loan is collateralized by substantially all of OrPower 4’s assets and by a pledge of all of the equity interests in OrPower 4.
The finance agreement includes customary events of default, including failure to pay any principal, interest or other amounts when due, failure to comply with covenants, breach of representations and warranties, non-payment or acceleration of other debt of OrPower 4, bankruptcy of OrPower 4 or certain of its affiliates, judgments rendered against OrPower 4, expropriation, change of control, and revocation or early termination of security documents or certain project-related agreements, subject to various exceptions and notice, cure and grace periods.
There are various restrictive covenants under the OPIC Loan, which include a required historical and projected 12-month DSCR of not less than 1.4 (measured as of March 15, June 15, September 15 and December 15 of each year). If OrPower 4 fails to comply with these financial ratios it will be prohibited from making distributions to its shareholders. In addition, if the DSCR falls below 1.1, subject to certain cure rights, such failure will constitute an event of default by OrPower 4. This covenant in respect of Tranche I became effective on December 15, 2014. As of December 31, 2018, the actual historical and projected 12-month DSCR was 2.87 and 3.03, respectively.
As of December 31, 2018, $210.6 million of the OPIC Loan was outstanding.
Debt service reserve
As required under the terms of the OPIC 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 OPIC Loan in the following six months. This restricted cash account is classified as current in the consolidated balance sheets. As of December 31, 2018 and 2017, the balance of the account was $2.6 million and $3.7 million, respectively. In addition, as of December 31, 2018, part of the required debt service reserve was backed by a letter of credit in the amount of $16.1 million (see Note 22).
Well drilling reserve
As required under the terms of the OPIC Loan, OrPower 4 may be required to maintain an account which may be funded by cash or backed by letters of credit to reserve funds for future well drilling, based on determination upon the completion of the expansion work.
Finance Agreement with OPIC (the Platanares power plant)
On April 30, 2018, Geotérmica Platanares, S.A. de C.V. (“Platanares”), a Honduran sociedad anónima de capital variable and an indirect subsidiary of Ormat Technologies, Inc., entered into a Finance Agreement (the “Finance Agreement”) with OPIC, pursuant to which OPIC will provide to Platanares senior secured non-recourse debt financing in an aggregate principal amount of up to $124.7 million (the “Platanares Loan”), the proceeds of which will be used principally for the refinancing and financing of the Platanares 35 MW geothermal power plant located in western Honduras (the “Project”). The finance agreement was amended and closed in October of 2018.
Tranche I in an aggregate principal amount of $114.7 million was drawn in October 2018, carries a fixed interest rate of 7.02% per annum and matures in September of 2032. The closing of tranche II of up to $10 million is expected during the first half of 2019 subject to the satisfaction or waiver of certain conditions precedent.
Under the Finance Agreement, Platanares may, upon prior written notice to OPIC, make voluntary prepayments of the OPIC Loan, in whole or in part, in a minimum partial prepayment amount of $5 million together with payment to OPIC of all accrued but unpaid interest on the principal amount of the OPIC Loan to be prepaid, plus a prepayment premium. The prepayment premium is equal to (i) 2% of the principal amount of the OPIC Loan to be prepaid for any voluntary prepayment in the first or second year following expiration of the Commitment Period (as defined in the Finance Agreement) and (ii) 1% of the principal amount of the Platanares Loan to be prepaid for any voluntary prepayment in the third year following expiration of the Commitment Period. There is no prepayment premium for any voluntary prepayment in the fourth year following expiration of the Commitment Period or thereafter.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The OPIC Loan is also subject to customary mandatory prepayment upon the occurrence of certain events, including, among others, (i) receipt by Platanares of compensation or damages following a dispute that results in a material adverse change to the primary power purchase agreement for the Project, (ii) receipt by Platanares of a termination or indemnity payment from a third party (other than OPIC) or expropriation proceeds from a governmental authority upon the termination of any project documents or the condemnation, nationalization, seizure or expropriation of all or a substantial portion of the Project or property of Platanares by a governmental authority, respectively, and (iii) receipt by Platanares of sale proceeds in excess of a certain threshold from the disposition of all or any part of the property of Platanares, subject to certain exceptions.
The OPIC Loan will be secured by a first priority lien on all of the assets and ordinary shares of Platanares. The Finance Agreement contains various restrictive covenants applicable to Platanares, among others (i) to maintain a projected and historic debt service coverage ratio of no less than 1.1 to 1; (ii) to maintain on deposit in a debt service reserve account and well reserve account funds or assets with a value in excess of a minimum threshold and (iii) covenants that restrict Platanares from making certain payments or other distributions to its equity holders unless the projected and historic debt service coverage ratio is not less than 1.2 to 1. As of December 31, 2018, the projected 12-month Debt Service Coverage Ratio was 1.50.
The Finance Agreement also contains customary events of default, including, among others, failure to pay principal, interest or other amounts when due, non-payment or acceleration of other indebtedness of Platanares, the occurrence of a change of control of Platanares without the prior approval of OPIC, expropriation, judgments rendered against Platanares in excess of a certain threshold, failure to comply with covenants, a voluntary abandonment of the Project and the occurrence of certain bankruptcy events, subject to various exceptions and applicable notice, cure and grace periods.
As of December 31, 2018, $112.7 million of the Platanares OPIC Loan was outstanding.
Debt service reserve
As required under the terms of the Platanares Loan, Platanares 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 Platanares Loan in the following six months (or nine months in case of overdue payments by the offtaker up to a certain agreed threshold). This restricted cash account is classified as current in the consolidated balance sheets. As of December 31, 2018, the balance of the account was $13.4 million and no letter of credit was required to be issued.
Well drilling reserve
As required under the terms of the Finance Agreement, Platanares is required to maintain an account which may be funded by cash or backed by letters of credit to reserve funds for well costs, based on certain determinations. As of December 31, 2018, the balance of the account was $2 million and no letter of credit was required to be issued.
OFC Senior Secured Notes
In February 2004, our subsidiary OFC issued $190.0 million of Senior Secured Notes (“OFC Senior Secured Notes”) for the purpose of refinancing the acquisition cost of the Brady, Ormesa and Steamboat 1, 1A, 2 and 3 power plants, and financing the acquisition cost of 50% of the Mammoth complex. Principal and interest on the OFC Senior Secured Notes, which would have matured on December 30, 2020, were payable semi-annually. The OFC Senior Secured Notes were collateralized by substantially all of the assets of OFC and those of its wholly owned subsidiaries and fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC. In September 2017, the Company fully prepaid the outstanding amount of $14.3 million of OFC Senior Secured Notes, plus an additional make-whole premium of $1.3 million.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OrCal Senior Secured Notes
In December 2005, OrCal, the Company’s wholly owned subsidiary, issued $165.0 million, 6.21% Senior Secured Notes (“OrCal Senior Secured Notes”) 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 Ratings. 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. 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 of OrCal and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OrCal. In addition, there are restrictions on the ability of OrCal to make distributions to its shareholders, which include a required historical and projected 12-month debt service coverage ratio (“DSCR”) of not less than 1.25 (measured semi-annually as of June 30 and December 31 of each year). If OrCal fails to comply with the DSCR ratio it will be prohibited from making distributions to its shareholders. OrCal is only required to measure these covenants on a semi-annual basis and as of December 31, 2018, the last measurement date of the covenants, the actual historical 12-month DSCR was 1.18 and the pro-forma 12-month DSCR was 1.41. There was $18.7 million and $32.1 million of OrCal Senior Secured Notes outstanding as of December 31, 2018 and December 31, 2017, respectively.
OrCal may redeem the OrCal Senior Secured Notes, in whole or in part, at any time at a redemption price equal to the principal amount of the OrCal Senior Secured Notes to be redeemed plus accrued interest, and a “make-whole” premium. Upon certain events, as defined in the indenture governing the OrCal Senior Secured Notes, OrCal may be required to redeem a portion of the OrCal Senior Secured Notes at a redemption price of 100% of the principal amount of the OrCal Senior Secured Notes being redeemed plus accrued interest.
Debt service reserve
As required under the terms of the OrCal Senior Secured Notes, OrCal maintains an account 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 sheets. As of December 31, 2018 and 2017, the balance of such account was $0.0 million and $1.9 million, respectively. In addition, as of each of December 31, 2018 and 2017, part of the required debt service reserve was backed by a letter of credit in the amount of $4.6 million (see Note 22).
OFC 2 Senior Secured Notes
In September 2011, OFC 2, the Company’s wholly owned subsidiary and OFC 2’s wholly owned project subsidiaries (collectively, the “OFC 2 Issuers”) entered into a note purchase agreement (the “Note Purchase Agreement”) with OFC 2 Noteholder Trust, as purchaser, John Hancock Life Insurance Company (U.S.A.), as administrative agent, and the DOE, as guarantor, in connection with the offer and sale of up to $350.0 million aggregate principal amount of OFC 2 Senior Secured Notes (“OFC 2 Senior Secured Notes”) due December 31, 2034.
Subject to the fulfillment of customary and other specified conditions precedent, the OFC 2 Senior Secured Notes may be issued in up to six distinct series associated with the phased construction (Phase I and Phase II) of the Jersey Valley, McGinness Hills and Tuscarora geothermal power plants, which are owned by the OFC 2 Issuers. The OFC 2 Senior Secured Notes will mature and the principal amount of the OFC 2 Senior Secured Notes will be payable in equal quarterly installments and in any event not later than December 31, 2034. Each series of notes will bear interest at a rate calculated based on a spread over the Treasury yield curve that will be set at least ten business days prior to the issuance of such series of notes. Interest will be payable quarterly in arrears. The DOE will guarantee payment of 80% of principal and interest on the OFC 2 Senior Secured Notes pursuant to Section 1705 of Title XVII of the Energy Policy Act of 2005, as amended. The conditions precedent to the issuance of the OFC 2 Senior Secured Notes includes certain specified conditions required by the DOE in connection with its guarantee of the OFC 2 Senior Secured Notes.
On October 31, 2011, the OFC 2 Issuers completed the sale of $151.7 million in aggregate principal amount of 4.687% Series A Notes due 2032 (the “Series A Notes”). The net proceeds from the sale of the Series A Notes, after deducting transaction fees and expenses, were approximately $141.1 million, and were used to finance a portion of the construction costs of Phase I of the McGinness Hills and Tuscarora power plants and to fund certain reserves. Principal and interest on the Series A Notes are payable quarterly in arrears on the last day of March, June, September and December of each year.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On June 20, 2014, Phase 1 of Tuscarora Facility achieved Project Completion under the Note Purchase Agreement. In accordance with the terms of the Note Purchase Agreement and following recalibration of the financing assumptions, the loan amount was adjusted through a principal prepayment of $4.3 million.
On August 29, 2014, OFC 2 sold $140.0 million of OFC 2 Senior Secured Notes (the “Series C Notes”) to finance the construction of the second phase of the McGinness Hills project. The Series C Notes are the last tranche under the Note Purchase Agreement with John Hancock Life Insurance Company and are guaranteed by the DOE’s Loan Programs Office in accordance with and subject to the DOE's Loan Guarantee Program under Section 1705 of Title XVII of the Energy Policy Act of 2005. The Series C Notes, which mature in December 2032, carry a 4.61% coupon with principal to be repaid on a quarterly basis.
In connection with the anticipated sale of the Series C Notes, on August 13, 2014, the Company entered into an on-the-run interest rate lock agreement with a financial institution with a termination date of August 15, 2014. This on-the-run interest rate lock agreement had a notional amount of $140.0 million and was designated as a cash flow hedge. The objective of this cash flow hedge was to eliminate the variability in the changes in the 10-year U.S. Treasury rate as that is one of the components in the annual interest rate of the OFC 2 Senior Secured Notes that was forecasted to be fixed on August 15, 2014. The Company hedged the variability in total proceeds attributable to changes in the 10-year U.S. Treasury rate for the forecasted sale of Series C Notes. On August 18, 2014, the settlement date, the Company paid $1.5 million to the counterparty of the on-the-run interest rate lock agreement.
The Company concluded that the cash flow hedge was fully effective with no ineffective portion and no amounts excluded from the effectiveness testing, thus, in 2014, the total loss from the cash flow hedge was fully recognized in “Loss in respect of derivatives instruments designated for cash flow hedge” under other comprehensive income of $0.9 million noted above, which was net of related taxes of $0.6 million. The cash flow hedge loss recorded is amortized over the life of the OFC 2 Senior Secured Notes using the effective interest method. In 2016 and 2015, the Company reclassified $0.1 million, each year, of the loss from “Accumulated other comprehensive income (loss)” into interest expense.
The OFC 2 Senior Secured Notes are collateralized by substantially all of the assets of OFC 2 and those of its wholly owned subsidiaries and are fully and unconditionally guaranteed by all of the wholly owned subsidiaries of OFC 2. There are various restrictive covenants under the OFC 2 Senior Secured Notes, which include limitations on additional indebtedness of OFC 2 and its wholly owned subsidiaries. Failure to comply with these and other covenants will, subject to customary cure rights, constitute an event of default by OFC 2. In addition, there are restrictions on the ability of OFC 2 to make distributions to its shareholders.
Among other things, the distribution restrictions include a historical debt service coverage ratio requirement of at least 1.2 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately preceding the proposed distribution, and a projected future DSCR requirement of at least 1.5 (on a blended basis for all OFC 2 power plants), measured, at the time of any proposed distribution, over each of the two six-months periods comprised of distinct consecutive fiscal quarters immediately following such proposed distribution. As of December 31, 2018, our historical DSCR was 2.55 and 2.21, respectively for each of the two six-month periods, and our projected future DSCR was 2.09 and 2.18, respectively for each of the two six-month periods.
There were $217.8 million and $232.5 million of OFC 2 Senior Secured Notes outstanding as of December 31, 2018 and December 31, 2017, respectively.
The Company provided a guaranty in connection with the issuance of the Series A Notes and Series C Notes. The guaranty may be drawn in the event of, among other things, the failure of any facility financed by the relevant series of OFC 2 Senior Secured Notes to reach completion and meet certain operational performance levels (the “non-performance trigger”) which gives rise to a prepayment obligation on the OFC 2 Senior Secured Notes. The guarantee may also be drawn if there is a payment default on the OFC 2 Senior Secured Notes or upon the occurrence of certain fundamental defaults that result in the acceleration of the OFC 2 Senior Secured Notes, in each case, prior to the date that the relevant facility(ies) financed by such OFC 2 Senior Secured Notes reaches completion and meets the applicable operational performance levels. The Company’s liability under the guaranty with respect to the non-performance trigger is limited to an amount equal to the prepayment amount on the OFC 2 Senior Secured Notes necessary to bring the OFC 2 Issuers into compliance with certain coverage ratios. The Company’s liability under the guarantee with respect to the other trigger event described above is not so limited.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt service reserve; other restricted funds
Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is required to maintain a debt service reserve and certain other reserves, as follows:
(i)
A debt service reserve 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 2 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, 2018, part of the required debt service reserve was backed by a letter of credit in the amount of $20.0 million (see Note 22).
(ii)
A performance level reserve account, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. This reserve builds up over time and reduces gradually each time the project achieves certain milestones. Upon issuance of the Series A Notes, this reserve was funded in the amount of $28.0 million. As of December 31, 2018, the balance of such account was zero million, and no letter of credit was required to be issued.
(iii)
Under the terms of the OFC 2 Senior Secured Notes, OFC 2 is also required to maintain a well field drilling and maintenance reserve that builds up over time and is dedicated to costs and expenses associated with drilling and maintenance of the project's well field, which may be funded by cash or backed by letters of credit.
(iv)
A performance level reserve account for McGinness Hills Phase II, intended to provide additional security for the OFC 2 Senior Secured Notes, which may be funded by cash or backed by letters of credit. As of December 31, 2018, there was no requirement for an additional security to be issued as the project was completed.
Don A. Campbell Senior Secured Notes - Non-Recourse
On November 29, 2016, ORNI 47 LLC (“ORNI 47”), the Company’s subsidiary, entered into a note purchase agreement (the “ORNI 47 Note Purchase Agreement”) with MUFG Union Bank, N.A., as collateral agent, Munich Reinsurance America, Inc. and Munich American Reassurance Company (the “Purchasers”) pursuant to which ORNI 47 issued and sold to the Purchasers $92.5 million aggregate principal amount of its 4.03% Senior Secured Notes due September 27, 2033 (the “DAC 1 Senior Secured Notes”) in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended. ORNI 47 is the owner of the first phase of the Don A. Campbell geothermal power plant (“DAC 1”), and part of the ORPD LLC (“ORPD”) portfolio.
The net proceeds from the sale of the DAC 1 Senior Secured Notes, after deducting certain transaction expenses and the funding of a debt service reserve account, were approximately $87.1 million and ORNI 47 used the proceeds from the sale of the Notes to refinance the development and construction costs of the DAC 1 geothermal power plant, which were originally financed using equity.
ORNI 47 began paying a scheduled amount of principal of the DAC 1 Senior Secured Notes on December 27, 2016 and now makes principal payments quarterly, on the 27th day of each March, June, September and December, until the DAC 1 Senior Secured Notes mature.
The DAC 1 Senior Secured Notes constitute senior secured obligations of ORNI 47 and are secured by all of the assets of ORNI 47. Under the ORNI 47 Note Purchase Agreement, ORNI 47 may prepay at any time all, or from time to time any part of, the DAC 1 Senior Secured Notes in an amount equal to at least $2 million or such lesser amount as may remain outstanding under the DAC 1 Senior Secured Notes at 100% of the principal amount to be prepaid plus the applicable make-whole amount determined for the prepayment date with respect to such principal amount. Upon the occurrence of a Change of Control (as defined in the ORNI 47 Note Purchase Agreement), ORNI 47 must make an offer to each holder of DAC 1 Senior Secured Notes to repurchase all of the holder’s notes at 101% of the aggregate principal amount of such notes to be repurchased plus accrued and unpaid interest, if any, on such notes to, but not including, the date of repurchase. Each holder of DAC 1 Senior Secured Notes may accept such offer in whole or in part. In certain events, including certain asset sales outside the ordinary course of business, ORNI 47 must make mandatory prepayments of the DAC 1 Senior Secured Notes at 100% of the principal amount to be prepaid. The ORNI 47 Note Purchase Agreement requires ORNI 47 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens, amendment or modification of material project documents, the ability of ORNI 47 to merge or consolidate with another entity. The ORNI 47 Note Purchase Agreement also contains customary events of default. In addition, there are restrictions on the ability of ORNI 47 to make distributions to its shareholders, which include a required historical and projected DSCR of not less than 1.20 for the four fiscal quarterly periods. As of December 31, 2018, the historical and projected DSCR were 1.35 and 1.69, respectively.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2018, $83.3 million is outstanding under the DAC 1 Senior Secured Notes.
USG loans
On April 24, 2018, the Company completed the acquisition of USG. As part of the acquisition we assumed the following non-recourse loans:
Prudential Capital Group - Idaho non-recourse
In May 2016, USG’s wholly owned subsidiary (Idaho USG Holdings LLC) entered into a loan agreement with the Prudential Capital Group to finance its development activities. The original principal totaled $20.0 million and included the option to issue additional debt up to $50.0 million within the following two years. The $20.0 million loan amount bears interest at a fixed interest rate of 5.8% per annum. The principal and interest payments are due semi-annually and the principal is partially repaid during the first seven-year term and the remaining balance of $16.0 million is due in full at this seven-year term. The loan is secured by the Company’s ownership interests in the Neal Hot Springs project and the Raft River project projects. As of December 31, 2018, $18.9 million of the Prudential Capital loan is outstanding.
U.S. Department of Energy - non-recourse
On August 31, 2011, USG’s wholly owned subsidiary, USG Oregon LLC (“USG Oregon”), completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its power plant at Neal Hot Springs project in Eastern Oregon. All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note dated February 23, 2011. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Neal Hot Springs site. No additional advances are allowed under the terms of the loan. A total of 13 draws were taken and each individual draw or tranche is considered to be a separate loan. The loan principal is scheduled to be paid over 21.5 years from the first scheduled payment date with semi-annual installments including interest calculated at an aggregate fixed interest rate of 2.6%. The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. As of December 31, 2018, $51.4 million of the DOE loan is outstanding.
Prudential Capital Group - Nevada non-recourse
On September 26, 2013, USG’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group to finance the Phase I of San Emidio geothermal project located in northwest Nevada. The term of the note is approximately 24 years and bears interest at a fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to projected operating results made at the loan origination date and available cash balances. The loan agreement is secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the San Emidio project and the equity interests in USG Nevada LLC. As of December 31, 2018, $27.8 million of the loan is outstanding.
Senior Unsecured Bonds
In September 2016, the Company concluded an auction tender and accepted subscriptions for two series of senior unsecured bonds comprised of approximately $67 million aggregate principal amount of senior unsecured bonds (the “Series 2 Bonds”) and approximately $137 million aggregate principal amount of senior unsecured bonds (the “Series 3 Bonds” and together with the Series 2 Bonds, the “Senior Unsecured Bonds”). The proceeds from the Series 2 Bonds and Series 3 Bonds were used on September 29, 2016 to prepay the Company’s $250 million aggregate principal amount of previously issued bonds that were payable on August 1, 2017.
The Series 2 Bonds will mature in September 2020 and bear interest at a fixed rate of 3.7% per annum, payable semi-annually. The Series 3 Bonds will mature in September 2022 and bear interest at a fixed rate of 4.45% per annum, payable semi-annually. The Series 2 Bonds and Series 3 Bonds will be repaid at maturity in a single bullet payment, unless earlier prepaid by the Company pursuant to the terms and conditions of the trust instrument that governs such Senior Unsecured Bonds.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Senior Unsecured Loan
On March 22, 2018 the Company entered into a definitive loan agreement (the "Migdal Loan Agreement") with Migdal Insurance Company Ltd., Migdal Makefet Pension and Provident Funds Ltd. and Yozma Pension Fund of Self-Employed Ltd., all entities within the Migdal Group, a leading insurance company and institutional investor in Israel. The Migdal Loan Agreement provides for a loan by the lenders to the Company in an aggregate principal amount of $100.0 million (the "Migdal Loan"). The Migdal Loan will be repaid in 15 semi-annual payments of $4.2 million each, commencing on September 15, 2021, with a final payment of $37.0 million on March 15, 2029. The Migdal Loan bears interest at a fixed rate of 4.8% per annum, payable semi-annually, subject to adjustment in certain circumstances as described below.
The Loan is subject to early redemption by the Company prior to maturity from time to time (but not more frequently than once per quarter) and at any time in whole or in part, at a redemption price set forth in the Migdal Loan Agreement. If the rating of the Company is downgraded to "ilA-"(or equivalent), of any of Standard and Poor’s, Moody’s or Fitch (whenever in Israel or outside of Israel) (each a “Credit Rating Agency”), the interest rate applicable to the Migdal Loan will increase by 0.50%. If the rating of the Company is further downgraded to a lower level by any Credit Rating Agency, the interest rate applicable to the Migdal Loan will be increased by 0.25% for each additional downgrade. In no event will the cumulative increase in the interest rate applicable to the Loan exceed 1% regardless of the cumulative rating downgrade. A subsequent upgrade or reinstatement of a rating by any Credit Rating Agency will reduce the interest rate applicable to the Migdal Loan by 0.25% for each upgrade (but in no event will the interest rate applicable the Migdal Loan fall below the base interest rate of 4.8%). Additionally, if the ratio between short-term and long-term debt to financial institutions and bondholders, deducting cash and cash equivalents to EBITDA is equal to or higher than 4.5, the interest rate on all amounts then outstanding under the Migdal Loan shall be increased by 0.5% per annum over the interest rate then-applicable to the Migdal Loan.
The Migdal Loan constitutes senior unsecured indebtedness of the Company and will rank equally in right of payment with any existing and future senior unsecured indebtedness of the Company, and effectively junior to any existing and future secured indebtedness, to the extent of the security therefore.
The Migdal Loan Agreement includes various affirmative and negative covenants, including a covenant that the Company maintain (i) a debt to adjusted EBITDA ratio below 6, (ii) a minimum equity amount (as shown on its consolidated financial statements, excluding noncontrolling interests) of not less than $650 million, and (iii) an equity attributable to Company's stockholders to total assets ratio of not less than 25%. In addition, the Migdal Loan Agreement restricts the Company from making dividend payments if its equity falls below $800 million and otherwise restricts dividend payments in any one year to not more than 50% of the net income of the Company of such year as shown on the Company’s consolidated annual financial statements as long as any of the Company's bonds issued in Israel prior to March 27, 2018 remain outstanding. The Migdal Loan Agreement includes other customary affirmative and negative covenants and events of default.
Loan Agreements with DEG (the Olkaria III Complex)
In March 2009, OrPower 4, the Company’s wholly owned subsidiary, entered into a project financing loan of $105.0 million to refinance its investment in Phase I of the Olkaria III complex located in Kenya (the “DEG Loan”). The DEG Loan was provided by a group of European DFIs arranged by DEG. The DEG Loan was to mature on December 15, 2018, and payable in 19 equal semi-annual installments. Interest on the loan was variable based on 6-month LIBOR plus 4.0%. The Company fixed the interest rate on most of the loan at 6.90%. In September 2017, the Company prepaid the outstanding amount of $11.8 million of the DEG Loan, plus an additional prepayment fee of $0.1 million.
On October 20, 2016, OrPower 4 entered into a new $50 million subordinated loan agreement with DEG (the “DEG 2 Loan Agreement”) and on December 21, 2016, OrPower 4 completed a drawdown of the full loan amount of $50 million, with a fixed interest rate of 6.28% for the duration of the loan (the “DEG 2 Loan”). The DEG 2 Loan will be repaid in 20 equal semi-annual principal installments commencing December 21, 2018, with a final maturity date of June 21, 2028. Proceeds of the DEG 2 Loan were used by OrPower 4 to refinance Plant 4 of the Olkaria III Complex, which was originally financed using equity. The DEG 2 Loan is subordinated to the senior loan provided by OPIC for Plants 1-3 of the Olkaria III Complex. The DEG 2 Loan is guaranteed by the Company.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under the DEG 2 Loan Agreement, OrPower 4 may prepay at any time all, or from time to time any part of the DEG 2 Loan in an amount equal to at least $5 million or such lesser amount as may remain outstanding under the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. In certain events, OrPower 4 must make mandatory prepayments of the DEG 2 Loan at 100% of the principal amount to be prepaid plus the applicable make-whole amount and certain prepayment premium amount determined for the prepayment date with respect to such principal amount. The DEG 2 Loan Agreement requires OrPower 4 to comply with certain covenants, including, among others, restrictions on the incurrence of indebtedness or liens. The DEG 2 Loan Agreement also contains customary events of default.
As of December 31, 2018, $47.5 million is outstanding under the DEG 2 Loan.
Revolving credit lines with commercial banks
As of December 31, 2018, the Company has credit agreements with eight commercial banks for an aggregate amount of $468.0 million (including $60.0 million from Union Bank, N.A. (“Union Bank”) and $35.0 million from HSBC), as described below. Under the terms of these credit agreements, the Company, or its Israeli subsidiary, Ormat Systems Ltd. (“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 $233.0 million; and (ii) the issuance of one or more letters of credit in the amount of up to $235.0 million. The credit agreements mature between end of March 2019 and September 2019. 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, 2018, $159.0 million in loans were outstanding, of which $14.1 million are non-committed, and letters of credit with an aggregate stated amount of $229.6 million were issued and outstanding under such credit agreements.
Credit Agreements
Credit agreement with Union Bank
In February 2012, Ormat Nevada Inc. (“Ormat Nevada”), the Company’s wholly owned subsidiary, entered into an amended and restated credit agreement with Union Bank. Under the credit agreement, the credit termination date is June 30, 2019. On December 31, 2018, the aggregate amount available under the credit agreement was $60 million. The facility is limited to the issuance, extension, modification or amendment of 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 lenders. In connection with this transaction, the Company entered into a guarantee in favor of the administrative agent for the benefit of the banks, pursuant to which the Company agreed to guarantee Ormat Nevada’s obligations under the credit agreement. Ormat Nevada’s obligations under the credit agreement are otherwise unsecured.
There are various restrictive covenants under the credit agreement, which include a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2018: (i) the actual 12-month debt to EBITDA ratio was 2.91; (ii) the 12-month DSCR was 2.94; and (iii) the distribution leverage ratio was 1.10. 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, 2018, letters of credit in the aggregate amount of $51.5 million remain issued and outstanding under this credit agreement with Union Bank.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit agreement with HSBC
In May 2013, Ormat Nevada, entered into a credit agreement with HSBC Bank USA, N.A for one year with annual renewals. The current expiration date of the facility under this credit agreement is August 31, 2019. The aggregate amount available under the credit agreement was increased by $10 million to $35 million. Other than the $10 million of this credit facility which may be drawn for our working capital needs, this credit line is limited to the issuance, extension, modification or amendment of letters of credit. HSBC 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 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.
There are various restrictive covenants under the credit agreement, including a requirement to comply with the following financial ratios, which are measured quarterly: (i) a 12-month debt to EBITDA ratio not to exceed 4.5; (ii) 12-month DSCR of not less than 1.35; and (iii) distribution leverage ratio not to exceed 2.0. As of December 31, 2018: (i) the actual 12-month debt to EBITDA ratio was 2.91; (ii) the 12-month DSCR was 2.94; and (iii) the distribution leverage ratio was 1.10. 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 HSBC.
As of December 31, 2018, letters of credit in the aggregate amount of $30.0 million remain issued and outstanding under this credit agreement.
CHUBB Surety Bond
In May 2017, the Company entered into a surety bond agreement (the “Surety Agreement”) with Chubb Limited (“Chubb”) pursuant to which the Company may request that Chubb issue up to an aggregate $200.0 million of surety bonds with respect to the contractual obligations of the Company and its subsidiaries in exchange for bank letters of credit or as otherwise may be required. There is no expiration date for the Surety Agreement, but it may be terminated by the Company at any time upon twenty days’ prior written notice to Chubb. Delivery of such termination notice will not affect any surety bonds issued and outstanding prior to the date on which such notice is delivered. As of December 31, 2018, Chubb issued a surety bond in the amount of $141.1 million under the Surety Agreement.
Restrictive covenants
The Company’s obligations under the credit agreements, the loan agreements, and the trust instrument governing the bonds, described above, are unsecured, but 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 term loan agreements, as well as 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 has agreed to maintain certain financial ratios, which are measured quarterly, such as: (i) equity of at least $600.0 million and in no event less than 25% of total assets; (ii) 12-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio not to exceed 6; and (iii) dividend distribution not to exceed 35% of net income for that year. As of December 31, 2018: (i) total equity was $1,445.1 million and the actual equity to total assets ratio was 46.3%, and (ii) the 12-month debt, net of cash, cash equivalents marketable securities and short-term bank deposits to Adjusted EBITDA ratio was 3.21. During the year ended December 31, 2018, the Company distributed interim dividends in an aggregate amount of $26.8 million.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Future minimum payments
Future minimum payments under long-term obligations, excluding revolving credit lines with commercial banks, as of December 31, 2018 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 original geothermal power plant of the Puna complex located on the Big Island (the “Puna Power Plant”).
Pursuant to a 31-year head lease (the “Head Lease”), PGV leased the Puna 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, 2018 and 2017 amounted to $19.7 million and $25.3 million, net of accumulated depreciation of $33.1 million and $35.6 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 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, 2018, are as follows:
Depository accounts
As required under the terms of the lease agreements, there are certain reserve funds that need to be managed by the indenture trustee in accordance with certain balance requirements. Such reserve funds amounted to $1.3 million and $7.9 million as of December 31, 2018 and 2017, respectively, and were included in restricted cash accounts in the consolidated balance sheets and were classified as current as they were used for current payments.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Distribution account
PGV maintains an account to deposit its remaining cash, after making all of the necessary payments and transfers as provided for in the lease agreements, in order to make distributions to Ormat Nevada. 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, 2018 and 2017, the balance of such account was $0.
NOTE 13 -TAX MONETIZATION TRANSACTIONS
Opal Geo Transaction
On December 16, 2016, Ormat Nevada entered into an equity contribution agreement (the “Equity Contribution Agreement”) with OrLeaf LLC (“OrLeaf”) and JPM with respect to Opal Geo. Also on December 16, 2016, OrLeaf, a newly formed limited liability company formed by Ormat Nevada and ORPD LLC, entered into an amended and restated limited liability company agreement of Opal Geo (the “LLC Agreement”) with JPM. The transactions contemplated by the Equity Contribution Agreement and LLC Agreement will allow the Company to monetize federal PTCs and certain other tax benefits relating to the operation of five geothermal power plants located in Nevada.
In connection with the transactions contemplated by the Equity Contribution Agreement and the LLC Agreement, Ormat Nevada transferred its indirect ownership interest in the McGinness Hills (Phase I and Phase II), Tuscarora, Jersey Valley and second phase of the Don A. Campbell (“DAC 2”) geothermal power plants to Opal Geo. Prior to such transfer, Ormat Nevada held an approximately 63.25% indirect ownership interest in DAC 2 through ORPD LLC, a joint venture between Ormat Nevada and Northleaf Geothermal Holdings LLC (“Northleaf”), an affiliate of Northleaf Capital Partners, and held, directly or indirectly, a 100% ownership interest in the remaining geothermal power plants that were transferred to Opal Geo.
Pursuant to the Equity Contribution Agreement, JPM contributed approximately $62.1 million to Opal Geo in exchange for 100% of the Class B Membership Interests of Opal Geo. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal PTC. The Company expects the aggregate amount of JPM’s deferred capital contributions to equal approximately $21 million and to be paid over time covering the period through December 31, 2022.
Under the LLC Agreement, until December 31, 2022, OrLeaf will receive distributions of 97.5% of any distributable cash generated by operation of the power plants while JPM will receive distributions of 2.5% of any distributable cash generated by operation of the power plants. Unless JPM has already achieved its target internal rate of return on its investment in Opal Geo, from December 31, 2022 until JPM has achieved its target internal rate of return, JPM will receive 100% of any distributable cash generated by operation of the power plants. Thereafter, OrLeaf will receive distributions of 97.5%, and JPM will receive 2.5%, of any distributable cash generated by operation of the power plants.
Under the LLC Agreement, all items of Opal Geo income and loss, gain, deduction and credit (including the federal production tax credits relating to the operation of the two PTC eligible power plants) will be allocated, until JPM has achieved its target internal rate of return on its investment in Opal Geo (and for so long as the two PTC eligible power plants are generating PTCs), 99% to JPM and 1% to OrLeaf, or 5% to JPM and 95% to OrLeaf if PTCs are no longer available to either of the two PTC eligible power plants. Once JPM achieves its target internal rate of return, all items of Opal Geo income and loss, gain, deduction and credit will be allocated 5% to JPM and 95% to OrLeaf.
Under the LLC Agreement, OrLeaf, which owns 100% of the Class A Membership Interests in Opal Geo, will serve as the managing member of Opal Geo and control the day-to-day management of Opal Geo and its portfolio of five power plants. However, in certain limited circumstances (such as bankruptcy of Orleaf, fraud or gross negligence by OrLeaf) JPM may remove OrLeaf as the managing member of Opal Geo. JPM, as the Class B Member of Opal Geo, has consent and approval rights with respect to certain items that are designated as major decisions for Opal Geo and the five power plants. In addition, by virtue of certain provisions in OrLeaf’s own limited liability company agreement, and consistent with the ORPD LLC formation documents, Northleaf has similar consent and approval rights with respect to OrLeaf’s determination of major decisions pertaining to the DAC 2 power plant. In both cases, these major decisions are generally equivalent to customary minority protection rights. As a result, the Company’s wholly owned subsidiary, Ormat Nevada, which serves as the managing member of OrLeaf and as the managing member of ORPD LLC, will effectively retain the day-to-day control and management of Opal Geo and its portfolio of five power plants.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The LLC Agreement contains certain customary restrictions on transfer applicable to both OrLeaf and JPM with respect to their respective Membership Interests in Opal Geo, and also provides OrLeaf with a right of first offer in the event JPM desires to transfer any of its Class B Membership Interests, pursuant to which OrLeaf may purchase such Class B Membership Interests. The LLC Agreement also provides OrLeaf with the option to purchase all of the Class B Membership Interests on either December 31, 2022 or the date that is 9 years after the closing date under the Equity Contribution Agreement at a price equal to the greater of (i) the fair market value of the Class B Membership Interests as of the date of purchase (subject to certain adjustments) and (ii) $3 million.
Pursuant to the Equity Contribution Agreement, the Company has provided a guaranty for the benefit of JPM of certain of OrLeaf’s indemnification obligations to JPM under the LLC Agreement. In addition, Ormat Nevada also provided a guaranty for the benefit of JPM of all present and future payment and performance obligations of OrLeaf under the LLC Agreement and each ancillary document to which OrLeaf is a party.
JPM’s approximately $62.1 million capital contribution to Opal Geo was recorded as a $3.7 million allocation to noncontrolling interests and a $58.5 million allocation to liability associated with sale of tax benefits as described in Note 1. JPM also agreed to make deferred capital contributions to Opal Geo based on the amount of electricity generated by the DAC 2 and McGinness Hills Phase II power plants which are eligible for the federal PTC.
Tungsten Mountain partnership transaction
On May 17, 2018, one of the Company’s wholly-owned subsidiaries that indirectly owns the 26 MW Tungsten Mountain Geothermal power plant entered into a partnership agreement with a private investor. Under the transaction documents, the private investor acquired membership interests in the Tungsten Mountain Geothermal power plant project for an initial purchase price of approximately $33.4 million and for which it will pay additional installments that are expected to amount to approximately $13 million. The Company will continue to operate and maintain the power plant and will receive substantially all the distributable cash flow generated by the power plant.
Under the agreements, prior to December 31, 2026 (“Target Flip Date”), the Company’s fully owned subsidiary, Ormat Nevada Inc. ("Ormat Nevada"), receives substantially all of the distributable cash flow generated by the project, while the private investor receives substantially all of the tax attributes of the project. Following the later of the Target Flip Date and the date in which the private investor reaches its target return, Ormat Nevada will receive 97.5% of the distributable cash and 95.0% of the taxable income, on a going forward basis.
On the Target Flip Date, Ormat Nevada has the option to purchase the private investor’s interests at the then-current fair market value, plus an amount that may be needed to cause the private investor to reach its target return, if needed. If Ormat Nevada exercises this purchase option, it will become the sole owner of the project again.
Other completed tax monetization transactions
On May 31, 2017, the Company’s partners JPM and Morgan Stanley achieved their target after-tax yield on its investment in OPC and on October 31, 2017, Ormat Nevada purchased all of the Class B membership units in OPC from JPM and Morgan Stanley for $1.9 million. As a result, Ormat Nevada is now the sole owner of all of the economic and voting interests in OPC and continues to consolidate OPC in its financial statements. The purchase of Class B membership units of OPC was recorded in equity as a reduction of $6.5 million to Noncontrolling Interest with the surplus of $8.5 million charged to Additional Paid-in Capital.
In March 2017, JPM achieved its target after-tax yield on its investment in ORTP and on July 10, 2017, Ormat Nevada purchased all of the Class B membership units in ORTP from JPM for $2.4 million. As a result, Ormat Nevada is now the sole owner of all of the economic and voting interests in ORTP and continues to consolidate ORTP in its financial statements. The purchase of Class B membership units of ORTP was recorded in equity as a reduction to Noncontrolling Interest of $7.0 million with the surplus of $ $2.9 million charged to Additional Paid-in Capital.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2018, the total future compensation cost related to unvested stock-based awards that are expected to vest is $17.0 million, which will be recognized over a weighted average period of 1.3 years.
During the years ended December 31, 2018, 2017 and 2016, the Company recorded compensation related to stock-based awards as follows:
During the fourth quarters of 2018, 2017 and 2016, the Company evaluated the trends in the stock-based award forfeiture rate and determined that the actual rates are 5.3%, 1.1% and 10.3%, respectively. This represents an increase of 381.8%, a decrease of 89.3%, and an increase of 7%, respectively, from prior estimates. As a result of the change in the estimated forfeiture rate, there was an immaterial impact on stock-based compensation expense for each of the respective periods.
Valuation assumptions
Prior to 2016, the fair value of each grant of stock-based awards was estimated using the Black-Scholes valuation model. The Company’s expected term represented the period that the Company’s stock-based awards were 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. Starting in 2016, the Company estimated the fair value of the stock-based awards using the Exercise Multiple-Based Lattice Model as it enables a degree of accounting for the complexities of option valuation and reduces the probability of a measurement error. The dividend yield forecast is expected to be 20% of the Company’s yearly net profit, which is equivalent to a 0.9% yearly weighted average dividend rate in the year ended December 31, 2018. 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:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-based awards
The 2012 Incentive Compensation Plan
In May 2012, the Company’s shareholders adopted the 2012 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 2012 Incentive Plan, a total of 4,000,000 shares of the Company’s common stock were 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 2012 Incentive Plan typically vest and become exercisable as follows: 25% vest 24 months after the grant date, an additional 25% vest 36 months after the grant date, and the remaining 50% vest 48 months after the grant date. Options granted to non-employee directors under the 2012 Incentive Plan will vest and become exercisable one year after the grant date. Restricted stock units granted to directors and members of senior management vest according to a vesting schedule as follows: for the directors, 100% on the first anniversary of the grant date and for members of senior management, 25% on each of the first, second, third and fourth anniversaries of the grant date. The term of stock-based awards typically ranges from six to ten years from the grant date. The shares of common stock issued in respect of awards under the 2012 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs. The 2012 Incentive Plan expired in May 2018 upon adoption of the 2018 Incentive Compensation Plan (“2018 Incentive Plan”), except as to stock-based awards outstanding under the 2012 Incentive Plan on that date.
The 2018 Incentive Compensation Plan
On May 7, 2018, the Company held its 2018 Annual Meeting of Stockholders at which the Company's stockholders approved the 2018 Incentive Plan. The 2018 Incentive Plan provides for the grant of the following types of awards: incentive stock options, restricted stock units (“RSUs”), 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 2018 Incentive Plan, a total of 5,000,000 shares of the Company’s common stock were authorized and reserved for issuance, all of which could be issued as options or as other forms of awards. SARs and RSUs granted to employees under the 2018 Incentive Plan typically vest and become exercisable as follows: 50% on the second anniversary of the grant date and 25% on each of the third and fourth anniversaries of the grant date. SARs and Restricted stock units granted to directors under the 2018 Incentive Plan typically vest and become exercisable (100%) on the first anniversary of the grant date. The term of stock-based awards typically ranges from six to ten years from the grant date. The shares of common stock issued in respect of awards under the 2018 Incentive Plan are issued from the Company’s authorized share capital upon exercise of options or SARs.
On June 13, 2016, the Company granted its employees, an aggregate of 1,080,000 SARs under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $42.87, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire six years from the date of the grant and will vest over 4 years as follows: 50% after two years; an additional 25% after three years and the remaining 25% after four years from the grant date.
The fair value of each SAR on the grant date was $11.98 for senior management and $11.42 for other employees. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On November 8, 2016, the Company granted its directors, an aggregate of 60,000 SARs under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $47.46, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire seven years from the date of the grant and will vest at the end of the first year from the grant date.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each SAR on the grant date was $14.51. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On June 7, 2017, the Company granted its employees, an aggregate of 23,200 SAR’s under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $58.79, which represented the fair market value of the Company’s common stock on the grant date. Such SARs will expire five years from the date of the grant. Such SARs will vest according to a vesting schedule as follows: 50% on the first anniversary of the grant date and 25% on each of the third and fourth anniversaries of the grant date.
The fair value of each SAR on the grant date was $13.67. The Company calculated the fair value of each SAR on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On August 4, 2017, the Company granted its directors, an aggregate of 30,000 options under the Company’s 2012 Incentive Plan. The exercise price of each option is $57.97, which represented the fair market value of the Company’s common stock on the grant date. Such options will expire seven years from the date of the grant and will fully vest one year from the grant date.
The fair value of each option on the grant date was $18.42. The Company calculated the fair value of each option on the grant date using the Exercise Multiple-Based Lattice SAR-Pricing model based on the following assumptions:
On November 8, 2017, the Company granted its directors and members of its senior management an aggregate of 108,771 SARs and 22,742 Restricted Stock Units (“RSUs”) under the Company’s 2012 Incentive Plan. The exercise price of each SAR is $63.35, which represented the fair market value of the Company’s common stock on the grant date. Such SARs and RSUs will expire in six years and will vest according to a vesting schedule as follows: for the directors, 100% on the first anniversary of the grant date and for members of senior management, 25% on each of the first, second, third and fourth anniversaries of the grant date.
The fair value of each SAR for the directors and members of senior management on the grant date was $17.6 and $17.7, respectively. The fair value of each RSU for the directors and members of senior management on the grant date was $62.9 and $62.3, respectively. The Company calculated the fair value of each SAR and RSU on the grant date using the Exercise Multiple-Based Lattice Pricing model based on the following assumptions:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On May 8, 2018, the Company granted an aggregate of 295,671 SARs and 40,489 RSUs to the CEO and one of the directors under the Company’s 2018 Incentive Plan. The exercise price of each SAR is $55.16, which represented the fair market value of the Company’s common stock on the grant date. The SARs and RSUs will expire in five and a half years from the date of grant and will vest according to a vesting schedule as follows: for the director, 100% after a half year from the grant date and for the CEO, 22% on the half year and one and a half year from the grant date and 28% on the two and a half and three and a half year from the grant date.
The fair value of each SAR for the director and the CEO on the grant date was $14.56 and $14.57, respectively. The fair value of each RSU for the director and the CEO on the grant date was $54.92 and $54.23, respectively. The Company calculated the fair value of each SAR and RSU on the grant date using the Exercise Multiple-Based Lattice Pricing model based on the following assumptions:
On June 25, 2018, the Company granted its employees and members of its senior management an aggregate of 841,117 SARs and 19,848 RSUs under the Company’s 2018 Incentive Plan. The exercise price of each SAR is $53.44, which represented the fair market value of the Company’s common stock on the grant date. The SARs and RSUs will expire in six years from the date of grant and will vest according to a vesting schedule as follows: 50% on the second anniversary of the grant date and 25% on each of the third and fourth anniversaries of the grant date.
The fair value of each SAR for the employees and members of senior management on the grant date was $13.82 and $14.64, respectively. The fair value of each RSU for the members of senior management on the grant date was $52.09, respectively. The Company calculated the fair value of each SAR and RSU on the grant date using the Exercise Multiple-Based Lattice Pricing model based on the following assumptions:
On November 7, 2018, the Company granted its directors and employees an aggregate of 35,395 SARs and 13,688 Restricted Stock Units (“RSUs”) under the Company’s 2018 Incentive Plan. The exercise price of each SAR was $53.16 which represented the fair market value of the Company’s common stock on the grant date. Such SARs and RSUs will expire in six years and will vest according to a vesting schedule as follows: for the directors, 100% on the first anniversary of the grant date and for the employees, 50% on the second anniversary of the grant date and 25% on each of the third and fourth anniversaries of the grant date.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each SAR for the directors and employees on the grant date was $14.8 and $14.0, respectively. The fair value of each RSU for the directors on the grant date was $52.6. The Company calculated the fair value of each SAR and RSU on the grant date using the Exercise Multiple-Based Lattice Pricing model based on the following assumptions:
*
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.
**
An RSU represents the right to receive one share of common stock once certain vesting conditions are met. The value of an RSU is identical to the value of the underlying stock.
As of December 31, 2018, 3,605,740 shares of the Company’s common stock are available for future grants under the 2018 Incentive Plan. No shares of the Company’s common stock are available for future grants under the 2012 and 2004 Incentive Plan as of such date.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock-based awards outstanding at December 31, 2018 (shares in thousands):
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about stock-based awards outstanding at December 31, 2017 (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 $52.30 and $63.96 as of December 31, 2018 and 2017, 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 awards exercisable as of December 31, 2018 and 2017 was 846,215 and 431,387, respectively.
The total pretax intrinsic value of options exercised during the year ended December 31, 2018 and 2017 was $5.2 million and $38.9 million, respectively, based on the average stock price of $55.58 and $58.82 during the years ended December 31, 2018 and 2017, respectively.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, Guatemala, Guadeloupe and Honduras. 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 2019 to 2043. 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, 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 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 in delivery of renewable energy and energy credits, and not meeting certain performance threshold requirements, as defined in the relevant PPA. The amount of payment required is dependent upon the level of shortfall in 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 evaluated whether such PPAs contained a lease element requiring lease accounting. Future lease revenues under PPAs which contain a lease element as of December 31, 2018 including the PPAs that provide for minimum production or performance guarantees are accounted for as contingent lease revenues as they are production-based payments and contingent on generation levels that are impacted by climatic variables that are inherently uncertain including geological conditions and ambient temperature. The PPAs considered to be leases were also assessed for inclusion of embedded derivatives, which required that they be separately accounted for at fair value. However, none of such PPAs were determined to include embedded derivatives.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 17 - INTEREST EXPENSE, NET
The components of interest expense are as follows:
NOTE 18 - INCOME TAXES
U.S. and foreign components of income from continuing operations, before income taxes and equity in income (losses) of investees consisted of:
The components of the provision (benefit) for income taxes, net are as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation of the U.S. federal statutory tax rate to the Company’s effective income tax rate is as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The net deferred tax assets and liabilities consist of the following:
The following table presents a reconciliation of the beginning and ending valuation allowance:
At December 31, 2018, the Company had U.S. federal net operating loss (“NOL”) carryforwards of approximately $230.5 million. The Company had $224.5 million generated before December 31, 2017 which expire between 2027 and 2037, and $6.0 million are available to be carried forward for an indefinite period. The Company had state NOL carryforwards of approximately $269.1 million, $264.7 million which expire between 2025 and 2038 and $3.3 million are available to be carried forward for an indefinite period. The state tax credits in the amount of $0.8 million at December 31, 2018 are available to be carried forward for an indefinite period. The Production Tax Credits (“PTCs") in the amount of $90.9 million at December 31, 2018 are available for a 20-year period and expire between 2026 and 2038. The Foreign Tax Credits (“FTCs”) in the amount of $58.1 million at December 31, 2018 are available for a 10-year period and begin to expire in 2027.
The Company has recorded deferred tax assets for net operating losses, foreign tax credits, and production tax credits. Realization of the deferred tax assets and tax credits is dependent on generating sufficient taxable income in appropriate jurisdictions prior to expiration of the NOL carryforwards and tax credits. Based upon available evidence of the Company’s ability to generate additional taxable income in the future and historical losses in prior years, a valuation allowance in the amount of $22.4 million and $77.6 million is recorded against the U.S. deferred tax assets as of December 31, 2018 and 2017, respectively, as it is more likely than not that the deferred tax assets will not be realized. The overall decrease in the valuation allowance of $55.1 million is due to (i) write-off of foreign tax credits due to new refinements in 965 regulations and related valuation allowance on such credits (ii) true-up of foreign tax credits due to refined transition tax calculation and (iii) new available evidence that has refined the Company’s calculations in regards to the Tax Act which is expected to result in additional taxable income in the US. The Company is maintaining a valuation allowance of $22.4 million against a portion of the U.S. foreign tax credits and state NOLs that are expected to expire before they can be utilized in future periods.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On April 24, 2018, the Company acquired 100% of stock of USG for approximately $110 million. Under the acquisition method of accounting, the Company recorded a net deferred tax asset of $1.7 million comprised primarily of federal and state NOLs netted against deferred tax liabilities for partnership basis differences and fixed assets. The total amount of acquired federal and state NOLs, which are subject to limitations under Section 382, were $115.2 million and $49.9 million, respectively. A valuation allowance of $2.1 million has been recorded against such acquired state NOLs, as it is more likely than not that the deferred tax asset will not be realized.
On December 22, 2017, the U.S. government signed into law the Tax Act. The Tax Act makes significant changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate income tax rate from 35 percent to 21 percent; (2) the transition of U.S. international taxation from a worldwide tax system to a territorial system (GILTI, BEAT, Dividends Received Deduction); (3) one-time transition tax on undistributed earnings of foreign subsidiaries as of December 31, 2017; (4) eliminating the corporate alternative minimum tax; (5) creating a new limitation on deductible interest expense; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017.
The Company applied the guidance of SAB 118 for the effects of the Tax Act in 2017 and throughout 2018. We completed our analysis to determine the effect of the Tax Act during December 2018. The Deemed Repatriation Tax (Transition Tax) is a tax on previously untaxed accumulated and current earnings and profits (E&P) of certain foreign subsidiaries. To determine the amount of the Transition Tax, we determined, in addition to other factors, the amount of post-1986 E&P of the relevant subsidiaries, as well as the amount of non-U.S. income taxes paid on such earnings. As a result of our initial analysis of the impact of the Act, we recorded a provisional amount of Transition Tax inclusion of $71.9 million. We completed our accounting for such items during 2018 and recorded a final Transition Tax inclusion of $64.2 million. The Company has sufficient NOLs to offset such earnings, therefore there is no resulting obligation due for such amount. In addition, the Company finalized its accounting related to the remeasurement of deferred taxes which resulted in a decrease of $3.5 million to the provisional benefit of $22.6 million recorded in 2017.
The FASB released guidance Staff Q&A, Topic 740, No. 5, that states a company can make an accounting policy election to either recognize deferred taxes related to GILTI or to provide for the GILTI tax expense in the year the tax is incurred as a period cost. The Company has elected to treat any GILTI inclusions as a period cost.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the deferred taxes on the balance sheet as of the dates indicated:
(1) The non-current deferred tax asset has been reduced by the uncertain tax benefit of $0.1 million in accordance with ASU 2013-11, Income Taxes.
During 2017, the Company changed its intention to reinvest certain undistributed earnings of Ormat Systems Ltd., a wholly owned subsidiary in Israel. In the prior year, the Company distributed $396.0 million, of which $300.0 million was received in December 2017 and the remaining $96.0 million was received in December 2018. The Company recorded the tax impact of the distribution received in 2018 as part of the 2017 financials, including the 15% Israeli withholding tax in the amount of $14.4 million and corresponding foreign tax credit tax benefit, net of valuation allowance. In accordance with the Company’s assertion to distribute certain earnings of Ormat Systems Ltd. as of December 31, 2018, the Company recorded a deferred tax liability on withholding taxes of approximately $8.1 million and foreign tax credits of $2.2 million on anticipated earnings to be remitted of $53 million. Foreign tax credits of $2.2 million is recorded on the withholding taxes which is subject to valuation allowance based on the Company’s projected ability to utilize such foreign tax credits in the U.S. prior to the 10-year expiration period.
The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $211.3 million at December 31, 2018. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, the Company has not recorded a deferred tax liability on foreign earnings other than for OSL. The additional taxes on that portion of undistributed earnings which is available for dividends are not practicably determinable.
Uncertain tax positions
We are subject to income taxes in the U.S. (federal and state) and numerous foreign jurisdictions. Significant judgment is required in evaluating our tax positions and determining our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. We establish reserves for tax-related uncertainties based on estimates of whether, and the extent to which additional taxes will be due. These reserves are established when we believe that certain positions might be challenged despite evidence supporting the position. We adjust these reserves in light of changing facts and circumstances, such as the outcome of tax audits. The provision for income taxes includes the impact of reserve positions and changes to reserves that are considered probable.
At December 31, 2018 and 2017, there are $11.8 million and $8.9 million of unrecognized tax benefits that if recognized would affect the annual effective tax rate. 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 our unrecognized tax benefits is as follows:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company and its U.S. subsidiaries file consolidated income tax returns for federal and state purposes. As of December 31, 2018, 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 2002-2017 and by local state jurisdictions for the years 2004-2017. These examinations may lead to ordinary course adjustments or proposed adjustments to our taxes or our net operating losses with respect to years under examination as well as subsequent periods.
The reduction of $0.3 million, $0.8 million, and $5.4 million in 2018, 2017, and 2016, respectively, was due to the statute of limitations expiration on certain tax positions as well as Ormat System's tax settlement as detailed below.
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. On February 9, 2018 the Bipartisan Budget Act of 2018 was enacted extending the PTC and ITC in lieu of PTCs for geothermal projects that begin construction before 2018. Geothermal projects that begin construction before 2018 and meet certain other “begun construction” rules qualify for 2.4 cents per kilowatt hour of PTCs for their first 10-years of operations; alternatively, the owner of the project may elect a 30% ITC in lieu of PTCs. In either case, under current tax rules for tax credits generated before January 1, 2018, any unused tax credit has a 1-year carry back and a 20-year carry forward.
If the Company claims the ITC, the Company’s “tax base” in the plant that it can recover through bonus or accelerated depreciation (if elected) must be reduced by half of the ITC. If the Company claims the PTC, there is no reduction in the tax basis for depreciation. Whether the Company claims the PTC or the ITC in lieu of PTC, for assets acquired and placed in service after September 27, 2017, the Company is permitted to fully expense the cost of qualified property (“bonus depreciation”). In later years, the first-year bonus depreciation deduction phases down, as follows:
● 80% for property placed in service after Dec. 31, 2022 and before Jan. 1, 2024.
● 60% for property placed in service after Dec. 31, 2023 and before Jan. 1, 2025.
● 40% for property placed in service after Dec. 31, 2024 and before Jan. 1, 2026.
● 20% for property placed in service after Dec. 31, 2025 and before Jan. 1, 2027.
The Company could also elect in lieu of bonus deprecation 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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income taxes related to foreign operations
Guatemala - The enacted tax rate is 25%. 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. Starting August 2017, Ortitlan pays income tax of 7% on its Electricity revenues. The effect of the tax exemption in the years ended December 31, 2018, 2017, and 2016 is $2.0 million, $2.6 million, and $3.3 million, respectively ($0.04, $0.05, and $0.07 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 26.5% in 2015, 25% in 2016, 24% in 2017 and 23% in 2018 and thereafter. 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. 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 16% in 2014 and thereafter. Ormat Systems decided to irrevocably comply with the new law starting in 2011. In the event of distribution of a cash dividend out of retained earnings which were tax exempt due to prior benefits, Ormat Systems would have to pay tax in respect of the amount distributed. Since the exemptions are contingent upon nondistribution of dividends and since upon liquidation the Company will have to pay a 25% tax on exempt income, Ormat Systems recorded deferred tax liability at the rate of 25% in respect of the tax exempt income in 2004-2008. In the event that Ormat Systems fails to comply with the program terms, the tax benefits may be canceled and it may be required to refund the amount of the benefits utilized, in whole or in part, with the addition of linkage differences and interest.
Kenya - The Company’s operations in Kenya are taxed at the rate of 37.5%. On September 11, 2015, Kenya's Income Tax Act was amended pursuant to certain provisions of the recently adopted Finance Act, 2015. Among other matters, these amendments retain the enhanced investment deduction of 150% under Section 17B of the Income Tax Act, extend the period for deduction of tax losses from 5 years to 10 years under Sections 15(4) and 15(5) of the Income Tax Act, and amend the effective date from January 1, 2016 to January 1, 2015 under Sections 15(4) and 15(5) of the Income Tax Act.
During the fourth quarter of 2018, the Kenya Revenue Authority (“KRA”) notified the Company’s subsidiary in Kenya of their intention to conduct an audit primarily focusing on related parties transactions for the years 2014-2017. The Company has submitted all of the required documents and further discussions with the KRA are currently underway.
As previously reported by the Company, the KRA conducted an audit related to the Company’s operations in Kenya for fiscal years 2012 and 2013. On June 20, 2017, the Company has signed a Settlement Agreement with the KRA under which it paid approximately $2.6 million in principal for full settlement of all claims raised by the KRA during the audit. The principal amount that was paid in June 2017 was recorded as an addition to the cost of the power plants and is qualified for investment deduction at 150% under the terms of the settlement agreement. Additionally, as per the Settlement Agreement, the Company submitted a request for waiver on the applied interest in the amount of approximately $1.2 million, for which the Company recorded a provision to cover such a potential exposure.
Guadeloupe - The Company’s operations in Guadeloupe are taxed at a rate of 34.43% in 2017, a maximum rate of 33.3% in 2018, a maximum rate 31% in 2019, a rate of 28% in 2020, 26.5% in 2021 and 25% in 2022.
Honduras - The Company’s operations in Honduras are exempt from income taxes for the first ten years starting at the commercial operation date of the power plant.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other significant foreign countries - The Company’s operations in New Zealand are taxed at the rate of 28% that is applied on certain qualified costs basis in 2018 and 2017.
Income taxes related to U.S. tax legislation commonly referred to as the Tax Cuts and Jobs Act
On December 22, 2017, the U.S. government signed into law the Tax Act. The Tax Act makes significant changes to the U.S. tax code, including, but not limited to, (1) reducing the U.S. federal corporate income tax rate from 35 percent to 21 percent; (2) the transition of U.S. international taxation from a worldwide tax system to a territorial system (GILTI, BEAT, Dividends Received Deduction); (3) one-time transition tax on undistributed earnings of foreign subsidiaries as of December 31, 2017; (4) eliminating the corporate alternative minimum tax; (5) creating a new limitation on deductible interest expense; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 19 - BUSINESS SEGMENTS
In 2018, the Company started disclosing its energy storage and power load management business activity under the Other segment as such operations met the reportable segment criteria of ASC 280, Segment Reporting. As such, starting in 2018 the Company has three reporting segments: the Electricity segment, the Product segment and the Other segment. These 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. The Other segment is engaged in management of curtailable customer loads under contracts with U.S. retail energy providers and directly with large commercial and industrial customers as well as battery storage as a service.
Transfer prices between the operating segments were determined on current market values or cost plus markup of the seller’s business segment.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized financial information concerning the Company’s reportable segments is shown in the following tables, including, as further described under Note 1 to the consolidated financial statements, the Company's disaggregated revenues from contracts with customers as required by ASC 606:
(1)
Electricity segment revenues in the United States are all accounted under ASC 840, Leases, except for $26.9 million for the year ended December 31, 2018 that are accounted under ASC 606 starting in 2018. Product and Other segment revenues in the United States are accounted under ASC 606, as further described under Note 1 to the consolidated financial statements.
(2)
Electricity segment revenues in foreign countries are all accounted under ASC 840, Leases, and Product revenues in foreign countries are accounted under ASC 606 as further described under Note 1 to the consolidated financial statements.
(3)
Electricity segment assets include goodwill in the amount of $20.0 million and $7.6 million as of December 31, 2018 and 2017, respectively. Other segment assets include goodwill in the amount of $0 million and $13.5 million as of December 31, 2018 and 2017, respectively. For further information on goodwill, see Note 9 - Intangible assets and goodwill to the consolidated financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciling information between reportable segments and the Company’s consolidated totals is shown in the following table:
The Company sells electricity and products for power plants and others, mainly to the geographical areas according to location of the customers, as detailed below. The following tables present certain data by geographic area:
(1)Revenues as reported in the geographic area in which they originate.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents revenues from major customers:
(1)Revenues reported in Electricity segment.
(2)Subsidiaries of NV Energy, Inc.
(3)Revenues related to the Sarulla project that are reported in Product segment.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 20 - TRANSACTIONS WITH RELATED ENTITIES
There were no transactions between the Company and related entities, other than those disclosed elsewhere in these financial statements.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 21 - 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. In 2018, 2017 and 2016, contributions made by the Company were matched up to a maximum of 4%, 3% and 2% of the employee’s annual salary, respectively. The Company’s contributions to the Plan were $1.6 million, $1.4 million, and $1.0 million for the years ended December 31, 2018, 2017, and 2016, 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 recorded at each balance sheet date by determining the undiscounted obligation as if it were payable at that point in time. 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 $10.6 million and $13.9 million at December 31, 2018 and 2017, 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, 2018, 2017, and 2016 were $3.0 million, $3.2 million, and $2.3 million, respectively, which are net of income (including loss) amounting to $(1.1) million, $1.8 million, and $0.3 million, respectively, generated from the regular deposits and amounts accrued in severance funds.
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.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 22 - COMMITMENTS AND CONTINGENCIES
Geothermal resources
The Company, through its project subsidiaries in the U.S., controls certain rights to geothermal fluids through certain leases with the 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 $21.6 million, $19.4 million, and $17.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.
Letters of credit
In the ordinary course of business with customers, vendors, and lenders, the Company is contingently liable for performance under letters of credit totaling $229.6 million at December 31, 2018. 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, 2018, total obligations related to such supplier agreements were approximately $129.3 million (out of which approximately $36.1 million relate to construction-in-process). All such obligations are payable in 2019.
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, 2018, 2017, and 2016. 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, 2018 and 2017, amounted to $2.0 million and $1.9 million, respectively, of which approximately $1.0 million and $0.9 million, respectively, represents interest based on the LIBOR rate, as defined above.
Lease commitments
The Company entered into lease transactions for a fleet of vehicles. The lease transactions are classified as capital leases and the leased vehicles are classified under Property, Plant and Equipment in the total amount of $7.5 million and $3.6 million as of December 31, 2018 and 2017, respectively, representing the cost of vehicles under such transactions net of the related accumulated depreciation. The terms of the lease are monthly payments in equal installments over 5 years. The following table summarizes the minimum lease rentals for the following five years:
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a schedule by years of future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2018.
Contingencies
●
On May 21, 2018, a motion to certify a class action was filed in Tel Aviv District Court against Ormat Technologies, Inc. and 11 officers and directors, by the name of Heit vs. Ormat Technologies, et al. The alleged class is defined as "All persons who purchased Ormat shares on the Tel Aviv Stock Exchange between August 3, 2017 and May 13, 2018". The motion alleges that the Company violated Sections 31(a)(1) and 38C of the Israeli Securities Law because it allegedly: (1) misled investors by stating in its financial statements that it maintains effective internal controls over its accounting policies and procedures, however the Company's internal controls had material weaknesses which led to erroneous accounting in its 2017 unaudited quarterly reports that had to be restated, including adjustments to the Company’s net income and shareholders’ equity; and (2) failed to issue an immediate report in Israel until May 16, 2018, analogous to the report that was released in the United States on May 11, 2018 stating, inter alia, that the errors in its financial reports affected its balance sheet and would be remedied in its 2017 annual report. The Tel Aviv District Court has stayed the proceedings in Israel until a final decision in the U.S. putative class action case (Mac Costas below) of related subject matter is adjudicated. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
●
On June 11, 2018, a putative class action was filed by Mac Costas on behalf of alleged shareholders that purchased or acquired the Company's ordinary shares between August 8, 2017 and May 15, 2018 was commenced in the United States District Court for the District of Nevada against the Company and its Chief Executive Officer and Chief Financial Officer. The complaint asserts claims against all defendants pursuant to Section 10(b) of the Exchange Act, as amended, and Rule 10b-5 thereunder and against its officers pursuant to Section 20(a) of the Exchange Act. The complaint alleges that the Company's Form 10-K for the years ended December 31, 2016 and 2017, and Form 10-Qs for each of the quarters in the nine months ended September 30, 2017 contained material misstatements or omissions, among other things, with respect to the Company’s tax provisions and the effectiveness of its internal control over financial reporting, and that, as a result of such alleged misstatements and omissions, the plaintiffs suffered damages. Following the Mac Costas claim filing, four additional complaints of similar content were filed by other complainants. As described below, this action has been consolidated with the derivative action of related subject matter. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
●
On September 11, 2018, the Klein derivative action was filed against the Company, our board and our CEO and CFO in the United States District Court for the District of Nevada, and on October 22, 2018, the Matthew derivative action was filed in the same court against the company, certain named present and former board members (Barniv, Beck, Boehm, Clark, Falk, Freedland, Granot, Joyal, Nishigori, Sharir, Stern and Wong) in the United States District Court, District of Nevada. Pursuant to a stipulation granted by the court, these derivative and the putative class actions described above (Mac Costas) have been consolidated, the derivative actions stayed pending a court ruling on an anticipated motion to dismiss the putative class actions, and service requirements waived by the Company and three US based directors. The Klein complaint asserts four derivative causes of action generally arising from Ormat's restatement of its financial statements: (i) the individual defendants allegedly breached their fiduciary duties by allowing the company to improperly report its financials; (ii) the individual defendants allegedly were unjustly enriched by being compensated while breaching their fiduciary duties; (iii) the individual defendants allegedly committed corporate waste in paying officers and directors and by incurring legal costs and potential liability; and (iv) the director defendants allegedly breached Section 14(a) of the Exchange Act in connection with the issuance of 2018 proxy. The Matthew complaint similarly alleges derivatively a breach of fiduciary duties, abuse of control, gross mismanagement, and corporate waste by the named directors. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
●
Following the announcement of the Company’s acquisition of USG, a number of putative shareholder class action complaints were initially filed on behalf of USG shareholders between March 8, 2018 and March 30, 2018 against USG and the individual members of the USG board of directors. All of the purported class action suits filed in Federal Court in Idaho have been voluntarily dismissed. The single remaining class action complaint is a purported class action filed in the Delaware Chancery Court, entitled Riche v. Pappas, et al., Case No. 2018-0177 (Del. Ch., Mar. 12, 2018). An amended complaint was filed on May 24, 2018 under seal, under a confidentiality agreement that was executed by plaintiff. The amended Riche complaint alleges state law claims for breach of fiduciary duty against former USG directors and seeks post-closing damages. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
●
On February 18, 2018, Western Watersheds Project ("WWP") filed a notice of appeal and petition for standing with respect to the January 16, 2018 BLM decision approving Addendum 2 to Operation Plan & Utilization Plan for the McGinness Hills Geothermal Project. The appeal alleges that the January 2018 BLM decision authorizing construction and operation of Phase 3 of McGinness Hills causes harm to WWP and its members by allowing degradation of the wildlife habitat of the Greater sage-grouse in that area. The Company has filed a motion to intervene as an interested party in support of the BLM. The litigation was resolved and the settlement for an immaterial amount was approved by the Interior Board of Land appeals.
●
On August 5, 2016, George Douvris, Stephanie Douvris, Michael Hale, Cheryl Cacocci, Hillary E. Wilt and Christina Bryan, acting for themselves and on behalf of all other similarly situated residents of the lower Puna District, filed a complaint in the Third Circuit Court for the State of Hawaii seeking certification of a class action for preliminary and permanent injunctive relief, consequential and punitive damages, attorney’s fees and statutory interest against PGV and other presently unknown defendants. On December 12, 2016, the District Court granted plaintiffs’ motion for joinder of HELCO as a co-defendant, and the case, which had been removed prior to the U.S. District Court for the District of Hawaii, was remanded back to the Third Circuit Court. The amended complaint purports that injuries and other damages in an undisclosed amount were caused to the plaintiffs as a result of an alleged toxic release by PGV in the wake of Hurricane Iselle in August 2014. On June 14, 2017, the Third Circuit Court denied HELCO’s motion to dismiss the complaint against itself which it had filed on March 25, 2017 and agreed to the Company’s request to add two third party defendants, who are, respectively, the distributor and manufacturer of the pressure release valve that failed to reseat during Hurricane Iselle. Discovery and depositions took place during the course of 2018 and, in January 2019, the case was again removed back to the U. S. District Court for the District of Hawaii. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
●
On March 29, 2016, a former local sales representative in Chile, Aquavant, S.A., filed a claim on the basis of unjust enrichment against Ormat’s subsidiaries in the 27th Civil Court of Santiago, Chile. The claim requests that the court order Ormat to pay Aquavant $4.6 million in connection with its activities in Chile, including the EPC contract for the Cerro Pabellon project and various geothermal concessions, plus 3.75% of Ormat geothermal products sales in Chile over the next 10 years. Pursuant to various motions submitted by the defendants and the plaintiffs to various courts, including the Court of Appeals, the case was removed from the original court and then refiled before the 11th Civil Court of Santiago. The evidentiary period has concluded before the Civil Court on the basis of the court’s “statement of facts” to be proved. The Company believes that it has valid defenses under law and intends to defend itself vigorously.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In addition, from time to time, the Company is named as a party to various other 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, the Company accrues reserves when a loss is probable and the amount of such loss can be reasonably estimated. It is the opinion of the Company’s management that the outcome of these proceedings, individually and collectively, will not be material to the Company’s consolidated financial statements as a whole.
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 23 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
ORMAT TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 24 - SUBSEQUENT EVENTS
Cash dividend
On February 26, 2019, the Company’s Board of Directors declared, approved and authorized payment of a quarterly dividend of $5.6 million ($0.11 per share) to all holders of the Company’s issued and outstanding shares of common stock on March 14, 2019, payable on March 28, 2019.
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
Evaluation of disclosure controls and procedure. Our management, including our Chief Executive Officer and Chief Financial Officer, have conducted the evaluation of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) required by Rules 13a-15(b) or 15d-15(b) under the Exchange Act, as amended. Based on that evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were not effective as of December 31, 2018 as a result of a material weakness in the Company’s internal control over financial reporting that existed at December 31, 2017 and has not been remediated by the end of the period covered by this Annual Report on Form 10-K.
Management’s Report on Internal Control over Financial Reporting
Our management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as described in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended, or the Exchange Act. Internal control over financial reporting is defined as a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, 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 and includes those policies and procedures that: (1) Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer, (2) 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 issuer are being made only in accordance with authorizations of management and directors of the issuer and (3) Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’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 our conditions, or that the degree of compliance with our policies or procedures may deteriorate.
Evaluation of effectiveness of internal control over financial reporting Our management, under the supervision and participation of our Chief Executive Officer and our Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2018 using criteria established in Internal Control - Integrated Framework (2013) issued by the COSO and, based on this evaluation, concluded that our internal control over financial reporting was not effective as of December 31, 2018 as a result of the material weakness in our internal control over financial reporting discussed below. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
Material weakness. In connection with the change in our repatriation strategy and the related release of the US income tax valuation allowance in the second quarter of 2017, we did not perform an effective risk assessment related to our internal controls over the accounting for income taxes. As a result, we identified a deficiency in the design of our internal control over financial reporting related to our accounting for income taxes, which resulted in the restatements of the Company’s unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017, the three and nine months ended September 30, 2017, and the restatement of the Company’s consolidated financial statements for the year ended December 31, 2017. Our management has concluded that this deficiency constitutes a material weakness in our internal control over financial reporting.
In Management’s Report on Internal Control Over Financial Reporting included in our original Annual Report on Form 10-K for the year ended December 31, 2017, our management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2017 because of the material weakness described above. As a result, we concluded that we did not maintain an effective internal control over financial reporting as of December 31, 2017, based on the criteria in Internal Control-Integrated Framework (2013) issued by the COSO.
Remediation Plan
Subsequent to the evaluation made in connection with filing our Amended Annual Report on Form 10-K for the year ended December 31, 2017, our management, with the oversight of the Audit Committee of the Board of Directors, has continued the process of remediating the material weakness. In connection with the remediation process, we have:
●
performed an enhanced risk assessment related to our internal controls over the accounting for income taxes;
●
recruited additional tax personnel throughout the year, including a VP of Tax in January 2019;
●
engaged an external tax and accounting firm to prepare and review our annual and quarterly income tax provision;
●
implemented specific control procedures for the review, analysis and reporting of our income tax accounts, including control procedures of projections that support the deferred tax assets and liabilities;
●
strengthened our income tax controls with improved documentation, communication and oversight.
We have made substantial progress in accordance with our remediation plan. However, the material weakness will not be considered remediated until the applicable controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. As such, since an appropriate period of time has not yet passed, we have determined that we did not maintain an effective internal control over financial reporting as of December 31, 2018 and have a material weakness in internal control over financial reporting in accounting for income taxes.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting in the fourth quarter of 2018 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
The following table sets forth the name, age and positions of our directors, executive officers and persons who are executive officers of certain of our subsidiaries who perform policy making functions for us:
Name Age Position
Todd C. Freeland
Chairman of the Board of Directors and Independent Director (1)
Byron G. Wong
Independent Director (1)
Dan Falk
Independent Director (1)
Stanley B. Stern
Independent Director (2)
Yuichi Nishigori
Independent Director (2)
David Granot
Independent Director (2)
Ravit Barniv
Independent Director (3)
Stan H. Koyanagi
Independent Director (3)
Dafna Sharir
Independent Director (3)
Isaac Angel
CEO*
Doron Blachar
CFO*
Zvi Krieger
Executive Vice President-Electricity Segment*
Shlomi Argas
Executive Vice President-Product Segment and Operations*
Bob Sullivan
Executive Vice President - Business Development Sales & Marketing
* Performs the functions described in the table, but is employed by Ormat Systems
1)Denotes Class III Director - Term expiring at 2019 Annual Shareholders Meeting
2)Denotes Class I Director - Term expiring at 2020 Annual Shareholders Meeting
3)Denotes Class II Director - Term expiring at 2021 Annual Shareholders Meeting
Audit Committee
Information required by this Item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by this item and not set forth below is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this item is incorporated herein by reference to the Company’s definitive proxy statement for the 2019 annual meeting.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) (1) List of Financial Statements
See Index to Financial Statements in Part II, Item 8 of this annual report.
(2) List of Financial Statement Schedules
All applicable schedule information is included in our Financial Statements in Part II, Item 8 of this annual report.
(b) Exhibit Index. We hereby file, as exhibits to this Annual Report, those exhibits listed on the Exhibit Index immediately following the signature page hereto.
Exhibit
No. Document
(C) EXHIBIT INDEX
2.1
Agreement and Plan of Merger, dated January 24, 2018, by and among Ormat Nevada Inc., OGP Holding Corp. and U.S. Geothermal Inc., incorporated by reference to Exhibit 2.1 to Ormat Technologies, Inc.’s Form 10-K filed with the Securities and Exchange Commission on March 16, 2018.^
3.1
Third Amended and Restated Certificate of Incorporation, incorporated by reference to Appendix A to Ormat Technologies, Inc.’s Definitive Proxy Statement on Schedule 14A filed with the Securities and Exchange Commission on April 10, 2017.
3.2
Fourth Amended and Restated By-laws, incorporated by reference to Exhibit 3.2 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on January 2, 2013.
3.3
Amended and Restated Limited Liability Company Agreement of ORPD LLC, dated April 30, 2015, by and among Ormat Nevada Inc., Northleaf Geothermal Holdings LLC, and ORPD Holding LLC incorporated by reference to Exhibit 3.5 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 7, 2015.
4.1
Form of Common Share Stock Certificate, incorporated by reference to Exhibit 4.1 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
4.2
Form of Preferred Share Stock Certificate, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
4.3
Indenture for Senior Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.2 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) filed with the Securities and Exchange Commission on January 6, 2006.
4.4
Indenture for Subordinated Debt Securities, dated as of January 16, 2006, between Ormat Technologies, Inc. and Union Bank of California, incorporated by reference to Exhibit 4.3 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-3 (File No. 333-131064) filed with the Securities and Exchange Commission on January 6, 2006.
4.5
Indenture of Trust and Security Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, HSS II, LLC, and Wilmington Trust Company, as Trustee and Depository, incorporated by reference to Exhibit 4.8 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2011.
Exhibit
No. Document
10.1.1
Agreement for Purchase of Membership Interests in ORPD LLC, dated as of February 5, 2015, by and between Ormat Nevada Inc. and Northleaf Geothermal Holdings LLC is incorporated by reference to Exhibit 3.5 to Ormat Technologies, Inc.'s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 7, 2015.
10.1.2
Agreement for Purchase of Membership Interests in ORNI 37 LLC, dated as of November 22, 2016, by and between Northleaf Geothermal Holdings LLC and Ormat Nevada Inc., incorporated by reference to Exhibit 10.1.13 to Ormat Technologies, Inc.’s Form 10-K filed with the Securities and Exchange Commission on March 1, 2017.
10.1.3
Amended and Restated Limited Liability Company Agreement of Opal Geo LLC, dated as of December 16, 2016, by and between OrLeaf LLC and JPM Capital Corporation, incorporated by reference to Exhibit 10.1.14 to Ormat Technologies, Inc.’s Form 10-K filed with the Securities and Exchange Commission on March 1, 2017.
10.1.4
Equity Contribution Agreement, dated as of December 16, 2016, by and among JPM Capital Corporation, Ormat Nevada Inc. and OrLeaf LLC, incorporated by reference to Exhibit 10.1.15 to Ormat Technologies, Inc.’s Form 10-K filed with the Securities and Exchange Commission on March 1, 2017.
10.2.1
Power Purchase Contract dated, April 16, 1985, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.7 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.2
Amendment No. 1, dated as of October 23, 1987, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.8 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.2.3
Amendment No. 2, dated as of July 27, 1990, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.9 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.2.4
Amendment No. 3, dated as of November 24, 1992, between Southern California Edison Company and Second Imperial Geothermal Company, incorporated by reference to Exhibit 10.3.10 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
Exhibit
No. Document
10.2.5
Power Purchase Contract, dated April 15, 1985, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.13 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
10.2.6
Amendment No. 1, dated as of October 27, 1989, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.14 to Ormat Technologies, Inc. Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) to the Securities and Exchange Commission on September 28, 2004.
10.2.7
Amendment No. 2, dated as of December 20, 1989, between Mammoth Pacific and Southern California Edison Company, incorporated by reference to Exhibit 10.3.15 to Ormat Technologies, Inc. Registration Statement on Form S-1 (File No. 333-117527) to the Securities and Exchange Commission on July 20, 2004.
10.2.8
Interconnection Facilities Agreement, dated October 13, 1985, by and between Southern California Edison Company and Mammoth Pacific (II), incorporated by reference to Exhibit 10.3.20 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.9
Plant Connection Agreement for the Second Imperial Geothermal Company Power Plant No. 1, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.24 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.10
IID-SIGC Transmission Service Agreement for Alternative Resources, dated, October 27, 1992, by and between Imperial Irrigation District and Second Imperial Geothermal Company incorporated by reference to Exhibit 10.3.25 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
Exhibit
No. Document
10.2.11
IID-Edison Transmission Service Agreement for Alternative Resources, dated, September 26, 1985, by and between Imperial Irrigation District and Southern California Edison Company incorporated by reference to Exhibit 10.3.34 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.12
Plant Amendment No. 1, to IID-Edison Transmission Service Agreement for Alternative Resources, dated, August 25, 1987, by and between Imperial Irrigation District and Southern California Edison Company incorporated by reference to Exhibit 10.3.35 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.13
Agreement Addressing Renewable Energy Pricing and Payment Issues, dated June 15, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.39 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.14
Amendment No. 1 to Agreement Addressing Renewable Energy Pricing and Payment Issues, dated November 30, 2001, by and between Second Imperial Geothermal Company QFID No. 3021 and Southern California Edison Company incorporated by reference to Exhibit 10.3.40 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
Exhibit
No. Document
10.2.15
Purchase Power Contract, dated March 24, 1986, by and between Hawaii Electric Light Company and Thermal Power Company incorporated by reference to Exhibit 10.3.44 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.16
Firm Capacity Amendment to Purchase Power Contract, dated July 28, 1989, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.45 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.17
Amendment to Purchase Power Contract, dated October 19, 1993, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.46 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.18
Third Amendment to the Purchase Power Contract, dated March 7, 1995, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.47 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.19
Performance Agreement and Fourth Amendment to the Purchase Power Contract, dated February 12, 1996, by and between Hawaii Electric Light Company and Puna Geothermal Venture incorporated by reference to Exhibit 10.3.48 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.2.20
Power Purchase Agreement, dated October 20, 2016, between ONGP, LLC and Southern California Public Power Authority, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities Exchange Commission on June 1, 2017.
10.3.1
Ormesa BLM Geothermal Resources Lease CA 966 incorporated by reference to Exhibit 10.4.1 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.2
Ormesa BLM License for Electric Power Plant Site CA 24678 incorporated by reference to Exhibit 10.4.2 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.3
Geothermal Resources Mining Lease, dated February 20, 1981, by and between the State of Hawaii, as Lessor, and Kapoho Land Partnership, as Lessee incorporated by reference to Exhibit 10.4.3 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.4
Geothermal Lease Agreement, dated October 20, 1975, by and between Ruth Walker Cox and Betty M. Smith, as Lessor, and Gulf Oil Corporation, as Lessee incorporated by reference to Exhibit 10.4.4 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.5
Geothermal Lease Agreement, dated August 1, 1976, by and between Southern Pacific Land Company, as Lessor, and Phillips Petroleum Company, as Lessee incorporated by reference to Exhibit 10.4.5 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.6
Geothermal Resources Lease, dated November 18, 1983, by and between Sierra Pacific Power Company, as Lessor, and Geothermal Development Associates, as Lessee incorporated by reference to Exhibit 10.4.6 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
Exhibit
No. Document
10.3.7
Lease Agreement, dated November 1, 1969, by and between Chrisman B. Jackson and Sharon Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.7 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.8
Lease Agreement, dated September 22, 1976, by and between El Toro Land & Cattle Co., as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.8 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.9
Lease Agreement, dated February 17, 1977, by and between Joseph L. Holtz, as Lessor, and Chevron U.S.A. Inc., as Lessee incorporated by reference to Exhibit 10.4.9 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.10
Lease Agreement, dated March 11, 1964, by and between John D. Jackson and Frances Jones Jackson, also known as Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.10 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.11
Lease Agreement, dated February 16, 1964, by and between John D. Jackson, conservator for the estate of Aphia Jackson Wallan, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.11 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.12
Lease Agreement, dated March 17, 1964, by and between Helen S. Fugate, a widow, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.12 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.13
Lease Agreement, dated February 16, 1964, by and between John D. Jackson and Frances J. Jackson, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.13 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.14
Lease Agreement, dated February 20, 1964, by and between John A. Straub and Edith D. Straub, also known as John A. Straub and Edythe D. Straub, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.14 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.15
Lease Agreement, dated July 1, 1971, by and between Marie L. Gisler and Harry R. Gisler, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.15 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.16
Lease Agreement, dated February 28, 1964, by and between Gus Kurupas and Guadalupe Kurupas, husband and wife, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.16 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.17
Lease Agreement, dated April 7, 1972, by and between Nowlin Partnership, as Lessor, and Standard Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.17 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.18
Geothermal Lease Agreement, dated July 18, 1979, by and between Charles K. Corfman, an unmarried man as his sole and separate property, and Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.18 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.19
Lease Agreement, dated January 1, 1972, by and between Holly Oberly Thomson, also known as Holly F. Oberly Thomson, also known as Holly Felicia Thomson, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.19 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
Exhibit
No. Document
10.3.20
Lease Agreement, dated June 14, 1971, by and between Fitzhugh Lee Brewer, Jr., a married man as his separate property, Donna Hawk, a married woman as her separate property, and Ted Draper and Helen Draper, husband and wife, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.20 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.21
Lease Agreement, dated May 13, 1971, by and between Mathew J. La Brucherie and Jane E. La Brucherie, husband and wife, and Robert T. O’Dell and Phyllis M. O’Dell, husband and wife, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.21 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
10.3.22
Lease Agreement, dated June 2, 1971, by and between Dorothy Gisler, a widow, Joan C. Hill, and Jean C. Browning, as Lessor, and Union Oil Company of California, as Lessee incorporated by reference to Exhibit 10.4.22 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.23
Geothermal Lease Agreement, dated February 15, 1977, by and between Walter J. Holtz, as Lessor, and Magma Energy Inc., as Lessee incorporated by reference to Exhibit 10.4.23 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.24
Geothermal Lease, dated August 31, 1983, by and between Magma Energy Inc., as Lessor, and Holt Geothermal Company, as Lessee incorporated by reference to Exhibit 10.4.24 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.25
Geothermal Resources Lease, dated June 27, 1988, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.26 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.26
Amendment to Geothermal Resources Lease, dated January, 1992, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.27 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.27
Second Amendment to Geothermal Resources Lease, dated June 25, 1993, by and between Bernice Guisti, Judith Harvey and Karen Thompson, Trustees and Beneficiaries of the Guisti Trust, as Lessor, and Far West Capital, Inc. and its Assignee, Steamboat Development Corp., as Lessee incorporated by reference to Exhibit 10.4.28 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.28
Geothermal Resources Sublease, dated May 31, 1991, by and between Fleetwood Corporation, as Lessor, and Far West Capital, Inc., as Lessee incorporated by reference to Exhibit 10.4.29 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.29
KLP Lease and Agreement, dated March 1, 1981, by and between Kapoho Land Partnership, as Lessor, and Thermal Power Company, as Lessee incorporated by reference to Exhibit 10.4.30 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.30
Amendment to KLP Lease and Agreement, dated July 9, 1990, by and between Kapoho Land Partnership, as Lessor, and Puna Geothermal Venture, as Lessee incorporated by reference to Exhibit 10.4.31 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.31
Second Amendment to KLP Lease and Agreement, dated December 31, 1996, by and between Kapoho Land Partnership, as Lessor, and Puna Geothermal Venture, as Lessee incorporated by reference to Exhibit 10.4.32 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 1 on Form S-1/A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
10.3.32
Participation Agreement, dated May 18, 2005, by and among Puna Geothermal Venture, SE Puna, L.L.C., Wilmington Trust Company, S.E. Puna Lease, L.L.C., AIG Annuity Insurance Company, American General Life Insurance Company, Allstate Life Insurance Company and Union Bank of California, incorporated by reference to Exhibit 10.4.33 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q/A filed with the Securities and Exchange Commission on December 22, 2005.
10.3.33
Project Lease Agreement, dated May 18, 2005, by and between SE Puna, L.L.C. and Puna Geothermal Venture, incorporated by reference to Exhibit 10.4.34 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q/A filed with the Securities and Exchange Commission on December 22, 2005.
Exhibit
No. Document
10.4.1*
Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 11, 2014.
10.4.2**
Form of Incentive Stock Option Agreement to Ormat Technologies, Inc.’s 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.31.2 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 28, 2014
10.4.3*
Form of Freestanding Stock Appreciation Right Agreement to Amended and Restated Ormat Technologies, Inc.’s 2012 Incentive Compensation Plan, , incorporated by reference to Exhibit 10.31.3 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 28, 2014.
10.4.4*
Ormat Technologies, Inc.'s Annual Management Incentive Plan, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 29, 2016.
10.4.5*
Form of Restricted Stock Unit Agreement under the Amended and Restated Ormat Technologies, Inc. 2012 Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities Exchange Commission on November 9, 2017.
10.4.6*
Ormat Technologies, Inc. 2018 Incentive Compensation Plan, incorporated by reference to Appendix A to Ormat Technologies, Inc.’s Definitive Proxy Statement on Schedule 14A filed on March 27, 2018.
10.4.7*
Form of Stock Appreciation Right Agreement under the Company’s 2018 Incentive Compensation Plan for stock appreciation rights awarded to Mr. Isaac Angel, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed on May 9, 2018.
10.4.8*
Form of Restricted Stock Unit Agreement under the Company’s 2018 Incentive Compensation Plan for restricted stock units awarded to Mr. Isaac Angel, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed on May 9, 2018.
10.4.9*
Form of Restricted Stock Unit Grant Notice and Terms and Conditions (Employees-Time Based Units), incorporated by reference to Exhibit 10.5 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed on August 8, 2018.
10.4.10*
Form of Stock Appreciation Right Grant Notice and Terms and Conditions (Employees), incorporated by reference to Exhibit 10.6 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed on August 8, 2018.
10.4.11+*
Form of Restricted Stock Unit Grant Notice and Terms and Conditions (Directors) to Ormat Technologies, Inc.’s 2018 Incentive Compensation Plan.
10.4.12+*
Form of Stock Appreciation Right Grant Notice and Terms and Conditions (Directors) to Ormat Technologies, Inc.’s 2018 Incentive Compensation Plan.1
10.5.1*
Form of Indemnification Agreement incorporated by reference to Exhibit 10.11 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on October 20, 2004.
10.6.1
Note Purchase Agreement, dated December 2, 2005, among Lehman Brothers Inc., OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.12 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 28, 2006.
10.6.2
Note Purchase Agreement, dated November 29, 2016, among ORNI 47 LLC, MUFG Union Bank, N.A., Munich Reinsurance America, Inc. and Munich American Reassurance Company, incorporated by reference to Exhibit 4.1 to Ormat Technologies Inc.'s Current Report on Form 8-K/A filed with the Securities and Exchange Commission on December 6, 2016.
10.7.1
Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 28, 2006.
10.7.2
First Supplemental Indenture dated as of June 14, 2006 amending the Indenture dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company and Union Bank of California, incorporated by reference to Exhibit 10.13.2 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on August 7, 2006.
10.8
Guarantee dated as of December 8, 2005 among OrCal Geothermal Inc., OrHeber 1 Inc., OrHeber 2 Inc., Second Imperial Geothermal Company, Heber Field Company and Heber Geothermal Company, incorporated by reference to Exhibit 10.14 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 28, 2006.
10.14.1
Amended and Restated Power Purchase Agreement for Olkaria III Geothermal Plant, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Exhibit 10.20.1 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 12, 2007.
10.14.2
Olkaria III Project Security Agreement, dated January 19, 2007, between OrPower 4 Inc. and The Kenya Power and Lighting Company Limited, incorporated by reference to Exhibit 10.20.2 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 12, 2007.
Exhibit
No. Document
10.16
Joint Ownership Agreement for the Carson Lake Project, dated as of March 12, 2008, by and between Nevada Power Company and ORNI 16 LLC, incorporated by reference to Exhibit 10.24 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 7, 2008.
10.17
Sale and Purchase Agreement dated August 2, 2010, between ORNI 44 LLC and CD Mammoth Lakes I, Inc. and CD Mammoth Lakes II, Inc., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2010.
10.18
Note Purchase Agreement, dated September 23, 2011, among OFC 2 LLC, ORNI 15 LLC, ORNI 39 LLC, ORNI 42 LLC, and HSS II, LLC, as Issuers, OFC 2 Noteholder Trust, as Purchaser, John Hancock Life Insurance Company (U.S.A.), as Administrative Agent, and the United States Department of Energy (DOE), as Guarantor, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 4, 2011.
10.19.1
Finance Agreement, dated as of August 23, 2012, between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and Overseas Private Investment Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 8, 2012.
10.19.2
Amendment No. 1 to the Finance Agreement, dated as of August 23, 2012, between OrPower 4, Inc., an indirect wholly-owned subsidiary of Ormat Technologies, Inc., and Overseas Private Investment Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on November 8, 2012.
10.19.3
Loan Agreement, dated March 22, 2018, by and among Ormat Technologies, Inc. and Migdal Insurance Company Ltd., Migdal's Makefet Pension and Provident Funds Ltd. and Yozma Pension Fund of Self Employed Ltd., incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on June 19, 2018.
10.19.4
Finance Agreement, dated April 30, 2018 between Geotermica Platanares, S.A. DE C.V. and Overseas Private Investment Corporation incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on June 19, 2018.
10.19.5
Amendment to Finance Agreement, dated October 17, 2018 between Geotermica Platanares, S.A. DE C.V. and Overseas Private Investment Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed on November 8, 2018.
10.20
Equity Contribution Agreement with respect to ORTP, dated as of January 24, 2013, between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.
10.21
Limited Liability Company Agreement of ORTP, LLC dated as of January 24, 2013, between Ormat Nevada, Inc., a wholly-owned subsidiary of Ormat Technologies, Inc., and JPM Capital Corporation, incorporated by reference to Exhibit 3.1 to Ormat Technologies, Inc. Current Report on Form 8-K to the Securities and Exchange Commission on January 30, 2013.
10.22.1*
Employment Agreement, dated as of February 11, 2014, between Ormat Technologies, Inc. and Isaac Angel, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 11, 2014.
10.22.2*
Employment Agreement, dated as of January 6, 2013, between Ormat Systems, Ltd. and Doron Blachar, incorporated by reference to Exhibit 10.30.2 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange on February 28, 2014.
10.23.1
JBIC Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation and Mizuho Bank, Ltd., dated March 28, 2014, incorporated by reference to Exhibit 10.7 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 9, 2014.
10.23.2
Common Terms Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, Japan Bank for International Cooperation, Asian Development Bank, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Mizuho Bank, Ltd., Mizuho Bank (USA), Pt. Bank Mizuho Indonesia, Société Générale, Société Générale Tokyo Branch, and Sumitomo Mitsui Banking Corporation, dated March 28, 2014, incorporated by reference to Exhibit 10.8 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 9, 2014.
10.23.3
Covered Lenders Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., Orsarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited, The Bank of Tokyo-Mitsubishi UFJ, Ltd., ING Bank N.V., Tokyo Branch, National Australia Bank Limited, Société Générale, Tokyo Branch, and Sumitomo Mitsui Banking Corporation, dated March 28, 2014, incorporated by reference to Exhibit 10.9 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 9, 2014.
10.23.4
ADB Facility Agreement, dated March 28, 2014, by and among Kyuden Sarulla Pte. Ltd., OrSarulla Inc., PT Medco Geopower Sarulla, Sarulla Operations Ltd, Sarulla Power Asset Limited and Asian Development Bank, dated March 28, 2014, incorporated by reference to Exhibit 10.10 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 9, 2014.
10.23.5
Ormat Equity Support Deed, dated March 28, 2014, by and among Ormat International, Inc., Ormat Holding Corp., OrPower 11 Inc., OrSarulla Inc., Sarulla Operations Ltd, Mizuho Bank, Ltd. and Mizuho Bank (USA), dated March 28, 2014, incorporated by reference to Exhibit 10.11 to Ormat Technologies, Inc.’s Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 9, 2014.
Exhibit
No. Document
10.24.1
Commercial Cooperation Agreement, dated May 4, 2017, between Ormat Technologies, Inc. and ORIX Corporation, incorporated by reference to Exhibit 10.1 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2017.
10.24.2
Governance Agreement, dated May 4, 2017, between Ormat Technologies, Inc. and ORIX Corporation, incorporated by reference to Exhibit 10.2 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2017.
10.24.3
Registration Rights Agreement, dated May 4, 2017, between Ormat Technologies, Inc. and ORIX Corporation, incorporated by reference to Exhibit 10.3 to Ormat Technologies, Inc.'s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 4, 2017.
21.1
Subsidiaries of Ormat Technologies, Inc., incorporated by reference to Exhibit 21.1 to Ormat Technologies, Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 28, 2006.
23.1+
Consent of Kesselman & Kesselman, Certified Public Accountants (Isr.), a member firm of PricewaterhouseCoopers International Limited, Independent Registered Public Accounting Firm.
23.2+
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
31.1+
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1+
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1
Material terms with respect to BLM geothermal resources leases incorporated by reference to Exhibit 99.1 to Ormat Technologies, Inc.’s Registration Statement Amendment No. 2 on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 21, 2004.
99.2
Material terms with respect to BLM site leases incorporated by reference to Exhibit 99.2 to Ormat Technologies, Inc.’s Registration Statement on Form S-1 (File No. 333-117527) filed with the Securities and Exchange Commission on July 20, 2004.
99.3
Material terms with respect to agreements addressing renewable energy pricing and payment issues incorporated by reference to Exhibit 99.3 to Ormat Technologies, Inc.’s Registration Statement on Form S-1A (File No. 333-117527) filed with the Securities and Exchange Commission on September 28, 2004.
101.INS XBRL Instance Document.
101.SCH XBRL Taxonomy Extension Schema Document.
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB XBRL Taxonomy Extension Label Linkbase Document.
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document.
*
Management contract or compensatory plan in which directors and/or executive officers are eligible to participate.
+
Filed herewith.
^
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. We will furnish the omitted schedules to the SEC upon request.
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.
Date: March 1, 2019
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 March 1, 2019.
Signature
Capacity
/s/ Isaac Angel
Chief Executive Officer
Isaac Angel
(Principal Executive Officer)
/s/ Doron Blachar
Chief Financial Officer
Doron Blachar
(Principal Financial and Accounting Officer)
/s/ Todd Freeland
Chairman of the Board of Directors
Todd Freeland
Director
Stan Koyanagi
/s/ Dan Falk
Director
Dan Falk
/s/ David Granot
Director
David Granot
/s/ Ravit Bar Niv
Director
Ravit Bar Niv
/s/ Yuichi Nishigori
Director
Yuichi Nishigori
/s/ Dafna Sharir
Director
Dafna Sharir
/s/ Stanley B. Stern
Director
Stanley B. Stern
/s/ Byron Wong
Director