ITEM 1. Business.
Unless the context requires otherwise, all references in this annual report to “Raser,” “the Company,” “we,” “us,” “our company,” “Raser Technologies” or “our” refer to Raser Technologies, Inc. and its consolidated subsidiaries.
Overview
We are an environmental energy technology company focused on geothermal power development and technology licensing. We operate two business segments: Power Systems and Transportation & Industrial. Our Power Systems segment develops geothermal electric power plants and anticipates also developing bottom-cycling operations in the future. Our Transportation & Industrial segment focuses on using our Symetron™ family of technologies to improve the efficiency of electric motors, generators and power electronic drives used in electric and hybrid electric vehicle propulsion systems. Through these two business segments, we are employing a business strategy to produce a positive impact on the environment and economically beneficial results for our stockholders. By executing our business strategy, we aim to become a producer of geothermal electric power as well as a provider of electric and hybrid-electric vehicle technologies and products.
Power Systems Segment
We have accumulated a portfolio of geothermal interests in four western continental states and a geothermal concession in Indonesia. These geothermal interests are important to our ability to develop geothermal power plants. We continue to seek and accumulate additional interests in geothermal resources for potential future projects.
We have initiated the development of eight geothermal power plant projects in our Power Systems segment to date. We have placed one power plant in service to date, which we refer to as our Thermo No. 1 plant, and we
are currently selling electricity generated by the Thermo No. 1 plant. The Thermo No. 1 plant is currently generating approximately 7 MW of electrical power (gross). After deducting the electricity required to power the plant, also known as parasitic load, the net power produced by the Thermo No. 1 plant is approximately 6 MW. In addition we also purchase power for remote pumps in our well field, which are required to ensure adequate flow of hot water. Both the gross output and the net output of the plant are below the amounts the plant was designed to produce, primarily due to issues related to temperature of the resource from the well field. We are working to improve the electrical output of the plant and the temperature of the resource.
Due to the economic downturn, a difficult financing environment, difficulties experienced at the Thermo No. 1 plant and other factors, we have had to adjust our development plans. We had anticipated to be in a position to move forward with the simultaneous development of the other seven sites we have initiated. In light of current conditions, we believe we need to focus most of our time and resources on development of the one or two projects we believe are best positioned for development at this time. Thus, we intend to focus on improving the electrical output from our Thermo No. 1 plant and completing the well field development at our Lightning Dock and/or Thermo No. 2 and No. 3 projects. We will continue to undertake permitting at the other sites we have initiated. The status of each of the eight projects we have initiated is described below (see “Current Geothermal Power Projects” section below).
Our ability to develop our geothermal power projects is dependent on our ability to obtain adequate financing to fund those projects. We intend to evaluate a variety of alternatives to finance the development of our projects. These alternatives could include government funding from grants, loan guarantees or private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, pre-paid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. We cannot be certain that funding from any of these sources will be available. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we may need to modify our current plans for plant construction, well field development and other development activities, extend the time frame over which these activities will take place, or cease operations.
Historically, federal and state governments have provided incentives and mandates for the development of renewable resources, including geothermal projects. The American Recovery and Reinvestment Act of 2009 (the “Recovery Act”) provides for a number of additional incentive programs to help fund renewable energy projects. Among these new programs is the Section 1603 renewable energy grant program under the Recovery Act. Pursuant to the Recovery Act, an owner of a qualified geothermal power plant may elect to receive a grant from the U.S. Treasury Department of up to 30% of certain qualifying construction and drilling costs in lieu of claiming either the energy credit (sometimes referred to as the investment tax credit) (“ITC”) or the production tax credit (“PTC”). The owner of a qualified geothermal power plant may apply for a grant of up to 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction began in 2009 or 2010. Grants are to be paid 60 days after the later of the date of the application for the grant is deemed complete or the date the project is placed in service.
We originally financed the construction of the Thermo No. 1 plant through project financing and tax equity financing arrangements. Subsequent to the adoption of the Recovery Act, we amended these financing arrangements to be consistent with the Recovery Act and take advantage of the grants available under the Recovery Act. We obtained a grant of approximately $33.0 million, which we received in February 2010. Approximately $3.8 million of the grant funds were released to us, as owner of the project. The remainder of the grant funds will be held in escrow until June 30, 2010, and the amounts to be released to the other parties that provided the debt and equity financing for the project will be determined based on the electrical output and the operational costs of the plant at that time. Up to $4.3 million of any amounts not released to these parties will be paid to Pratt Whitney Power Systems (“PWPS”) as final payment for the turbines in production at the Thermo No. 1 plant. Any remaining amount, after the payment to PWPS, will be released to us.
We believe the demand for clean, renewable energy will continue to increase in the future, and we believe we are well positioned to play a meaningful role in providing clean, renewable power to consumers. Not
everything has been in keeping with our original timeframes and cost expectations. Some of our projects have experienced longer development timelines or higher costs than originally planned. Moreover, the current economic conditions in the United States and around the world make it more difficult to secure the financing and complete the other various steps necessary to develop our projects. Nevertheless, we intend to continue to implement our business strategy of rapid deployment of our geothermal power projects.
Our Thermo No. 1 plant was the first geothermal power plant to be constructed utilizing PureCycle 280 generation units (“PureCycle units”) manufactured by PWPS. The PureCycle units are small, modular units each producing approximately 280 kilowatts (“kW”) of gross electrical output each. We installed fifty PureCycle units at the Thermo No. 1 plant. While we believe that the PureCycle units have advantages in certain scenarios, our current development plans anticipate using larger binary cycle units that produce 2.5 megawatts (“MW”) to 10 MW of gross electrical output per unit. We have received proposals from a number of equipment manufacturers and believe that moving to larger generating units could result in greater returns on our future projects.
Our geothermal resources portfolio consists of over 275,000 acres in the United States and a concession of over 100,000 acres in Indonesia. Our portfolio of geothermal leases contains a mix of private, state and federal leases. We utilize our in-house full-time geologists, independent geologists, in-house and independent transmission specialists, ARC-GIS specialists and others on our development team to help identify and locate areas that are favorable to development. We are primarily interested in securing locations that we believe contain the targeted geothermal activity, present a favorable development environment (considering permitting requirements, topography, site access, etc.), and allow transmission access to favorable power markets. Each lease we acquire is based upon these key indicators of the project’s geothermal potential. Some prospect areas, like our Lightning Dock project, have been the subjects of extensive exploration and data analysis, while others will require additional exploration and evaluation. Some of the geothermal leases in our portfolio have not been extensively explored and documented and could ultimately be rejected for full-scale development. We seek to acquire a broad-based portfolio of prospects, and we continue to evaluate new areas to target for leasing in addition to studying the prospect areas we currently have under lease.
Transportation & Industrial Segment
Our Transportation & Industrial segment focuses on commercializing our electric motor, generator and drive technologies, such as our series plug-in hybrid vehicle (“PHEV”) with range extender technologies, into applications. In 2008, we began work to integrate a Symetron™ traction motor, generator and controller drive in a Hummer H3 demonstration vehicle (“Hummer Demonstration Vehicle”). The Hummer Demonstration Vehicle was built under a collaborative arrangement with General Motors, Inc. (“General Motors”) and our integration partner FEV, Inc. The Hummer Demonstration Vehicle was designed to achieve 100 mpg equivalent to demonstrate the benefits of our plug-in electric drive system in Sports Utility Vehicle (“SUV”) and light truck applications. Our plug-in electric drive system is designed to allow light trucks and SUVs to achieve the equivalent of over 100 mpg in typical local daily driving with near zero emissions, by using electricity instead of petroleum as the primary fuel. Recently, General Motors decided to discontinue the Hummer brand. We believe, however, that our technology is capable of being used in other types of SUVs and light truck applications and we believe that our systems for light weight trucks and SUVs are ahead of our competitors in the market.
We completed the initial phase of developing our Hummer Demonstration Vehicle and unveiled the prototype at the 2009 SAE International World Congress, in Detroit Michigan. We are currently in the process of further testing the Hummer Demonstration Vehicle and seeking a manufacturing partner for small scale manufacturing of additional prototype vehicles. We also expect to begin to realize modest revenues from the sale of enhanced motors and generators through our business cooperation agreement with HHI, although the exact amount and timing of these revenues will be dependent on HHI’s ability to implement these enhanced designs into its manufacturing and distribution system which we anticipate to occur during 2010. Although progress is being made by each of our business segments with respect to this initiative, we may not be able to generate significant revenues from this technology by either of our segments, if at all.
We intend to continue to explore opportunities to commercialize our motor and drive technologies. However, the recent economic downturn has had a dramatic and adverse effect on the automotive industry and other large industrial manufacturers that would otherwise be in a position to use and benefit from our technologies. As a result, we believe our ability to commercialize our Symetron™ technologies will be limited until economic conditions improve. In light of the current economic conditions, we have reduced our resources committed to new developmental efforts. We intend to evaluate the prospects for our technologies on an ongoing basis. If we believe there are attractive opportunities, we will devote the resources to pursue those opportunities to the extent we believe appropriate. If, on the other hand, we determine that the risks and uncertainties for this business segment are too great in light of the current economic climate, we may choose to further reduce the resources devoted to these efforts.
We are also currently evaluating the advantages and disadvantages of a possible business separation transaction involving the Transportation and Industrial segment, which may include spinning off the Transportation and Industrial business to our stockholders as a separate independent company. We believe that a separation transaction involving the Transportation and Industrial business would facilitate the ability to raise capital for both businesses, including the capital needed to further develop and commercialize the Symetron™ family of technologies. However, we may ultimately determine that a business separation transaction involving the Transportation and Industrial segment is not feasible for financial, legal or other reasons. For a discussion of the revenues, profit/loss and total assets of the Transportation and Industrial segment for the years ended December 31, 2009, 2008 and 2007, please see Note 20. “Business Segments” in our audited consolidated financial statements.
Operating History, Corporate Structure and Capital Requirements
Consistent with our limited operating history, we have generated limited revenues from operations. While our Power Systems segment has begun to generate revenue from the operation of our Thermo No. 1 plant, we do not expect to generate significant additional revenues from this segment until we develop additional plants and place them in service. To date, our Transportation & Industrial segment has generated only a limited amount of revenue from research and development subcontracts administered through contractors for certain government agencies. Future revenues from our Transportation & Industrial segment will depend on our ability to commercialize our Symetron™ technologies, and we cannot predict when those efforts will be successful, if at all.
Limited historical information exists upon which an evaluation can be made regarding our business and prospects. We also have limited insight into how market and technology trends may affect our future business. The revenue and income potential of both of our business segments is unproven and the markets in which we expect to compete are very competitive and rapidly evolving. To date, all of our revenues have been derived from domestic sources. Our business and prospects should be considered in light of the risks, expenses, cash requirements, challenges and uncertainties that exist in an early stage company seeking to develop new technologies and products in competitive and rapidly evolving markets.
We have incurred substantial losses since inception and we are not operating at cash breakeven. Our continuation as a going concern is dependent on efforts to raise additional capital, increase revenues, reduce expenses, and ultimately achieve profitable operations. If substantial losses continue, or if we are unable to raise sufficient, additional capital on reasonable terms, liquidity concerns may require us to curtail or cease operations, liquidate or sell assets, or pursue other actions that could adversely affect future operations.
Given our current business strategy, we will need to secure additional financing in order to execute our plans and continue our operations. We may acquire this additional funding through the issuance of debt, preferred stock, equity or a combination of these instruments. We also intend to evaluate a variety of alternatives to finance the development of our geothermal power projects. These alternatives could include project financing and tax equity financing, government funding from grants, loan guarantees or private activity bonds, joint
ventures, the sale of one or more of our projects or interests therein, entry into prepaid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. The amount and timing of our future capital needs will depend on many factors, including the timing of our development efforts, opportunities for strategic transactions, and the amount and timing of any revenues we are able to generate. We cannot be certain that funding will be available to us on reasonable terms, or at all. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we may be unable to execute out plans or continue our operations.
We are incorporated in Delaware. We are the successor to Raser Technologies, Inc., a Utah corporation, which was formerly known as Wasatch Web Advisors, Inc. Wasatch Web Advisors acquired 100% of our predecessor corporation in a reverse acquisition transaction in October of 2003. Prior to that transaction, our predecessor corporation was a privately-held company.
Industry Overview
Our Power Systems segment is seeking to develop geothermal power plants. Geothermal energy is one of several clean, renewable energy sources that are part of the renewable energy industry. Our Transportation & Industrial segment is focused on commercializing technologies that improve electric motors and related components with a particular emphasis on electric and hybrid electric vehicle propulsion systems.
The Renewable Energy Industry and Geothermal Energy
The global demand for electrical power has continued to grow significantly each year. In recent years, concerns about CO2 emissions from fossil-fuel power plants and the potential effect of CO2 emissions on global climate change, together with concerns about sustainability and the United States’ dependence on foreign energy sources have led to an increased emphasis on domestic renewable energy. Renewable energy sources generally include: geothermal, solar, wind, hydro, biomass, fuel cells using renewable fuels, ocean wave, ocean thermal, and tidal current.
A number of states and the District of Columbia offer some form of regulation or financial incentive related to the increased use of renewable energy. Among the most wide-reaching regulations, currently adopted by 32 states and the District of Columbia, is the establishment of Renewable Portfolio Standards (“RPS”), which either mandate or set goals that electrical utilities operating in a state obtain a minimum level of energy from renewable energy sources by a stated deadline. Eligible sources of renewable energy vary by state, but generally include geothermal and certain of the other renewable energy sources described above. For example, California, one of the primary states to which we intend to sell our renewable power, has one of the most ambitious RPS requirements in the country. California’s RPS target is to achieve a 20 percent renewable supply by 2010, with a mandate to achieve 33 percent by the end of 2020. In addition to the state regulations and financial incentives, the federal government is considering a national RPS mandate and has provided tax incentives, grants and loan guarantees to encourage the development of renewable energy sources.
The need for utilities to meet RPS requirements and the available state and federal incentives, among other factors, have led to a significant increase in the development of renewable energy projects based on a variety of energy sources. While geothermal is only one of several renewable energy sources, we believe geothermal projects offer several advantages over other types of renewable energy. Geothermal power plants can provide a reliable, continuous power supply in contrast to wind and solar sources that can only produce energy when an abundance of wind or sun is available. Intermittent resources such as wind and solar have to be “firmed” by arranging for power supply when the resource is not available. Additionally, intermittent sources of power require transmission capacity be available at its peak generation capacity even though such capacity is only used intermittently. Such use of capital assets is inefficient. These attributes of intermittent renewable power add to the cost of power for utilities. A continuous source of firm power is called base load energy. Geothermal plants, based on modern technologies, can provide base load power with virtually no emissions. These factors make geothermal energy attractive to utilities and other purchasers of renewable energy.
Geothermal energy is derived from the natural heat of the earth that has been transferred from the core of the earth to hot or molten rocks nearer to the surface. The heat resource can be used to generate electricity through a transfer medium such as water. When water comes sufficiently close to hot or molten rock it is super heated and ascends toward the surface of the earth. Geothermal fluids cannot be transported economically over longer distances due to heat and pressure losses. Therefore, geothermal power plants must normally be located within approximately one to two miles of the geothermal production wells. Geothermal energy projects typically have higher capital costs compared to fossil fuel power plants. However, geothermal power plants tend to have significantly lower variable operating costs due primarily to the elimination of fuel expense.
Advances in heat transfer technology, such as the binary cycle technology utilized in our plant designs, have made it possible to generate electricity from lower temperature sources of geothermal heat that were previously unusable for such purposes. Binary cycle technology can utilize water-based geothermal resources with temperatures ranging from approximately 200 to 350 degrees Fahrenheit. Binary cycle technology is a closed-loop heat transfer system, in which the hot water from the geothermal resource is “cycled” or pumped to the surface through production wells and channeled through surface pipes into heat transfer equipment. In a binary system, the geothermal water never comes into direct contact with the blades of the turbine generator. The geothermally-heated water is used to heat an organic compound or “working fluid” located in the power generating units, which then vaporizes (at a lower temperature than boiling water) into a gas to turn the turbine generator. After the heat transfer process is complete, all of the geothermal water remains in the pipes at a cooler temperature. The cooler water is reinjected into the ground to renew the geothermal resource. All of the geothermal water is then returned to the geothermal heat resource under the earth’s surface through a reinjection well to ensure that the heat resource is properly maintained. As a result, no water is permanently “extracted” from the earth. In light of the nature of the heat transfer, and the fact that all of the geothermal water is returned to the heat source, the resource is considered fully renewable and can be used in a sustainable manner for long periods of time.
Geothermal power currently represents less than 1% of the total electrical power produced in the United States. However, studies by the National Renewable Energy Laboratory and the Massachusetts Institute of Technology suggest that geothermal energy could become a significant source of electrical energy, growing to as much as 10% of the United States’ overall electrical power production.
Transportation and Other Electric Motor Industries
Many of the same concerns that have led to an increased focus on renewable energy have also led to an increased focus on energy efficiency and conservation. Manufacturers and users of generators, alternators, motors and adjustable-speed drive systems continue to seek improved operating efficiencies and higher power and torque outputs. Many large industries such as automotive, heating, ventilating and air conditioning (“HVAC”), public transportation, military and others use induction motors and drives as well as generators and alternators. Each of these industries is large and requires different specifications to meet their application requirements. AC induction motors, for example, are the workhorses of industry and are found throughout factories, buildings and residences. Power electronic drives are used to control the speed and performance of AC induction motors in order to save energy. With the cost of electrical energy continuing to rise, end-user demand for higher efficiency electric motors, generators and adjustable-speed motor-drive systems is steadily increasing. At the same time, in order to minimize power plant emissions and reduce electrical power demand, government agencies are increasingly mandating higher efficiency electric motor and motor-drive system standards.
Through internal and collaborative research and development, our Transportation & Industrial segment has developed several innovations in electric motors, generators and their associated power electronic drives and controller technologies that allow for increased torque, power and efficiency. These technologies can be applied to industrial AC induction motors and drives, permanent magnet synchronous motors, AC generators and automotive alternators for use in industrial and transportation applications, hybrid-electric and electric vehicle propulsion systems, and other applications where the efficiency of electricity-to-motion or motion-to-electricity power conversions can be improved.
We believe our Symetron™ technologies are particularly well-suited for PHEV propulsion systems. PHEV systems are one of the new areas of focus among many auto companies for the next generation of hybrid vehicles. We are collaborating with other companies to develop a PHEV integrated master control hardware and software system and have developed our own electric vehicle propulsion system incorporating our technologies. We have successfully integrated many of these technologies into our Hummer Demonstration Vehicle and have filed additional patent applications related to their use in the Hummer Demonstration Vehicle. These technologies could also have applications in other SUVs and light truck systems.
Business Strategy
Our primary energy technology objectives are to be a leading developer of geothermal power plants and a leading developer and licensor of technologies that improve the performance of electric motors, generators, drives and related components. We believe the growing demand for clean, renewable energy sources and the increased emphasis on energy efficiency and conservation present significant growth opportunities for both of our business segments. We intend to pursue our objective through the following strategies:
Focus on Development of Geothermal Power Plants
Our Power Systems segment has initiated the development of eight geothermal projects in the United States to date, including the construction of our Thermo No. 1 plant, which has been operating and selling electricity to the City of Anaheim, California since April 2009. We have either obtained or are in the process of obtaining permits for the development of seven other geothermal power projects we have initiated. Continued development of each of these projects is dependent on our ability to obtain additional financing.
Due to the economic downturn, a difficult financing environment, difficulties experienced at the Thermo No. 1 plant and other factors, we have had to adjust our development plans. We had hoped to be in a position to move forward with the simultaneous development of the other seven sites we have initiated. However, we now believe we will need to focus most of our time and resources on the development of one or two projects we believe are best positioned for development at this time. Thus, we intend to focus on improving the electrical output from our Thermo No. 1 plant and completing the well field development at our Lightning Dock and/or Thermo No. 2 and No. 3 projects. We will continue to undertake some permitting activities at the other sites we have initiated, but we do not expect to conduct any significant development activities with respect to these projects until we have completed the projects just mentioned or further resources become available to us.
We intend to initiate the development of new projects each year, and we expect to maintain a portfolio or series of projects in development at all times. Our current goal is to develop, over the next few years, new projects each year that will generate a cumulative total of approximately 40 MW of electricity per year. However, the number of projects we initiate each year will depend on a number of factors, including the availability of adequate financing, the availability of adequate geothermal resources, the demand for renewable power, the total number of projects we have under development at one time, and our available resources to devote to our project development efforts.
Refine Rapid Deployment Strategy
Our current development efforts are focused on deployment of modular, binary-cycle generation units where the level of on-site construction activities can be decreased and development timelines shortened when compared to traditional geothermal power plant development. We installed PWPS PureCycle units at our Thermo No. 1 plant to accomplish this goal. Major construction of the Thermo No. 1 plant was completed in less than nine months but unforeseen challenges occurred in well field development that have prevented us from generating the level of electrical output the plant was designed to produce. We continue to take steps to increase the electrical output at the plant. However, we may not be able to increase the output to full capacity on a cost effective basis or in time to meet the requirements for Final Completion (as defined in the Thermo Financing Agreements discussed below) of the plant by June 30, 2010.
Based on experience with the Thermo No. 1 plant, we are evaluating refinements to our plant design in an effort to maximize electrical output from future plants we develop. For example, we are currently evaluating the benefits of utilizing larger modular units in the range of 2.5 MW to 10 MW as opposed to the smaller, PureCycle modular units. We are also increasing our focus on early well field development activities prior to beginning the construction phase of development. Rapid deployment remains, however, a key focus of our development efforts as we believe it provides competitive advantages in a number of areas.
Continue to Finance the Development of Geothermal Power Plants through Various Arrangements
Each geothermal power project generally consists of three phases. During the first phase, the site is identified and evaluated. During the second phase, the power plant, transmission lines and pipelines are constructed and the production and reinjection wells are drilled. The third and final phase is the production phase, during which the power plant is operated over its useful life. A different mix of financing alternatives is available for the various development phases and activities. To date, we have funded the site identification and evaluation phase of each project, as well as the drilling of production and reinjection wells, primarily from our funds available for general corporate purposes, which we have obtained principally from the issuance of convertible debt and equity securities from time to time. However, we intend to explore or have already explored other potential alternatives to finance the drilling of production and reinjection wells for our projects, including drilling-specific investment funds, government grants, loan guarantees and private activity bonds, joint ventures or other strategic transactions.
Sufficient financing to complete the development of each of our geothermal power projects is critical to the success of our strategy. We believe that access to capital will be a gating factor for beginning drilling and construction on geothermal projects we intend to develop in 2010 and beyond. While the current financing environment is difficult due to economic conditions, the current economic recession has also resulted in lower commodity prices and construction costs. Further, the Recovery Act provides for a number of grants and tax incentives to help fund renewable energy projects. The Recovery Act includes provisions that:
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Extend the 10-year PTC for qualified geothermal facilities placed in service through 2013.
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Permit taxpayers to elect to claim an ITC in place of the PTC for certain projects, including, geothermal energy facilities placed in service from 2009 through 2013. The amount of the ITC would generally be 30 percent of the qualifying costs.
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Modify the ITC by eliminating the reduction of the ITC for property financed by subsidized energy financing or tax-exempt private activity bonds.
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Permit a developer to receive a grant from the U.S. Treasury Department in place of claiming tax credits for certain properties placed in service in 2009 and 2010 that would otherwise qualify for the PTC or ITC. Property placed in service after 2010, but on or before the applicable credit termination date, could qualify for the grants as long as construction began in 2009 or 2010. The amount of a grant would generally be equal to the amount of the ITC for which the project would have otherwise been eligible.
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Extend first-year bonus depreciation to property placed in service in 2009. This means an owner of qualifying property placed in service in 2009 could deduct 50 percent of the adjusted basis of the property in 2009. The remaining 50 percent would be depreciated using the 5-year Modified Accelerated Cost Recovery System (“MACRS”).
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Authorize an additional $1.6 billion of Clean Renewable Energy Bonds (“CREBs”) to finance facilities that generate electricity from certain renewable resources.
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Authorize an additional $6.0 billion in loan guarantees for qualified facilities.
We are hopeful that the provisions of the Recovery Act will help us obtain financing for plant construction when we are in a position to begin the construction phase of a project. However, we cannot be certain the financing will be available to us on favorable terms or at all.
Prior to obtaining financing for the construction of a power plant, we also seek to enter into a power purchase agreement with investor-owned or municipal-owned utilities. This type of long-term contractual arrangement to sell power facilitates a number of funding mechanisms. Some utilities may arrange to pay part of the purchase price of the power up front in order to assist with the financing of construction and development of the power plant. This arrangement is referred to as a prepaid power purchase agreement. We may explore prepaid power purchase agreements as a source of construction financing at one or more of our projects as a cost effective alternative source of financing.
As described above, we are exploring potential alternatives to finance the drilling of production and reinjection wells for our projects. On December 7, 2009, we entered into an agreement (the “Co-Development Agreement”) with Evergreen Clean Energy, LLC (“Evergreen”), which could provide an alternative source of funding for drilling or other early-stage development activities at certain projects. Evergreen’s funding obligations with respect to each site selected for development are subject to the satisfaction of a number of conditions, including satisfactory due diligence, the completion of certain milestones, the granting of a security interest, and the negotiation of definitive agreements relating to the financing of each project. Moreover, Evergreen is a newly formed clean-energy fund in the process of raising capital for its first investments in renewable energy projects. Therefore, the ability of Evergreen to perform its obligations and provide funding for one or more of our projects under the Co-Development Agreement is dependent upon Evergreen’s ability to obtain sufficient capital commitments from investors.
We previously entered into a Commitment Letter with Merrill Lynch to finance up to 155 MW of future projects. Merrill Lynch provided financing for the construction of our Thermo No. 1 plant in accordance with this Commitment Letter. The Commitment Letter was subsequently terminated as part of an overall restructuring of the project finance and tax equity agreements for the Thermo No. 1 plant. As a result, we have no existing commitments to finance the construction of the power plants we intend to develop. We intend to seek appropriate financing arrangements on a project-by-project basis, once a project is ready to move to the construction phase.
Expand Power Systems Segment to Include Development of Bottom Cycling and Waste Heat Recovery Facilities
We believe that some of our projects will allow for expansions of the power plants through “bottom-cycling” operations. When the temperature of the geothermal fluids produced from the well field is sufficiently high, the geothermal fluids which are discharged from the plant can potentially carry enough heat to generate additional electricity. In a bottom-cycling operation, the discharged geothermal fluids are passed through additional generating units to generate electricity without the risk and expense of drilling new wells. We are in the process of implementing a limited bottom-cycling operation on the Thermo No. 1 plant in order to improve the efficiency and output of the project.
We also believe the technologies used in our geothermal power projects can be used to generate electricity from waste heat associated with certain industrial operations. However, based upon our limited internal resources at the present time, we do not expect to pursue opportunities to expand our Power Systems segment to include the development of facilities that utilize waste heat to generate electricity until we believe our resources are sufficient to successfully pursue this opportunity. We believe there are a number of companies that could benefit from these waste heat recovery facilities, including cement plants, conventional power plants, steel mills, and others.
Continue to Identify and Acquire Potential Geothermal Resources
We have accumulated domestic geothermal interests in Nevada, New Mexico, Oregon and Utah. We believe we have aggregated one of the largest portfolios of potential geothermal resources in the United States. With the help of internal and external geologists, we intend to continue to identify, evaluate and acquire additional interests in properties that have the potential to provide sufficient geothermal energy to operate geothermal
power plants. We intend to target well-studied properties with known geothermal anomalies. Generally, we intend to seek resources that have been previously passed over for development by other companies but are suitable for binary cycle plants, which have lower grade heat characteristics than those required for higher temperature flash geothermal power generating technologies. If we discover or acquire heat resources that have higher temperatures than those most suitable for binary cycle technology, we intend to evaluate the use of traditional flash technology to generate power from these resources.
In addition to our geothermal interests in the United States, in September 2008 we and Indonesia Power were selected as low bidders on a geothermal project in Indonesia. As a result, both companies were awarded a concession by the Indonesian government that includes approximately 100,000 acres of land that contains potential geothermal resources. In the third quarter of 2009, we and Indonesia Power submitted a joint application for a U.S. Trade and Development Agency (“USTDA”) grant for an exploration program on the resource in Indonesia. During the first quarter of 2010, Indonesia Power received notice of approval of the grant from USTDA. We have been appointed by Indonesia Power as sole source contractor for the project. Under the grant, USTDA will reimburse us up to $934,000 which is 70% of the overall estimated costs of $1,343,000 to be incurred for the exploration program. Accordingly, 30%, or $409,000, of the overall costs required as part of the cost matching provision will not be reimbursed. Any costs incurred in excess of $1,343,000 will also not be reimbursed.
Commercialize Electric Powertrain Propulsion Solutions for the Transportation Industry
We intend to continue our efforts to market the technologies developed by our Transportation & Industrial business and our manufacturing partners to the global transportation industry in the areas of electric and hybrid electric vehicles. We believe these technologies are suited for use in industrial and transportation applications, hybrid-electric and electric vehicle propulsion systems, and other applications where the improvement in efficiency and power torque density of electricity-to-motion or motion-to-electricity power conversions provides a competitive advantage. We believe that manufacturers of electric motors and industries that make extensive use of electric motors and drives can utilize our Symetron™ technologies to improve the efficiency of electric motors, generators and related power electronic adjustable-speed drive systems without a significant increase in their manufacturing costs. To date, we have entered into three Symetron™ licensing or cooperative development agreements to explore these types of applications of our technologies.
Pursue Acquisitions Opportunistically
We may explore opportunities to acquire technologies or resources that complement or enhance our existing asset base. In addition, we may pursue acquisitions that accelerate our plans to develop geothermal power plants.
Our Business Segments
We operate two business segments: Power Systems and Transportation & Industrial. Our Power Systems segment develops clean, renewable geothermal electric power plants and anticipates developing bottom-cycling operations in the future. Our Transportation & Industrial segment focuses on using our Symetron™ family of technologies to improve the efficiency of electric motors, generators and power electronic drives used in electric and hybrid electric vehicle propulsion systems. The sources of revenue and potential sources of revenue from our segments are further described below.
Power Systems
With respect to each geothermal power plant we develop, we expect to generate revenues and cash flows from two primary sources. First, we will generate revenues through power purchase agreements with utilities from the sale of electrical power generated by the power plants. Second, we expect to receive revenue and cash flows in the form of fees and distributions from our projects primarily related to the tax structuring of the
projects. We expect that tax equity partners who are in a position to benefit from the tax benefits associated with the geothermal power plants we plan to develop will make capital contributions to fund a portion of our projects and related fee payments and distributions. We expect to share the power sales revenues and tax benefits with the tax equity partner in consideration for fees and other distributions. During the first ten years of the life of a power plant for which we claim the production tax credit, the tax equity partner would receive a larger percentage of the tax benefits as part of its equity interest in consideration for payments made to the operating entity. After the first five to ten years of operations, when most of the tax benefits have been exhausted, we would expect to receive most of the excess cash flows generated by the operating entity, while the tax equity partner would continue to receive a small percentage of excess cash flows. The exact terms of these arrangements, however, will depend on negotiations with individual tax equity partners and may vary from project to project. These techniques for tax equity financing have traditionally been applied to wind power projects, but we believe that they are applicable and available to geothermal power projects. We utilized a similar structure to finance the construction of our Thermo No. 1 plant. However, we subsequently modified our financing structure of the Thermo No. 1 plant to take advantage of the Section 1603 grant under the Recovery Act.
Transportation & Industrial
During 2010, our Transportation & Industrial segment plans to continue to focus primarily on commercializing the applications contemplated by our agreements with FEV Inc. and HHI . However, the recent economic downturn has had a dramatic adverse effect on the automotive industry and other large industrial manufacturers that would be in a position to use and benefit from our technologies. As a result, we believe our ability to commercialize our Symetron™ technologies will be limited until economic conditions improve. Accordingly, we may be unable to generate significant revenues from this business segment for the foreseeable future. In the interim, we have taken steps to reduce the resources committed to new developmental efforts. We intend to evaluate the prospects for our Transportation & Industrial segment on an ongoing basis. If we believe there are attractive opportunities, we will devote the resources to pursue those opportunities to the extent we believe appropriate. If, on the other hand, we determine that the risks and uncertainties for this business segment are too great in light of the current economic climate, we may choose to further reduce the resources devoted to these efforts.
Our Potential Geothermal Resources
We have accumulated a large portfolio of geothermal interests in four western states in Utah, Nevada, New Mexico and Oregon. We believe these interests have the potential to provide sufficient geothermal energy to operate binary cycle geothermal power plants. In addition to our geothermal interests in the United States, in September 2008 we and Indonesia Power were selected as successful bidders on a geothermal project in Indonesia. As a result, both companies were awarded a concession by the Indonesian government that includes approximately 100,000 acres of land that contains potential geothermal resources.
With the help of internal and external geologists, we intend to continue to identify, evaluate and acquire interests in additional properties with potential geothermal resources. Typically, when we acquire an interest in a property with potential geothermal resources, we do so by entering into a geothermal lease with the owner of the property. Under the terms of the typical lease, the owner of the property grants us the right to explore and develop the geothermal resources on the property. These leases are generally long term in nature and may be renewed at the expiration of the term. We generally pay upfront lease bonuses and annual delay rentals for the leases until a geothermal power plant is placed in service. If a plant is placed in service on a property, we are obligated to pay royalties to the owner of the property on all power produced.
In addition to entering into long-term geothermal leases for properties with potential geothermal resources, we have acquired interests in several properties where wells have been drilled on, or in the vicinity of, the properties. In addition, we have acquired interests in three properties where the geothermal resources have sustained established greenhouse operations. The acquisition of properties with established geothermal resources
significantly reduces the exploration risk and the amount of development time that is required to place the planned geothermal power plant into operation. Therefore, we intend to continue to explore opportunities to acquire interests in properties with established geothermal resources and properties with operating wells. Properties with established geothermal resources usually cost more to acquire, but the amount of time and capital for well field development and the risks associated with such development are generally reduced.
We cannot be sure that a property will ultimately provide a sufficient geothermal resource to operate a binary cycle geothermal power plant without drilling or other testing. The costs associated with drilling and testing varies from property to property and can often be significant. Generally, drilling and testing must be at least partially completed before project-specific financing is available from tax equity partners or other third-parties. As a result, we potentially must fund the costs associated with drilling, testing, and other up-front development activities from other funds available to us or by separately financing these activities.
For additional information on the property interests we have acquired and the properties on which we are currently conducting drilling and testing, see “Development of Geothermal Power Plants” below.
Development of Geothermal Power Plants
Each geothermal power project we develop consists of three phases. During the first phase, the site is identified and evaluated. During the second phase, the power plant, transmission lines and pipelines are constructed and the production and reinjection wells are drilled. The third and final phase is the production phase, during which the power plant is operated over its useful life. We consider “development” to mean the time after initial exploration is complete but before the plant is placed into service. The order in which certain development activities are conducted may vary depending on the unique characteristics of each site.
Site Identification and Evaluation
We utilize our in-house full-time geologists, independent geologists, in-house and independent transmission specialists, ARC-GIS specialists and others on our development team to help identify and locate areas that are favorable to development. We are primarily interested in securing locations that we believe contain the targeted geothermal activity, present a favorable development environment (considering permitting requirements, topography, site access, etc.), and allow transmission access to favorable power markets.
As part of our site identification and evaluation process, we perform certain internal reviews and we contract with independent third party transmission, geologic and geothermal consultants to provide independent analysis. These reviews can typically be categorized as either (i) preliminary site identification reviews which are used to either identify parcels of land for which we want to pursue leases or to identify parcels within an already leased area that are of high interest (a “Preliminary Site Review”), or (ii) a resource evaluation and internally-generated basic economic analysis (a “Resource Evaluation”).
A Preliminary Site Review will generally take into account well drilling logs, if available, geophysical features, geological samples, geothermal anomalies such as hot springs, other readily available geologic studies and data from third-party mining operations. We will also do a basic review of accessibility to the power grid and prepare maps of the property owners in the area through a search of title records or tax plats. The Preliminary Site Review does not generally entail new geologic surveys or other reviews that are more costly. The purpose of such a study is to identify areas of high interest for the lowest cost possible. We generally initiate a Preliminary Site Review after we have either identified an area that we think may be of interest, or after we have been approached by a landowner or other third party about an area. The purpose of these studies is typically to help us decide if we want to pursue a geothermal lease in the area and undertake the next phase of geologic study and review. Often, these sites were previously passed over for geothermal development by other companies due to, among other reasons, limitations of older technologies. The Preliminary Site Reviews are generally performed by our in-house geologists or by third-party geothermal engineers with whom we contract. A review of transmission
is prepared by our in-house transmission specialists, or our independent transmission consultants, ZGlobal Engineering and Energy Services. These reviews can take the form of a formal report or may simply be presented to management orally.
When a Preliminary Site Review identifies an area to be of high interest, we begin the process of lease acquisition. Suitable geothermal resources are located on federal, state, or private lands. Once the land owners are identified, we enter into either public or private geothermal and/or surface leases with those land owners. Public land leases are normally obtained either directly or through a public auction. Occasionally, we may determine that it is more economically feasible to purchase the land directly instead of entering into a lease agreement. For additional information on the property interests we have acquired, see “Our Potential Geothermal Resources” above.
A Resource Evaluation is typically a more detailed review of the prospects of a resource and the likelihood that the resource contains a developable geothermal resource. As part of this more detailed review, we will generally perform, or hire others to perform, additional geologic and geophysical studies like: (i) well or hot spring sampling and geochemical analysis of the samples; (ii) on-site geologic mapping (generally done via a detailed walk-through of the area); (iii) gravity, ground magnetic, telluric-magnetotelluric, self-potential and/or seismic surveys; and (iv) drilling of thermal-gradient wells or exploratory “slim holes.” Often times, at least some of these geophysical studies have already been performed and it is often not necessary, or advisable due to cost, to perform all of them. Depending on the nature of the studies which have already been performed and which studies we determine to be necessary or advisable, a Resource Evaluation can cost anywhere from several thousand dollars to several hundred thousand dollars.
We generally ask for a formal report to be prepared as part of a Resource Evaluation, but before such a report is finalized we will have several interim meetings to discuss relevant findings. It is possible that if the interim findings are favorable enough, we will begin permitting and possibly even drilling before a final report is prepared. This was the case with our Thermo No. 1 plant as discussed below. The purpose of a Resource Evaluation is to help us determine whether we have a high degree of confidence that the resource can support a 10 MW or larger geothermal project. If the results of the Resource Evaluation are inconclusive, we may seek additional exploratory work to be performed or we may abandon the prospect. If the results of the Resource Evaluation are favorable, however, we will begin development of a project by securing permits and drilling our first full-sized production well. While the drilling of slim holes may be appropriate at certain sites, we do not believe it necessary to drill slim holes at all sites in order to determine with a high degree of confidence that a suitable geothermal resource exists. To date, we have contracted with The Energy and Geoscience Institute at the University of Utah, GeothermEx, Inc. and others to prepare this type of resource evaluation.
The process of site identification and Resource Evaluation is a fluid process that is managed by experienced geologists, geothermal experts, and our internal development staff. As noted above, many of the sites we have pursued were passed over by other developers in the past after numerous studies had been performed. Because of this, there is oftentimes sufficient data already available to conclude with a high degree of confidence that a 10 MW or larger project is commercially viable with little additional study or review by our team. In these instances we may not necessarily strictly follow this two-phase review process.
The “high degree of confidence” threshold reflects a conclusion reached by management based on judgment, experience and available information, which typically includes internal and external evaluations of the potential resource and, in some cases, could include the evaluation of non-production slim holes drilled at the site. While management’s conclusion necessarily reflects management’s assessment that a property contains a commercially viable geothermal resource, this conclusion is not based on a precise statistical measurement of probability. Further, management’s conclusion is not necessarily based on an independent feasibility study or a systematic drilling program intended to definitively establish the size and characteristics of the potential resource, and we believe we can reach a conclusion with respect to a site without necessarily drilling non-production slim holes. Management’s conclusion does, however, reflect our belief that, with a high degree of
confidence, the resource will support one or more power plants, justifying the commitment of substantial resources to begin the process to construct the power plant, transmission lines, production and reinjection wells and pipelines.
Well Drilling and Plant Construction
The second phase of project development consists of a variety of activities, including permitting, drilling of production and reinjection wells, and construction of the power plant, transmission lines and pipelines. The determination to proceed with this phase of development is based on obtaining sufficient third-party evaluation and analysis supporting the conclusion, with a high degree of confidence, that the given site contains adequate renewable geothermal resources to continually produce electricity without any substantial degradation in the heat resource.
During the second phase of development, we initiate a number of activities concurrently. We start acquiring the necessary water rights, file for interconnection and transmission agreements and begin acquiring rights of way as necessary for transmission lines. We also prepare all necessary environmental reviews and reports and begin negotiations for power purchase agreements.
As a component of our business model, when an independent geologist is able to readily identify the general location of the geothermal resource and its characteristics with a high degree of confidence, we omit drilling slim holes and begin drilling larger diameter production holes to be used as either production or reinjection wells for the production of electricity. The purpose of drilling the production and reinjection wells is to prepare the established geothermal resource for use in the commercial production of electricity. The number of production and reinjection wells required for each project will vary based upon the combined gross generating capacity of the power generating units used at each power plant and the combined production capability of the production wells. Generally, project-specific financing is not available until the well field has been at least partially drilled and a power purchase agreement is in place for a project. To date, we have funded the site identification and evaluation phase of each project, as well as the drilling of production and reinjection wells, primarily from our funds available for general corporate purposes, which we have obtained principally from the issuance of convertible debt and equity securities from time to time. However, we intend to explore and have already explored other potential alternatives to finance the drilling of production and reinjection wells for our projects, including drilling-specific investment funds, joint ventures or other strategic transactions. We have an agreement with a newly formed drilling-specific fund, Evergreen Clean Energy Fund, which is described in more detail above.
After a well is drilled and tested, it is classified as either (i) a production well; (ii) a reinjection well; or (iii) a non-commercial well. A production well is one that is capable of producing sufficient water flow and heat to generate electricity when run through a geothermal turbine. A reinjection well is one that demonstrates the necessary permeability to allow reinjection of the geothermal fluids discharged from the plant in a manner we believe will not detrimentally impact the geothermal resource or our production wells. A non-commercial well is one that does not currently demonstrate sufficient heat, water flow or permeability to be either a production well or reinjection well, or which provides inconclusive results but which we have determined to not pursue at that time for a variety of reasons including availability of funding for additional testing or drilling.
With sufficient drilling of the well field and a power purchase agreement in place, we next seek funding from third parties for the plant construction phase of the project. Third party financing sources generally require resource validation by an independent geologist prior to releasing the funds to complete the construction portion and drilling portion of the project. The third party financing companies generally contract with independent geothermal engineers to independently validate and quantify the power producing potential of the resource. The independent geothermal engineers also help monitor the drilling of the production and reinjection wells necessary to produce electricity. After each well is completed, we perform tests of the heat and volume of flow of the water for the financiers. Based upon the results of our testing, the independent engineers estimate the electricity
generating capacity of each well. When the total production capacity of the production and reinjection wells included in the applicable project achieve the electricity generating capacity needed for the planned power plant, the well field is considered completed. If the total production capacity of the wells is insufficient to generate the electrical capacity of the constructed geothermal power plant, additional wells are typically drilled accordingly.
With the preliminary results from the wells, we can determine the economic terms associated with the power plant development and the subsequent sale of the power. Accordingly, we believe that we should generally be able to obtain third party financing to complete the plant construction phase of our projects. Typical financing for geothermal projects comes in the form of project debt and tax-equity financing. Project financing can come from a variety of sources, including traditional financial institutions, large utility partners, or through government loan guarantee and grant programs. In addition to seeking traditional financing sources, we intend to explore prepaid power purchase agreements, joint ventures and other arrangements, which may provide additional sources of financing for the plant construction phase of our projects. The tax incentives associated with geothermal renewable energy projects have “placed in service” deadlines. We have incurred and may incur in the future, significant additional costs during this phase in order to meet a placed in service deadline imposed by tax rules and regulations.
While the total development time will vary from project to project, we believe we can complete the development of most projects, including well field development and plant construction, in eighteen months to two years from the time we begin drilling the well field. This rapid deployment is made possible by conducting a number of development steps simultaneously and using modular generating units. We intend to further refine and improve the speed and efficiency of this rapid deployment model as we develop additional projects.
Production Phase
The third and final phase of development is the production phase. During the production phase, the power plant is operated over its useful life. We expect to generate revenues and cash flows from two primary sources during the production phase of a project. First, we expect to generate revenues through power purchase agreements with utilities from the sale of electrical power generated by the power plant. Second, we expect to generate revenues and cash flows in the form of fees and distributions from our projects, which we expect to be funded primarily by contributions made by tax equity partners. See “Our Business Segments-Power Systems” above and “Tax Incentives” and “Financing” below.
Current Geothermal Power Projects
We have initiated the development of eight geothermal projects in our Power Systems segment to date. We have placed one power plant in service to date, which we refer to as our Thermo No. 1 plant, and we are currently selling electricity generated by the Thermo No. 1 plant.
As stated earlier, we have had to adjust our development plans by delaying certain projects. We had hoped to be in a position to move forward with the simultaneous development of the other seven sites we have initiated. In light of current conditions, we believe we need to focus most of our time and resources on the development of one or two projects we believe are best positioned for development at this time. At the present time, we intend to focus on improving the electrical output from our Thermo No. 1 plant and completing the well field development at our Lightning Dock and/or Thermo No. 2 and No. 3 projects. We will continue to undertake preliminary development activities such as permitting at the other sites we have initiated, but we do not expect to conduct any considerable development activities with respect to these projects at this time. Once we have advanced the development of the Lightning Dock and/or Thermo No. 2 and No. 3 projects to the point where we can devote resources to other projects, we intend to resume active development at one or more of our other projects. The current status of each of the eight projects we have initiated is described below:
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Thermo No. 1 Plant (Utah) We completed major construction of the cooling towers and transmission lines and installed the power generating units at the Thermo No. 1 plant, located in Beaver County,
Utah, in the fourth quarter of 2008. We completed the commissioning of the power plant in the first quarter of 2009 and, in April 2009, we began selling electricity generated by our Thermo No. 1 plant to the City of Anaheim pursuant to our power purchase agreement. The Thermo No. 1 plant is currently generating about 7.0 MW of gross electrical power. After deducting the electricity required to power the plant, which we purchase from other sources due to favorable rates, the net power sold by the Thermo No. 1 plant is approximately 6.0 MW. Both the gross output and net output of the plant sold to the City of Anaheim are below the amounts the plant was designed to produce. We are working to improve the electrical output of the plant. The development history of the Thermo No. 1 plant is described below.
In 2007, with the help of external consulting geologists, we began evaluating preliminary geologic studies of possible geothermal resources near Beaver, Utah referred to as the Thermo Known Geothermal Resource Area (the “Thermo KGRA”). The area in and around the Thermo KGRA was targeted initially because multiple geologic studies had been performed over many years in the area, and because a geothermal well had been drilled in the area that reached a temperature of 345 degrees Fahrenheit. Our consulting geologists reviewed numerous studies on the area, including gravity, ground magnetic, telluric-magnetotelluric and self-potential surveys. They also reviewed data from dozens of thermal-gradient wells that have been drilled in and around the Thermo KGRA. After analyzing all of the available data, we concluded that the Thermo area was a high-prospect area and likely suitable for at least a 10 MW geothermal power plant.
After identifying the Thermo prospect area, we began acquiring the exclusive geothermal rights to land located in the Thermo prospect area. Beginning in April 2007, we entered into several lease agreements with the State of Utah School and Institutional Trust Lands Administration (the “State”) for geothermal rights in the Thermo area totaling approximately 5,500 acres. The initial term of the geothermal leases is 10 years, subject to extension for as long as we are actively pursuing or generating electricity from geothermal resources from the leased lands. Annual delay rental payments on the State of Utah leases are $1.00 per acre and are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are paid based on a percentage of electrical sales from the plant. The leases provide for rights to the geothermal resource and rights to utilize the surface as necessary for the development of the geothermal rights.
Additionally, in September, 2007, we entered into a lease agreement with a private landowner to obtain the geothermal rights on approximately 11,000 acres of land located in the Thermo area. Through this lease, we acquired a 75% undivided interest in the geothermal rights on the properties. We acquired the remaining 25% undivided interest via a lease with another private entity, which was finalized in the fourth quarter of 2009. The expenses associated with the negotiation, document preparation, due diligence and other acquisition related activities were capitalized as part of the land acquisition. The initial term of the lease with a 75% undivided interest is ten years. Cumulative annual delay rental payments on the lease with a 75% undivided interest is $1.00 per acre and is due on each respective anniversary date until production has begun. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant. The lease provide for rights to the geothermal resource and rights to utilize the surface as necessary for the development of the geothermal rights. The lease on the remaining 25% undivided interest has a five year initial term with other provisions similar to the 75% lease.
While the leases mentioned above cover most of the area we consider to be the heart of the Thermo geothermal resource, we have signed additional agreements with private landowners and the State of Utah in the vicinity of the Thermo area covering an additional approximately 35,000 acres. We anticipate that we will dedicate a small portion (likely less than 1,000 acres) of our leased acreage for each individual 10-11 MW project we develop. We expect that a parcel of approximately 640-800 acres will be ultimately dedicated to the Thermo No. 1 plant. The Thermo No. 1 plant can be accessed utilizing public roads suitable for unrestricted ground transportation.
After acquiring the appropriate geothermal leases, we tasked our external geologic consultants with performing a Resource Evaluation as described above. During the evaluation process, we obtained a high degree of confidence supporting the conclusion that the Thermo No. 1 site contained a commercially viable geothermal resource to continually produce electricity without any substantial degradation in the heat resource. Therefore, in November 2007, prior to the completion of the final Resource Evaluation report, we omitted drilling slim holes and began drilling larger diameter production and reinjection wells for the production of electricity. Shortly thereafter, we received the written Resource Evaluation report. We continued drilling and after completing the drilling of several wells, we commissioned an independent geothermal engineer to issue an additional report on the wells and the overall resource. The report, issued in August of 2008, concluded that parts of our Thermo leasehold are underlain by a relatively large geothermal reservoir and that the resource underlying the proposed project site could support a 10 MW project. The report also concluded that the overall Thermo resource could likely support well over 200 MW of power generation. The reservoir is contained within relatively thin intervals in Paleozoic rock (predominantly limestone, dolomite and quartzite).
On March 10, 2008, prior to obtaining the geothermal engineer’s report, we executed a renewable power purchase and sale agreement (the “Thermo PPA”) with the City of Anaheim, California. Subject to certain conditions, the Thermo PPA provides for the delivery by the Thermo No. 1 plant of up to 11 megawatts of geothermal renewable power for 20 years. Subject to certain exceptions, we were required to begin delivering electricity from the power plant no later than May 15, 2009. The Thermo PPA provides for a selling price of $78 per megawatt hour with a two percent per annum increase over the term of the Thermo PPA. Under the Thermo PPA, the City of Anaheim also pays for the “wheeling costs,” or cost for transmission, of the electricity from the Thermo No. 1 plant to the City of Anaheim.
In May 2008, concurrent with the drilling of the wells, we began construction of the Thermo No. 1 plant and began receiving 50 PureCycle units. We were able to obtain the financing to complete the construction of the Thermo No. 1 plant with the related equipment, transmission lines, substations and pipelines from the well heads to the PureCycle units from Merrill Lynch. For further discussion of the financing arrangement, please refer to “Financing-The Thermo Financing” section below.
We completed the major construction of the cooling towers, transmission lines and setting of the PureCycle units at the Thermo No. 1 plant in October of 2008. Commissioning testing of the PureCycle units was completed in the first quarter of 2009 using two production wells and one reinjection well that we had connected to the plant. In April 2009, we began selling electricity generated by the Thermo No. 1 plant to the City of Anaheim pursuant to our power purchase agreement. Accordingly, in 2009 we reclassified the cost of the related leases, wells, transmission lines and substations and construction in progress as “geothermal property, plant and equipment” on the balance sheet. For further discussion and summary of the capitalized costs of the Thermo No. 1 plant, refer to Note 5. “Geothermal Property, Plant and Equipment” below.
During the year ended December 31, 2009, we delivered 25,200 MW hours of electricity to the City of Anaheim. Thus far, we have been unable to operate the plant at full capacity due to insufficient heat and flow from the production wells that provide geothermal water to the plant. In the fall of 2009 we undertook a comprehensive review of the plant and well field operations at the Thermo No. 1 plant and, together with outside experts and our financing partners, developed a plan for increasing the output of the Thermo No. 1 plant. The key component of this plan was to re-work certain wells in order to eliminate down flow of a shallower, cooler zone of geothermal fluids which was mixing with the deeper, hotter zones. In general, this cooler zone contains geothermal fluids in the range of 200 F, while the deeper zone contains temperatures greater than 300 Fahrenheit. We believe that well field work and optimization of certain operations at the plant, have the potential to significantly increase the net power production from the plant during 2010. However, we have not completed all of the necessary well field or plant work and testing, and we cannot be certain the changes will allow us to significantly increase the power production at the Thermo No. 1 plant. Although well field heat up is taking longer
than originally anticipated and additional work may be necessary to improve the output of the wells, we continue to believe we can significantly increase power production at the Thermo No. 1 plant and eventually be able to operate the Thermo No. 1 plant at its full designed capacity of 11 MW.
The power produced by the Thermo No. 1 plant is purchased by the City of Anaheim, California pursuant to a power purchase agreement (the “Thermo PPA”), which we entered into on March 10, 2008, before the plant was constructed. Subject to certain conditions, the Thermo PPA provides for the delivery by the Thermo No. 1 plant of up to 11 megawatts of geothermal renewable power for 20 years. The Thermo PPA provides for a selling price of $78 per megawatt hour with a two percent per annum increase over the term of the Thermo PPA. Under the Thermo PPA, the City of Anaheim is also obligated to pay for the “wheeling costs,” or cost for transmission, of the electricity from the Thermo No. 1 plant to the City of Anaheim. There is no penalty under the Thermo PPA for delivering less than 11 megawatts of geothermal renewable power.
We have drilled seven production wells and two reinjection wells that we expect to utilize for the plant. Of these wells, we believe that one may eventually be transferred to and used as a production well for the Thermo No. 2 plant. This decision is dependent upon the performance of the existing wells.
The geothermal resources utilized by the Thermo No. 1 plant are believed to be renewable so long as the plant is operated at or below the maximum level studies indicate that the resource will support, all of the geothermal fluids are recycled without losses, and the hydrological balance of the geothermal resource is properly maintained.
In addition to the wells described above, we drilled two wells that we, in consultation with our drilling and geothermal consultants, determined to be non-commercial wells at this time. The first of these two wells is the first well that we drilled on the site. This well exhibited positive early testing and appeared to be a good production well. However, the well became partially obstructed during the final stages of the drilling process. Shortly thereafter, we terminated our relationship with our original drilling contractor and hired a new contractor to re-drill the well. The re-drilled well again exhibited strong signs of being a good production well but again encountered problems during the final stages of drilling, and became partially obstructed. Even with the obstruction, the well still exhibited signs of being useful for commercial production. In the fourth quarter of 2008, however, acting on the advice of our consultants, we determined that it would be better to abandon further efforts to produce the well and drill an entirely new well adjacent to the original well. The new well is one of the seven production wells described above.
We are in the process of implementing a limited bottom-cycling operation at the Thermo No. 1 plant to improve the electrical output of the Thermo No. 1 plant. In a bottom-cycling operation, the discharged geothermal water from the main plant is cascaded through a second set of PureCycle units, extracting more heat to generate additional power.
We have experienced certain delays and cost overruns relating to the construction of the Thermo No. 1 plant and related well field. The Thermo No. 1 plant is the first ever large-scale commercial application of the UTCP generation units and the first plant built under our rapid-deployment approach so such delays and overruns are not entirely unexpected. The key drivers of the delays and cost overruns are as follows:
Well Field Development:
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Increased costs to broaden previous well field plans.
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Complications encountered by drilling contractors.
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High demand for drilling services and related materials due to the rapid increase in the price of oil.
Construction:
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Wider than planned step-outs for injection wells, which increased piping costs, due to concerns of lenders.
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Additional costs related to establishing the greater Thermo area.
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High demand for steel, concrete and other commodities caused prices to increase.
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Accelerated construction schedule required overtime and other additional costs.
Equipment:
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Expenses associated with installing PureCycle units for the first time, which allowed us to identify design changes for the benefit of future plants.
Transmission:
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In anticipation of future plants, we built a larger transmission infrastructure.
The Thermo No. 1 plant is accessible by road suitable for unrestricted ground transportation. The plant is interconnected to a power line along Thermo Road owned by Rocky Mountain Power.
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Lightning Dock Plant (New Mexico): We are in the process of obtaining the final, necessary permits for the Lightning Dock plant. Numerous exploratory wells and two production wells were drilled prior to our acquiring the site. We have purchased and received most of the essential major equipment needed for construction of the geothermal power plant such as the cooling towers, transformers and other electronic equipment which is currently being stored at the site. We are currently evaluating multiple turbine suppliers and expect to make a final decision with respect to which supplier to use for the construction of the power plant in the first half of 2010. In the second quarter of 2010, we intend to re-drill and test an existing well for production capabilities prior to seeking funding to drill additional production and reinjection wells. We are in the process of selecting a drilling contractor.
Our lease acquisition costs for the Lightning Dock plant totaled $4.7 million. In addition, we have taken delivery of components for the cooling towers and other transmission equipment totaling $3.5 million. We had previously taken delivery of 48 PureCycle units for which the title was returned to PWPS in 2009. We currently anticipate that the total costs of the completed Lightning Dock geothermal power plant will range from $65.0 to $80.0 million, including the costs of well field development and transmission line construction. We intend to seek financing for the drilling of production and reinjection wells. Once the production and reinjection wells have been completed and it is demonstrated that the wells can support a power plant of 12-15 MW or larger, we intend to seek financing for the construction of the plant. The development history of the Lightning Dock plant is described below.
We obtained an assignment of a BLM Lease and acquired other miscellaneous assets from a subsidiary of GeoLectric, LLC in 2007 (the “Purchase”). Under the BLM Lease, we obtained rights to begin development of one or more geothermal power plants on the property located on approximately 2,500 acres in Hidalgo County, New Mexico. Subsequent to the Purchase, the BLM converted another lease into Lightning Dock’s name for 640 acres of property next to leased property acquired from GeoLectric, LLC at no cost. We also obtained the exclusive rights to the geothermal energy resource contained on the property. The initial lease term of the assigned BLM Lease began in January 1979 and has been extended based upon certain conditions in the lease until January 2024. Annual delay rental payments of $5,000 are required on each anniversary date until geothermal power production has begun. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant. We have capitalized certain legal fees directly associated with completing the Purchase and obtaining the BLM lease. We also capitalized the obligations we assumed to plug certain abandoned wells located on the property.
With respect to the same 3,140 acres in Hidalgo County, New Mexico, in January 2008, we also entered into a surface access and use lease agreement, or surface lease agreement, with a private property owner in New Mexico (the “New Mexico Property Owner”) and paid $320,000 to obtain surface right-of-way access and drilling rights. The term of the surface lease agreement continues until our geothermal rights respective to the BLM lease have expired. Pursuant to the surface lease agreement, we also obtained certain water rights for the project.
In August 2008, we paid $1,200 as a lease bonus and entered into a ground lease agreement for 20 acres with the New Mexico Property Owner. The term of the ground lease agreement is indefinite, as long as the power plant, transmission and related facilities on the leased property are producing or capable of producing electricity from geothermal resources. No annual payments are required for the ground lease agreement. Under the ground lease agreement, we obtained the right to construct and operate a geothermal power plant and transmission facilities on the property.
The New Mexico resource is one of the most studied moderate-temperature geothermal resources in the country. The New Mexico resource is located in a topographic low, bounded on the west by the Peloncillo Mountains and on the east by the Pyramid Mountains. Relatively young basaltic volcanism is widespread in the area. Rocks exposed in the bordering mountain ranges include granodiorite, Paleozoic and Mesozoic sedimentary rocks, Tertiary/Cretaceous volcanic rocks, Tertiary intrusive rocks, and Tertiary conglomerate. The prominent features of the valley are the north east trending Animus Valley and western faults, which displace the Tertiary volcanic tuft in fractured basement rocks creating an ideal location for geothermal activity. The New Mexico property can be accessed by road suitable for unrestricted ground transportation and is approximately 14 miles from the nearest transmission lines. Based on the leases described above, we believe we have secured the necessary surface rights and rights of way to construct the power plant. We believe that we can obtain the necessary rights of way to construct an interconnection line to connect the planned power plant to the existing nearby transmission lines. The source of water to be used at the property is an underground well located at the site. There is a greenhouse operation and a fish farm nearby that utilize the geothermal resource for direct-use heating.
Prior to our obtaining an interest in the Lightning Dock leases, multiple shallow and deep wells had been drilled on the leased property exhibiting temperatures in the range of 227 to 329 degrees Fahrenheit. Previous studies indicate that an operational production well on the leased property has the potential to generate up to approximately 7 MW of electricity. Based upon the available studies and on the evaluation completed by our external geologic consultants, we concluded with a high degree of confidence that a commercially viable geothermal resource exists beneath the Lightning Dock project surface. We have received permits for drilling and storm water discharge, received a Finding of No Significant Impact (FONSI) related to the federal NEPA requirements, received permits for up to five new production and three reinjection wells, and are in the process of finalizing other permits to be able to begin drilling at the site. However, to date, we have not drilled production or reinjection wells on this site. Regarding use of surface water for cooling operations, we are awaiting final approval to proceed with permitting from the local government officials, pending a ruling relating to a protest filed by a nearby land owner.
The power generated from the facility will be sold to the Salt River Project Agricultural Improvement and Power District in Phoenix, Arizona pursuant to a 20-year power purchase agreement.
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Thermo No. 2 and No. 3 Plants (Utah): Based on our Preliminary Site Review, the written Resource Evaluation report on the Thermo resource, and the report prepared by our consulting reservoir engineers, we concluded with a high degree of confidence that the Thermo area contained a commercially viable geothermal resource which could support additional power plants. When it became clear that the geothermal resource located on our leased lands in the Thermo area could support more than just the Thermo No. 1 plant, we began preliminary planning for the Thermo No. 2 and Thermo No. 3 projects including preparing permit applications, securing water rights, filing for transmission interconnection, securing rights of way for the expected new transmission line, and
beginning environmental work. These permits include, among others, air quality permits, hazardous materials permits, and storm water discharge permits. We have begun obtaining the necessary permits for the Thermo No. 2 project and the Thermo No. 3 project. At the present time, we are seeking funding to continue the development of the Thermo No. 2 and Thermo No. 3 plants.
For additional information regarding a description of the Thermo area, the terms and conditions associated with the applicable geothermal lease agreements, and a discussion of the studies performed to obtain a high degree of confidence that a commercially viable geothermal resource exists in the Thermo area, please see the description of the “Thermo No. 1 Plant (Utah)” above. The Thermo No. 2 and 3 project sites are accessible utilizing public roads suitable for unrestricted ground transportation. The Thermo No. 1 plant was able to interconnect to the Rocky Mountain Power system via an approximately 6 mile long transmission line that we built. We are currently obtaining the proper easements and right of way permits from the federal, state and private land owners to construct a 17 mile long transmission line from our Thermo No. 1 interconnect location to a Rocky Mountain Power system interconnect location. We have also purchased the appropriate transformers and some reclosers in anticipation of obtaining the necessary approvals to proceed with the construction of the proposed transmission lines totaling $1.9 million as of December 31, 2009. We anticipate the total cost to complete the 17 mile transmission line to range between $15.0 to $18.0 million.
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Klamath Falls Plant (Oregon): We have obtained the necessary zoning permit and drilling permit to drill the first well at our Klamath Falls project. We are in the process of obtaining the necessary water change permit for injecting water into the ground, along with permits for construction, air quality and other permits necessary to begin construction of our geothermal power plant. We have performed some preparations at the site, but have not begun drilling activities. At the present time we are focusing primarily on other projects. Other than obtaining additional permits, as appropriate, we do not expect to conduct any significant development activities with respect to the Klamath Falls plant until we have advanced the development of one or more of our other projects. The timing of beginning and completing the construction of the Klamath Falls plant will in large part depend upon the timing of available financing. The development history of the Klamath Falls project is described below.
With the assistance of external consultants, we identified the Klamath Falls site for evaluation. The site has a few existing shallow wells with temperatures of approximately 195 degrees Fahrenheit that have been used to supply a greenhouse operation for approximately twenty-five years. We undertook a Preliminary Site Review. Based upon data obtained from an independent geochemistry study and the existing shallow wells, we determined to proceed with the Klamath Falls project.
In January 2008, we paid $10,000 as a lease bonus and entered into a geothermal lease with private land owners for 984 acres approximately 13 miles south of Klamath Falls, Oregon. The leased property is a farm that contains a residential house, barns, hay storage sheds, greenhouses and a bio diesel plant. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease term is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rental payments of $1,000 are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant.
Upon signing the lease, we retained independent geological consulting firms to perform a Resource Evaluation to further evaluate the information known about the Klamath Basin and conduct additional geologic and geophysical surveys to determine drilling targets. The independent geologists concluded that geothermal fluids at the Klamath Falls project site are fault-controlled deeply circulating waters that have encountered temperatures up to about 248 degrees Fahrenheit. The hot wells in the Klamath Falls project area, ranging from 194 degrees Fahrenheit to 199 degrees Fahrenheit, are associated with a fault that generally bounds in the range. This fault is part of the fault system that runs through an area where opal and silica veins are found in both sandstone and basalt. Hydrothermal alteration and self-potential anomalies are also found in this area. The geologists concluded that the coalescence of these
factors suggest that hot water is circulating throughout the fault system. Based upon the studies and evaluations completed by our external geologic consultants, we reached a high degree of confidence that a commercially viable geothermal resource exists beneath the Klamath Falls project surface.
The Klamath Falls project can be accessed by road suitable for unrestricted ground transportation and is approximately 6 miles from the nearest appropriate transmission interconnection location. We have begun the process of securing rights of way for the proposed transmission line to interconnect the project to the grid.
In addition to the lease acquisition costs for the Klamath Falls project totaling $10,000, we have incurred permitting costs totaling $78,100.
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Truckee Plant (Nevada): We have obtained the drilling, construction, air quality, water reinjection, water quality and other permits that are necessary to begin drilling at the Truckee site. We are in the process of obtaining the environmental assessment from the BLM that is necessary to construct the Truckee plant. We drilled the first well at this site in the fourth quarter of 2007. However, the results of the first well were inconclusive. We will have additional independent geologic studies performed before we proceed with any additional drilling. With other projects showing greater geothermal resources, we have sought financing for our other projects ahead of the Truckee project. Further development on the Truckee resource will be dependent upon more positive geological studies and the availability of financing for the resource. At the present time we are focusing primarily on other projects. Other than obtaining additional permits, as appropriate, we do not expect to conduct any significant development activities with respect to the Truckee plant until we have advanced the development of one or more of our other projects. The development history of the Truckee plant is described below.
With the assistance of external consultants, we identified a site in Nye County, Nevada known as the Big Smoky Valley for evaluation. We and our external geologic consultants prepared a Preliminary Site Review of the entire valley by gathering historic geophysical data that was available for the Big Smoky Valley area. For example, regional-scale gravity data, audio-magnetotelluric, magnetotelluric soundings, and telluric profiles were completed as part of a USGS exploration program in 1976. Additional gravity profiles and limited electrical resistivity and shallow temperature measurements were completed by the Nevada Bureau of Mines under a Department of Energy program. The most recent geophysical surveys completed include a ground magnetic survey. As part of the Preliminary Site Review we also analyzed land positions and transmission access.
Based on the results of the Preliminary Site Review we identified three areas to pursue within the valley: the Truckee project area, the Devil’s Canyon project area, and the Trail Canyon project area. The Truckee project is located near the mid-point of the Big Smoky Valley on generally flat to gently sloping land. We identified certain private and federal lands in the area to pursue. In December 2006, we paid $25,000 in cash, as a lease bonus, to cover the first year rental obligation, and issued to the owner 25,000 restricted shares of our common stock that had a fair value of $115,250 on the grant date to obtain the right to begin development and construction of geothermal power plants on three ranches in central Nevada consisting of approximately 11,600 acres. In August 2007, we also granted to the private property owner 35,000 options at a strike price of $15.10 representing the closing market price on the date of the grant as consideration to cancel previously awarded contingently vesting stock. The fair value of the 35,000 options was recorded as power project leases totaling $424,000. Annual delay rental payments total $34,800 on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant. The terms of the lease agreement are for 50 years subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Lease acquisition costs for the Truckee project total $755,900.
In June 2007, we paid $40,000 to the private land owner that held the geothermal rights and entered into a geothermal lease agreement for the same 11,600 acres described above. Under the terms of this
lease agreement, there are no delay rental payments. Of the 11,600 acres of leased property, approximately 1,000 acres have been designated for the Truckee project. In September 2007, we participated in a United States Bureau of Land Management (“BLM”) auction to obtain the geothermal development rights for certain parcels of land in the Truckee project site. We successfully won the bid for one parcel of land and entered into a 10-year lease agreement with the BLM covering a total of approximately 5,000 acres. Our payment obligation under this lease was $55,000, which was paid in the third quarter of 2007. Pursuant to the terms of the BLM leases, annual delay rental payments total $15,000. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant.
After we acquired the geothermal rights to the Truckee project, we contracted with external geologic consultants to perform a Resource Evaluation and assist with the determination of the drilling locations. Based upon a completed study and evaluation by our external geologic consultants, we received a high degree of confidence that a commercially viable geothermal resource exists beneath the Truckee project surface. As a result, we omitted drilling slim holes, and began drilling a production well in late 2007 to a depth of approximately 7,000 feet. Preliminary testing of the well indicated that temperatures were within commercial ranges but the flow data was inconclusive as to whether the well could be used to produce electricity. Since the results of the well were inconclusive, we determined to allow the well to stabilize and redirect efforts toward the construction of the Thermo No. 1 plant and delayed further testing of the Truckee well and drilling of the Truckee resource.
As of December 31, 2008, we performed an impairment review of the Truckee well and determined that it should be impaired. Management believes that the Truckee well could still be used in the production of electricity as either a production or reinjection well in the future should the appropriate financing be obtained. However, until more detailed testing is performed on the well we will not know if it will be a production well, a reinjection well or will be abandoned.
The Truckee project can be accessed by road suitable for unrestricted ground transportation and is approximately one mile from the nearest appropriate transmission interconnection location.
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Devil’s Canyon Plant (Nevada): We have obtained drilling permits for up to eight production wells and three reinjection wells at our Devil’s Canyon project. We are in the process of obtaining the necessary environmental assessment permit from the BLM, water change permit for reinjecting water into the ground, construction, air quality, environmental and other permits necessary to begin construction of our geothermal power plant. We have not yet begun drilling activities. At the present time we are focusing primarily on other projects. Other than obtaining additional permits, as appropriate, we do not expect to conduct any significant development activities with respect to the Devil’s Canyon plant until we have advanced the development of one or more of our other projects. The timing of beginning and completing the construction of the Devil’s Canyon plant will in large part depend upon the timing of available financing. The development history of Devil’s Canyon plant is described below.
The Devil’s Canyon project is located in the southern part of Big Smoky Valley, Nye County, Nevada on generally flat to gently sloping land. Based upon the Preliminary Site Review we performed on the Big Smoky Valley described above, we identified the Devil’s Canyon area as an area of high interest. The Devil’s Canyon area exhibits several geothermal anomalies including an active hot spring. A geothermal well drilled on an adjacent property in 1963 exhibited temperatures of 265 degrees Fahrenheit. Based on these positive signs, we determined to proceed with the Devil’s Canyon project. We have also obtained subsequent external studies from independent consultants concluding that the Devil’s Canyon resource equilibrium temperatures are likely in the 240-270 degrees Fahrenheit range and that the resource is fault controlled. Currently, additional geologic studies and other preparations are being done on the site.
Our Devil’s Canyon leases are adjacent to certain federal lands administered by the BLM which are under lease to Oski Energy (“Oski”), another geothermal developer. In 2009, we entered into a
cooperative exploration agreement with Oski. Under the agreement, Oski performed certain geophysical studies on both their leased parcels and our leased parcels in an attempt to better understand the Devil’s Canyon resource. Under the agreement, we would have to pay for a portion of the study costs in order to have access to the data. We are currently discussing these tests with Oski and expect to add data from their studies to our Devil’s Canyon resource review in the second quarter of 2010.
In February 2007, we entered into a lease agreement with a private property owner covering approximately 155 acres in Devil’s Canyon. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial term of the lease agreement is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Concurrently, we were assigned the rights of the private property owner’s BLM lease covering 240 acres. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The remaining term of the BLM lease agreement is four years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. In June 2008, we leased an additional 600 acres of private land from another private landowner adjacent to our previously leased property. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial term of the lease agreement is 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rental payments of $20,000 are due on each anniversary date until production begins.
Our Devil’s Canyon geothermal leases are located on ranches that contain a shed with no other structures.
In December 2008, we purchased a cold water well containing certain water rights on property that we had leased for geothermal development. We expect this well to provide a portion of the water needed to operate the Devil’s Canyon plant.
The Devil’s Canyon project can be accessed by road suitable for unrestricted ground transportation and is less than one mile from the nearest appropriate transmission interconnection location. We have begun the process of securing rights of way for the proposed transmission line to interconnect the project to the grid.
In addition to the lease acquisition costs for the Devil’s Canyon project totaling $45,700, we incurred permitting costs totaling $121,200.
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Trail Canyon Plant (Nevada): We have not yet obtained any permits for the Trail Canyon project. We are in the process of obtaining the necessary environmental assessment permit from the BLM, and are moving forward with drilling permits, the water change permit for re-injecting water into the ground, construction, air quality and other permits necessary to begin construction of our geothermal power plant. Accordingly, we have not yet begun drilling activities. We currently anticipate that we will begin drilling activities in 2010 or later. At the present time we are focusing primarily on other projects. Other than obtaining additional permits and conducting additional studies, as appropriate, we do not expect to conduct any significant development activities with respect to the Trail Canyon plant until we have advanced the development of one or more of our other projects. The timing of beginning and completing the construction of the Devil’s Canyon plant will in large part depend upon the timing of available project financing. The development history of the Trail Canyon plant is described below.
The Trail Canyon project is located in the northern part of the Big Smoky Valley on generally flat to gently sloping land. As part of our Preliminary Site Review of the Big Smoky Valley, we identified the Trail Canyon area as a high-prospect area. Data obtained from external studies indicate the existence of several geothermal anomalies and an active hot spring with promising geochemistry temperatures in the 260 degrees Fahrenheit range. Once we have made substantial progress developing the well fields at our Lightning Dock and Thermo No. 2 and No. 3 projects, we expect to undertake additional studies to determine the highest prospect drill sites.
After the Preliminary Site Review, we began acquiring land on or near the Trail Canyon project site. In January 2007, we paid $5,000 and issued 5,000 restricted shares of our common stock to a private land owner and entered into a geothermal lease agreement on 635 acres of private land in the Trail Canyon area. The terms of the lease agreement are for 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rentals total $635 on each anniversary date of the lease until production of electricity begins. In addition, concurrent with entering into this lease agreement, the private land owner assigned to us a BLM lease in the Trail Canyon project for the same 635 acres. The BLM lease contains the rights to develop and construct a geothermal power plant. The term of the BLM lease is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rentals for the BLM lease total $635 due on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by these leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
In September 2007, we participated in a United States BLM auction to obtain the geothermal development rights for certain parcels of land in the Trail Canyon project site. We successfully won the bid for one parcel of land and entered into a 10-year lease agreement with the BLM covering a total of approximately 1,900 acres. Our payment obligation under this lease was $126,800, which was paid in the third quarter of 2007. Pursuant to the terms of the BLM leases, annual delay rental payments total $5,700. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant.
In August and November 2007, we paid a total of $5,000 and entered into seven separate lease agreements with seven private land owners of the same private property near the Truckee project drilling site consisting of 4,444 acres to obtain the right to develop and construct a geothermal power plant. The terms of the lease agreements are for 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Pursuant to the terms of these lease agreements, annual delay rentals total $4,444 on each anniversary date until production of a geothermal power plant begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
In May 2008, we paid $15,000 as a lease bonus and entered into a geothermal lease with private land owners for 560 acres in the Trail Canyon project. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease term is 15 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. The annual delay rental payments total $5,000 on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
The Trail Canyon project can be accessed by road suitable for unrestricted ground transportation and is approximately three miles from the nearest appropriate transmission interconnection location. We have begun the process of securing rights of way for the proposed transmission line to interconnect the project to the grid.
In addition to the lease acquisition costs for the Trail Canyon project totaling $179,600, we incurred permitting costs totaling $239,000.
The following map indicates the geographical locations of our projects:
As described above, we have initiated two additional projects in the Thermo area because that area appears to have the potential to support additional plants. We believe that the geothermal resource for each of these projects has the potential to provide at least enough geothermal energy for a commercial power plant of approximately 20 MW of net electrical power. Like the Thermo No. 1 plant, we expect that other project sites we develop may have potential resources to generate more than 10 MW of net electrical power. We intend to seek to maximize the full power generating potential of all the sites we select for development.
The timing for construction and completion of each of the projects described above will depend on a number of factors, including the receipt of necessary permits, timely granting of interconnection and transmission access, and the ability to obtain adequate financing for both the well-field development phase and the plant construction phase of each project. Uncertainties associated with these factors could result in unexpected delays. In addition, the feasibility of a number of the projects described above is still subject to further geological testing and/or drilling to determine whether an adequate geothermal resource exists to support a geothermal power plant.
In addition to the projects currently under development, we intend to initiate the development of additional projects from time to time. However, the number of projects we initiate each year will depend on a number of factors, including the availability of adequate financing, the availability of adequate geothermal resources, the demand for renewable power, the number of projects we have under development, and our available resources to devote to our project development efforts.
Tax Incentives
In order to promote the production of renewable energy, including geothermal energy, the federal government has created several significant tax incentives. These tax incentives are instrumental to our ability to finance and develop geothermal power plants by providing increased economic benefits. If the available tax incentives were reduced or eliminated, the economics of the projects would be adversely affected and there could be reductions in our overall profitability or the amount of funding available from tax equity partners. Some projects may not be viable without these tax incentives.
Available federal tax incentives include deductibility of intangible drilling costs, accelerated depreciation, depletion allowances and the ITC, all of which currently are permanent features of the Internal Revenue Code with respect to geothermal power projects. In addition, the Recovery Act extended the availability of the PTC for geothermal projects placed in service before 2014 and created a new grant program for geothermal projects that are placed in service in 2009 or 2010, regardless of when construction begins, or for which construction begins in 2009 or 2010 and which are placed in service before 2014.
The ITC is claimed in the year in which the qualified project is placed in service, and the amount of the credit is a specified percentage (10% or 30%) of the eligible costs of the facility. All or some of the ITC is subject to recapture if the property eligible for the credit is sold or otherwise disposed, or ceases to be eligible property within five years after being placed in service. In lieu of claiming the ITC, a project owner generally can claim the PTC during the first ten years after the project is placed in service. The amount of the PTC is adjusted for inflation. For 2009, the amount was $21.00 per megawatt hour of electricity produced from the facility and sold to unrelated parties. The amount for 2010 has not been announced. The amount of the PTC also is subject to phase-out if the national average price of electricity produced from qualified energy resources exceeds an inflation adjusted threshold.
In addition, pursuant to the Recovery Act, an owner may elect to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or the PTC. For a geothermal project, the amount of the grant is 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the date the U.S. Treasury Department deems the application is properly submitted and complete. All or some of the grant is subject to recapture if the property eligible for the grant is sold or otherwise disposed, or ceases to be eligible property within, five years after being placed in service. None of the grant should be included in federal taxable income, but may be included in applicable state taxable income.
Owners of projects also are permitted to depreciate for tax purposes most of the cost of the power plant on an accelerated basis, generally, over a five- year period. If an owner elects to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or PTC, or if the owner elects to receive the ITC, the basis of the property for depreciation purposes is reduced by an amount equal to 50 percent of the grant or ITC, whichever is applicable.
All of these programs are subject to review and change by Congress from time to time. In addition, several of the programs are currently scheduled to expire, and continuation of those incentives will require affirmative Congressional action. Moreover, there are ambiguities as to how some of the provisions of the Recovery Act will operate.
Many of the tax incentives associated with geothermal power projects generally are beneficial only if the owners of the project have sufficient taxable income to utilize the tax incentives. Due to the nature and timing of these tax incentives, it is likely that the tax incentives available in connection with our geothermal power plants (other than the grant in lieu of the ITC and PTC) will exceed our ability to efficiently utilize these tax benefits for at least several years of operations. Therefore, an important part of our strategy involves partnering with investors that are able to utilize the tax incentives to offset taxable income associated with their operations unrelated to our geothermal power plants. For example, a corporation in an unrelated industry may be willing to
finance the development of a geothermal power plant in exchange for receiving the benefit of the tax incentives, which it could then use to reduce the tax liability associated with its regular operations.
In addition to the federal tax incentives, certain state tax benefits may be available for some of our geothermal power projects. These incentives vary state by state and generally range from sales and property tax exemptions to state production tax credits.
The current economic conditions in the United States and around the world are likely to make it more difficult to secure the financing necessary to develop our projects. Weak economic conditions generally reduce the demand for tax-driven investments because many potential investors have or expect to have little or no tax liability that can be reduced by such investments. While the demand for these types of investments is significantly lower than it has been in recent years, we believe the tax incentives available to our geothermal power projects remain an attractive investment option for companies that are in a position to benefit from these tax incentives.
Financing
To date, we have financed our operations principally through the sale of equity and equity related securities, and borrowings under our line of credit. We also financed the plant construction phase of our Thermo No. 1 plant through a combination of debt financing and tax equity capital that we obtained through Merrill Lynch.
We have incurred losses since inception and we are not operating at cash flow breakeven. Our cash balance at year end is not sufficient to fully fund our business plan or to satisfy our cash requirements for our anticipated additional land acquisitions, development activities and business growth over the next twelve months.
The execution of our business plan and the funding of our capital expenditures are dependent on our ability to obtain additional financing for our activities, including power plant development. In addition, the availability of such financing will affect the timing, pace, scope and amount of our capital expenditures. We believe we will be able to finance our activities through financing of tax benefits by tax equity partners, debt or equity financing, project financing, government funding from grants, loan guarantees or private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, pre-paid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties, or a combination of these sources. There can be no assurance, however, that we will be able to obtain additional financing, reduce expenses or successfully complete other steps to continue as a going concern. If we are unable to obtain sufficient funds to satisfy our future cash requirements, we may be forced to curtail or cease operations, dispose of assets or seek extended payment terms from our vendors. Such events would materially and adversely affect our financial position and results of operations.
As described above, an important part of our strategy for obtaining the necessary capital to fund the development of geothermal power plants is to develop strategic alliances with utilities that need clean renewable power and tax equity partners who are in a position to take advantage of certain tax benefits associated with the geothermal power plants we intend to develop. Through these alliances, we will seek to obtain funding pursuant to prepaid power purchase agreements and tax equity financing agreements. We also intend to pursue government funding from grants, loan guarantees or other incentives.
We believe that in the current economic environment, the combination of tax equity partnerships, private equity funds, and other sources with the 30% renewable energy grants that are currently being offered by the government, may provide additional sources of capital to help fund our development efforts. However, until financing can be obtained through these types of alternatives, we will also need to fund certain early-stage development activities, such as permitting, analysis of the well field and drilling slim holes to verify the resource. We will need to fund these expenditures from our existing cash balances, additional debt or equity financing,
private drilling funds, joint ventures, the sale of one or more of our projects or interests therein, or a merger and/ or other transaction. Although we believe that we will be able to obtain sufficient financing to successfully implement our business plan, we cannot provide any assurances that we will be able to obtain financing on favorable terms, or at all.
The Thermo Financing
On May 16, 2008, pursuant to a commitment letter with Merrill Lynch, we and our fully-consolidated subsidiary, Thermo No. 1 BE-01, LLC (the “Thermo Subsidiary”) entered into a financing commitment letter (the “Thermo Commitment”) with Merrill Lynch relating to the project financing and tax equity funding for the Thermo No. 1 plant. On August 31, 2008, we finalized the project financing arrangements for the Thermo No. 1 plant and entered into definitive agreements (the “Thermo Financing Agreements”) that provided debt financing and tax equity capital for the Thermo No. 1 plant. The Thermo No. 1 plant is held by our Thermo Subsidiary which is responsible for debt service, all maintenance and operations expenses, and the payment of various fees and distributions. The Thermo Financing Agreements provided for approximately $31.2 million of permanent non-recourse debt financing for the Thermo No. 1 plant with a fixed annual interest rate of 7.00%. The Thermo Subsidiary received proceeds from the debt financing of approximately $26.1 million for construction of the Thermo No. 1 plant after an original issue discount of approximately $5.0 million. From the proceeds of the debt financing, we received approximately $14.1 million from the Thermo Subsidiary as repayment for construction costs at the Thermo No. 1 plant that were incurred by us prior to closing the project financing. Under the Thermo Financing Agreements, approximately $24.5 million of tax equity capital for the tax benefits associated with the Thermo No. 1 plant was provided to the Thermo Subsidiary by ML Holdings. Our equity contribution to the Thermo Subsidiary of approximately $29.0 million was comprised primarily of the partially completed well field.
Under the Thermo Financing Agreements, Merrill Lynch was entitled to receive 99% of all residual cash flows from the Thermo No. 1 plant after paying all expenses and debt service until the date that Merrill Lynch achieved its target rate of return (the “Flip Date”). After the Flip Date, Merrill Lynch was entitled to receive 5% of the residual cash flows for the remaining useful life of the Thermo No. 1 plant. In connection with the Thermo Financing Agreements and the Thermo No. 1 plant financing, we and our affiliates entered into certain other ancillary agreements, including a Pledge Agreement with Deutsche Bank to secure payment and performance under the Credit Agreement. The Pledge Agreement granted Deutsche Bank a continuing security interest in and lien on certain membership interests or other interests in the Thermo No. 1 plant. We have also entered into a Guaranty Agreement in favor of the Thermo No. 1 plant and ML Holdings, pursuant to which we guaranteed certain obligations of certain parties to the Thermo Financing Agreements.
Under the Thermo Financing Agreement, the Thermo No. 1 plant was initially required to achieve “Final Completion” (as defined in the Thermo Financing Agreements) by June 30, 2008. After the Recovery Act was passed in February of 2009 it became apparent that the Thermo No. 1 plant would benefit from taking advantage of a U.S. Department of Treasury renewable energy grant under Section 1603 of the Recovery Act in lieu of tax credits offered under the Internal Revenue Code At the same time, we were working on increasing the output of the Thermo No. 1 plant and were not in a position to achieve Final Completion by the June 30, 2009 deadline. In December of 2009, we completed negotiations with the Thermo No. 1 financing partners, Prudential and Merrill Lynch, and entered into several amendments to the Thermo Financing Agreements (the “Restructuring Amendments”).
On December 4, 2009, pursuant to the Restructuring Amendments, the original Limited Liability Company Agreement was amended to enable the Thermo Subsidiary to apply for a grant (the “Grant”) under Section 1603 of the Recovery Act rather than take PTCs. The Grant is available to companies with qualified renewable energy projects. Qualified renewable energy projects may receive a cash grant in lieu of ITCs or PTCs.
As part of the Restructuring Amendments, the Thermo Subsidiary and Merrill Lynch entered into a Redemption Agreement pursuant to which Merrill Lynch withdrew from the Thermo Subsidiary. The redemption of Merrill Lynch’s interest was effective on December 11, 2009. According to a promissory note given by us to
Merrill Lynch (the “Thermo Note”), the amount to be paid to Merrill Lynch for the redemption (the “Redemption Amount”) is variable depending on a number of factors. As a result of receiving Grant proceeds of $33.0 million on February 19, 2010, the Redemption Amount has been adjusted to either $17.5 million or $20.0 million. If we reduce the amount of our outstanding 8.00% convertible notes (the “Convertible Notes”) by greater than 50% before June 30, 2010, the Redemption Amount will be $17.5 million. Otherwise the Redemption Amount will remain at $20.0 million, plus interest until paid.
The Thermo Note is subject to payment out of Grant proceeds under the order of priority for payments described above. We provided Merrill Lynch with both a Guaranty of the Thermo Note and a separate note (the “Raser Note”) to guaranty the payment in the event the escrowed funds are unavailable or insufficient to pay the Redemption Amount. If the Redemption Amount is not fully paid by the escrowed funds prior to June 30, 2010, Merrill Lynch will have no remaining claim against the Thermo Subsidiary for any shortfall but will look only to the Raser Note to pay the shortfall. The Raser Note may be secured by certain assets currently securing Prudential’s debt which are scheduled to be released from Prudential upon achieving Final Completion.
In February 2010, we amended the Restructuring Amendments to extend the date of Final Completion to June 30, 2010. Under the terms of the Restructuring Amendments, approximately $3.8 million was distributed to us. The remaining proceeds received from the Grant were placed into an escrow account and will be paid out in the following order on or about June 30, 2010: (i) first Prudential will potentially receive a pre-payment, together with a pre-payment penalty, of its outstanding debt, depending on the performance of the Thermo No. 1 plant at the time; (ii) project escrow accounts will be funded as required by the Thermo Financing Agreements; (iii) Merrill Lynch will receive its Redemption Amount (as described above); (iv) Pratt & Whitney Power Systems will receive any amounts left owing to it as the turbine supplier for the Thermo No. 1 plant; and (v) any remaining amounts will be placed in the revenue escrow account and will ultimately flow through as a distribution to us.
Prior to the redemption of Merrill Lynch’s equity interest in the Thermo Subsidiary, we had evaluated Merrill Lynch’s voting, participation, and protective rights in the Thermo Subsidiary along with variable interest entity accounting guidance and determined that the Thermo Subsidiary financing arrangement should not be classified as a variable interest entity and that the Thermo Subsidiary was properly consolidated for financial statement purposes. As of December 31, 2009, based upon the redemption of Merrill Lynch’s equity interest in the Thermo Subsidiary, we once again evaluated the variable interest entity accounting guidance. We determined that Merrill Lynch has no continuing rights with respect to the Thermo Subsidiary and only maintains the right to the distribution of a portion of the $33.0 million of federal grant funds as discussed above. Based upon our analysis, we determined that the Thermo Subsidiary should not be classified as variable interest entity under the new financing arrangements for the Thermo Subsidiary and that the Thermo Subsidiary should continue to be consolidated for financial statement purposes. In determining whether the Thermo Subsidiary should be classified as a variable interest entity, we had to make certain judgments and assumptions. If these judgments and assumptions prove to be incorrect, it could result in the deconsolidation of our Thermo Subsidiary and have a material impact on our results of operations and financial position.
The Symetron™ Family of Technologies
Our Symetron™ technologies consist of electromagnetic machine and power electric logic and topology innovations developed for electric motors, generators and their associated drives and controllers. These innovations can increase torque, power and efficiency of such machines and drive systems. These efficiency and power torque density improvements can increase a motor’s continuous power rating as well as decrease its power consumption during periods of high torque output using conventional materials and manufacturing processes.
We believe that our motor and drive technologies are scalable and can apply to radial, axial and pancake shaped motors. These concepts have also been applied to alternators and generators with observed increases in efficiency and power density.
Raser Series Demonstration PHEV
We have entered into a collaborative arrangement with FEV Inc., a large automotive parts and vehicle integration supplier, and General Motors to integrate our SymetronTM technologies into a Hummer Demonstration Vehicle with the objective to perform an all-electric, emissions-free driving range of 40 miles and an average driving fuel economy of 100 miles per gallon for the average American driver. This Hummer Demonstration Vehicle uses an enhanced motor, generator and power electronic drive controller for its electric powertrain. We have incorporated a newly-developed plug-in hybrid master controller with integrated software to control the vehicle’s propulsion generation, transmission, power management, motion control and other electrical subsystems. We unveiled the Hummer Demonstration Vehicle at the 2009 SAE International World Congress in Detroit, Michigan. The recent economic challenges that have dramatically impacted the automotive industry may further delay or eliminate the resources available to complete this project. We intend to continue to work closely with FEV and General Motors in an effort to complete the project in 2010.
Motor and Drive Technology
An induction motor drive/controller controls the performance of an AC induction motor, including its speed, torque and direction of rotation. In an integrated starter alternator (“ISA”), the controller also serves to control the flow of regenerated electric power back from the ISA to the batteries and to regulate the voltage output of the ISA when in generation mode. We believe our technologies can be used to increase the operating efficiency of both the driven motor and the drive’s power converter, optimizing the utilization of its power devices.
During 2006, under a STAC grant administered by the United States Department of Energy, we developed a flexible modular power electronic motor controller based upon efficiency optimized motor control technology (FlexMod™) for variable-torque HVAC applications. Independent testing conducted by the testing firm Advanced Energy demonstrated an improvement of up to 10% when compared to leading variable drive systems. We continue to explore opportunities to license our technologies to manufacturers of HVAC AC drives and equipment.
Integrated Starter Alternators
An ISA serves the combined function of the starter motor and the alternator or generator in an automobile. We intend to explore opportunities to license our technologies relating to ISAs for use in PHEV, electric, hybrid electric and fuel-cell powered automobiles, as well as certain other applications. The target applications for our AC induction and permanent-magnet motor designs include mild hybrid traction drives such as are used in mild hybrid belt-starter applications and integrated in-line transmission assemblies. In the last half of 2006 we were awarded a contract with ARINC, to complete follow-on tasks to our prior development work with the United States Army to develop an ISA for a military HMMWV hybrid vehicle. During 2007, we successfully completed the first three payment milestones of this follow-on task with ARINC. In the first half of 2008, we completed this phase of the project and demonstrated two working ISA prototypes for use in prototype vehicles for the United States Army. We continue to look for opportunities to commercialize our ISA-related technologies, but it is not a focus of our commercialization efforts at this time.
Alternators/Intelligent Voltage Regulators (“IVR”)
Alternators: We have licensed our Symetron™ technologies for use in brushless claw-pole alternators for automobiles, trucks, buses and other vehicles. A third party has successfully completed durability testing in the field and the laboratory. However, we have been unable to generate revenues from our IVR technology. We continue to seek other customers that may be able to help commercialize our IVR technology.
Efficiency Optimized Line-Driven AC Motor Technology (“EO”)
High-Efficiency AC Induction Motors: In cooperation with Hyundai Heavy Industries (“HHI”) one of the world’s largest manufacturing companies, we have sought to develop an enhanced line-driven AC induction
generator and an AC induction motor for HVAC chiller applications. We anticipate these generators and motors will demonstrate that our technologies can increase the efficiency of line-driven AC induction motors and generators without increasing manufacturing costs. If tests of these units are successful, we intend to explore opportunities to license our technologies to other manufacturers of high efficiency AC induction motors and generators.
In January 2008, we signed a business cooperation agreement with HHI under which HHI will manufacture and sell Symetron-enhanced AC motors, generators and drives for use in geothermal energy generation plant, HVAC and refrigeration equipment, and other industrial applications.
Patents and Other Intellectual Property Rights
Our Power Systems segment utilizes certain patented heat transfer technologies and proprietary plant designs in our geothermal power plant projects, including a binary cycle technology. Our Thermo No. 1 plant uses PureCycle geothermal power generating units. The PureCycle units utilize a proprietary binary cycle technology developed by PWPS.
We also have a license to use Kalina-cycle heat transfer technologies from a third party licensor. Five United States patents have been issued to the licensor, and one is pending, with respect to these technologies. We may use these technologies primarily within the United States, and we believe the patents are sufficient to protect the proprietary nature of the technologies covered by our license. Our Power Systems segment also intends to explore ways to incorporate our Symetron™ technologies into the motors, generators and drives used in the geothermal power plants we intend to develop. We believe these technologies can be applied in a number of ways to make geothermal power plants more efficient. Our Symetron™ technologies are further described above.
Our Transportation & Industrial segment has developed intellectual property that focuses on innovations we developed for electric motors and their associated drives and controllers. The electromagnetic machine and power electronic drive technology is trademarked under the names “Symetron™” and “Raser™.”
The United States Patent and Trademark Office has issued seven patents to us, including two for resonant motors (U.S. Patent No’s. 6,847,186 and 7,034,498); one for resonant unipolor generators (U.S. Patent No. 7,459,823); one for electromagnetic motors (U.S. Patent No. 7,034,499); one for motor controllers (U.S. Patent No. 7,026,785); one for pancake motors (U.S. Patent No. 7,116,029); and one for hydrodynamic slip rings (U.S. Patent No. 7,019,431). We have filed additional patent applications and expect to continue to file new patent applications as we continue to refine our PHEV project.
We regularly review our patented technologies, the patent applications we have filed and the patent applications we have been preparing to file in order to assess the commercial viability of each patent or application. Based upon the results of this assessment, we may shift commercialization efforts away from some of our patented technologies and focus efforts on commercialization of others.
We rely on a combination of laws and contractual restrictions with employees, customers, suppliers, affiliates and others to establish and protect proprietary rights. Applications for patent protection for key technologies are made on a global basis. We require technical personnel to sign confidentiality agreements that contractually obligate them to assign new intellectual property to us. Legal expertise has been engaged to help process applications to protect our intellectual property. Despite these precautions, it may be possible for a third party to copy or otherwise obtain and use our intellectual property without authorization. In addition, others may independently develop substantially similar intellectual property.
Research and Development
Our Transportation & Industrial segment has sought to develop and demonstrate new applications for our motor and drive/controller-related technologies as well as our new extended range PHEV-based product and
solution technologies. We have made periodic introductions of new motor and generator-related technologies, application of technologies to manufacturers’ test applications, testing and performance evaluations of these technologies and participation in the design and engineering of related projects for original equipment manufacturers (“OEMs”).
We have devoted considerable effort to further develop various technologies and to internally test, refine, characterize and further verify the technologies. Characterization of the technology is the process by which the performance levels that can be achieved over a range of likely operating conditions are determined. This data provides a performance description that is useful to the customer in understanding the capabilities of the motor without revealing the intellectual property underlying the improved performance levels.
Our research and development costs for the years ended December 31, 2009, 2008 and 2007 totaled $1,855,858, $4,762,733 and $3,390,688, respectively. Due to the current economic weakness in the automotive industry and impact on other manufacturers, we have reduced our resources committed to further research and develop new solutions based on our technologies. We believe future research and development expenditures are required in order to develop additional extended range technologies primarily relating to plug-in hybrid electric vehicles and electric and electric-hybrid propulsion systems, ISAs, AC electric motors, generators and power electronic AC drives. However, for the foreseeable future, particularly until economic conditions improve, we intend to focus our efforts on commercializing already licensed technologies and technologies developed by our manufacturing partners.
Suppliers and Key Relationships
We entered into purchase agreements with affiliates of United Technologies, Inc. These agreements provided for the delivery of PureCycle® units for the Thermo No. 1 plant. Subject to our obtaining financing and payment of the purchase price, these agreements also provide for the delivery of PureCycle® modular units for the other plants we intend to build. The PureCycle units enables us to construct power plants utilizing heat from geothermal resources with cooler to lower temperatures than conventional equipment at a fraction of the time otherwise required. Our agreements with PWPS contemplate a long-term relationship in developing geothermal resources as well as potential exchanges of technology.
We believe that other equipment suppliers may be able to provide generation units which meet our standards and fit into our rapid deployment strategy. In an effort to reduce our dependence on any one turbine supplier, we have been in discussions with alternate suppliers and may, in the future, purchase generation units from other suppliers in addition to PWPS.
In the second quarter of 2007, we also signed a Geothermal Project Alliance Agreement and a Consulting Services Agreement with Cummins & Barnard, Inc. (“C&B”), a full service engineering consulting company. Under these agreements, C&B will provide program management and construction services for the development of our first three geothermal power plants. In January 2008, HDR, a leading architecture, engineering and consulting firm, acquired C& B and changed its name to HDR- Cummins & Barnard (“HDR-C&B”). New HDR-C&B management has indicated that they remain committed to the original agreement and continue to provide the program management and construction services for the development of our first three geothermal power plants. Except for the three plants covered by the agreements with HDR-C&B, we do not currently have any agreements in place for the program management and construction services relating to any of the other projects we intend to develop.
Drilling operations are necessary to develop the well field for each geothermal power project we develop. We utilize various suppliers to obtain the appropriate permits, rent drilling equipment, perform drilling services, provide casing and other tangible assets for the well and provide well testing services. Should one supplier fail to meet our purchasing requirements, we are confident that other suppliers could be identified and the appropriate items procured and obtained without significant delays. Patterson-UTI Energy, Inc., a publicly-traded drilling company, has performed the majority of our drilling services to date.
Competition
Our Power Systems segment primarily competes in the power generation industry. Competition in the power generation industry is characterized by intense competition from not only large power plants burning fossil fuels, but from other companies trying to develop clean, renewable energy from sources such as geothermal, solar, wind, ethanol, hydro-electric and other sources of clean energy. In the last year, competition from the wind and solar power generation industry has increased. While we anticipate that the current demand for renewable energy is large enough that this increased competition will not significantly impact our ability to obtain new power purchase agreements, this increased competition could contribute to a reduction in electricity prices for new renewable projects. We believe this risk is substantially mitigated by the fact the geothermal power represents a base load source of renewable energy.
In general the primary competitive factors for the geothermal market are the ability to obtain properties with the appropriate heat sources, technologies and equipment, geographic locations of power plants, access to prime market and transmission infrastructures, and favorable regulatory and tax environments for renewable energy. In the geothermal power generation sector, our main competitors in the United States are Ormat Technologies, Calpine, CalEnergy Generation, Terra-Gen Power and other smaller-sized developers such as U.S. Geothermal, Nevada Geothermal, RAM, Magma Renewables, Agua Caliente, and Vulcan Power.
Our Transportation & Industrial segment competes primarily with other developers of electric powertrains, PHEV technologies, and with other developers of technologies designed to improve the efficiency of electric motors, generators and related systems. As the market for electric and hybrid electric vehicle propulsion systems, high performance motors, generators, drives and controllers grows, we believe that the number of competitors will increase. We also expect that manufacturers of electric vehicles and Hybrid electric vehicles, electric motors, generators, drives and controllers, including many of our potential customers, will seek to develop their own technologies that would compete with our technologies. In general, the competitive factors for electric motor, generator, drive and related technologies are efficiency, power and torque density, peak torque, costs of production, reliability and expected warranty costs. We believe that our PHEV strategy of targeting light trucks and SUVs for our technology has put us in a favorable position as compared to our competitors. We believe that our technology is in a more advanced state as evidenced by our Hummer Demonstration Vehicle.
Some of our existing and potential competitors have greater brand recognition, longer operating histories, larger customer bases and significantly greater financial, marketing and other resources than we do. Smaller competitors may also achieve competitive advantages by entering into strategic or commercial relationships with larger, more established and well-financed companies. Many of our competitors could devote greater resources to plant development, marketing and research and development efforts than we can. New technologies and the continued enhancement of existing technologies also may increase competitive pressures in the future.
Government Regulation
Power Systems
The following is a summary overview of the electric utility industry and applicable federal and state regulations, and should not be considered a full statement of the law or all issues pertaining thereto.
We are subject to both federal and state regulation with respect to the production, sale and distribution of electricity. Federal legislation includes the Federal Power Act (“FPA”), as well as the Public Utility Regulatory Policies Act of 1978 (“PURPA”) and the Energy Policy Act of 2005 (“EPACT 2005 “), which among other things repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Our current electric generation projects are planned to be developed as qualifying facilities (“Qualifying Facilities”) under regulations of the Federal Energy Regulatory Commission (“FERC”) adopted pursuant to PURPA. This legislative act encourages the development of alternative energy sources such as geothermal, wind, biomass, solar and cogeneration.
PUHCA
Although EPACT 2005 repealed the Public Utility Holding Company Act of 1935, PUCHA 2005 granted state regulators and the FERC broad access to books and records of non-exempt project companies. PUCHA 2005 also provided for FERC review of the allocation of costs for non-power goods or services between regulated and unregulated affiliates of such companies. Geothermal project companies can obtain an exemption from these requirements by obtaining status as a Qualifying Facility under PURPA.
PURPA
As described below, PURPA provides certain benefits if a project is a Qualifying Facility. There are two types of Qualifying Facilities: cogeneration facilities and small power production facilities. A small power production facility is a Qualifying Facility if (i) the facility does not exceed 80 MW, (ii) the primary energy source of the facility is biomass, waste, renewable resources, or any combination thereof, and at least 75% of the total energy input of the facility is from these sources; and (iii) the facility has filed with FERC a notice of self-certification of qualifying status, or has filed with FERC an application for FERC certification of qualifying status, that has been granted.
PURPA exempts Qualifying Facilities from most provisions of the FPA and state laws relating to the financial, organization and rate regulation of electric utilities. In addition, FERC’s regulations promulgated under PURPA require that electric utilities purchase electricity generated by Qualifying Facilities at a rate based on the purchasing utility’s incremental cost of purchasing or producing energy (also known as “avoided cost”).
Pursuant to EPACT 2005, FERC issued a final rule that subjects Qualifying Facilities to FERC rate regulation for sales of energy or capacity unless such sales are either (i) from Qualifying Facilities 20 MW or smaller in size; (ii) pursuant to a contract executed on or before March 17, 2006; or (iii) pursuant to a state regulatory authority’s implementation of section 210 of PURPA. The practical effect of this final rule is to require Qualifying Facilities that are larger than 20 MW in size to obtain market-based rate authority from FERC for non-PURPA sales of power (i.e. power that is sold in a manner that is not pursuant to state implementation of PURPA).
EPACT 2005 also allows FERC to terminate a utility’s PURPA obligation to purchase energy from a Qualifying Facility upon a finding that the Qualifying Facility has nondiscriminatory access to either (i) independently administered, auction-based day ahead and real time wholesale markets for electric energy and wholesale markets for long-term sales of capacity and electric energy (“Day 2” wholesale markets); (ii) transmission and interconnection services provided by a FERC-approved regional transmission entity and administered under an open-access transmission tariff that affords nondiscriminatory treatment to all customers, and competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy, including long and short term sales to buyers other that the utility to which the Qualifying Facility is interconnected; or (iii) wholesale markets for the sale of capacity and energy that are at a minimum of comparable competitive quality as markets described in (i) and (ii) above. FERC adopted a rule to implement these provisions of the EPACT 2005. The rule creates a rebuttable presumption that for Qualifying Facilities larger than 20 MW, if the utility is a member of any of four regional transmission organizations or independent system operators with Day 2 wholesale markets (Midwest ISO, PJM, ISO-NE, NYISO), the Qualifying Facility does have nondiscriminatory access to the relevant wholesale market. A utility in those areas thus will be eligible for relief from the mandatory obligation. While the rule creates a rebuttable presumption regarding nondiscriminatory transmission access to all markets where there is a filed open access transmission tariff (or reciprocity tariff of a non-jurisdictional utility), the order did not find that any markets (other than the four listed RTO/ISOs and ERCOT, under separate exemptions)provide a meaningful opportunity to sell capacity and energy, including long and short-term sales to buyers other than the utility to which the Qualifying Facility is interconnected. Further, the rule provides a procedure for utilities to file to obtain relief from the mandatory purchase obligation on an individual service territory-wide, or regional basis, and establishes procedures for affected Qualifying Facilities to seek reinstatement of the purchase obligation. The rule creates a rebuttable presumption that a Qualifying Facility with
a net capacity no greater than 20 MW does not have nondiscriminatory access to any wholesale market, and the mandatory purchase obligation remains. The rule also protects a Qualifying Facility’s rights under any contract or obligation for the sale of energy in effect or pending approval before the appropriate state regulatory authority or non-regulated electric utility on or before August 8, 2005.
Prior to EPACT 2005, electric utilities or electric utility holding companies could not own more than a 50% equity interest in a Qualifying Facility. EPACT 2005 eliminates the restriction on utility ownership of a Qualifying Facility.
We expect that all of the projects we intend to develop will meet the criteria required for Qualifying Facilities under PURPA. However, it is possible that the utilities that purchase power from the projects could successfully obtain an elimination of the mandatory-purchase obligation in their service territories.
FPA
Pursuant to the FPA, the FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities have certain exemptions from the FPA that vary depending on their size. If any of the projects were to lose its Qualifying Facility status, such project could also become subject to the full scope of the FPA and applicable state regulations. The application of the FPA and other applicable state regulations to the projects could require operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce operational flexibility. Even if a project does not lose Qualifying Facility status, pursuant to a final rule issued by FERC pursuant to EPACT 2005, the project will become subject to rate regulation under the FPA unless it is 20 MW or smaller, or has a sales contract executed on or before March 17, 2006 or made pursuant to a state regulatory authority’s implementation of section 210 of PURPA.
If a project that is exempt from rate regulation was to become subject to FERC’s ratemaking jurisdiction under the FPA as a result of loss of Qualifying Facility status and the power purchase agreement remains in effect, the FERC may determine that the rates currently set forth in the power purchase agreement are not appropriate and may set rates that are lower than the rates currently charged. In addition, the FERC may require that the project refund certain amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in future revenues or in an obligation to disgorge profits previously received from the project, plus interest either of which would have an adverse effect on revenues.
State Regulations
Qualifying Facilities that make only wholesale sales of electricity are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. Our projects will likely sell their electrical output under power purchase agreements to electric utilities. We expect the power purchase agreements with those utilities (except certain utilities such as municipalities that are not regulated by state utility commissions) will be submitted by the utilities for approval by their respective state public utility commissions.
While geothermal power generation operations produce electricity without emissions of certain pollutants such as nitrogen oxide, and with far lower emissions of other pollutants such as carbon dioxide than conventional fossil fuel fired power generation operations, some geothermal projects may emit air pollutants in quantities that are subject to regulation under applicable environmental air pollution laws. Such operations typically require air permits. Especially critical to geothermal operations are those permits and standards applicable to the construction and operation of geothermal wells and brine reinjection wells. In the United States, injection wells are regulated under the federal Safe Drinking Water Act Underground Injection Control program, which we refer to as UIC. Geothermal reinjection wells typically fall into UIC Class V, one of the least regulated categories, because fluids are reinjected to enhance utilization of the geothermal resource. Geothermal plants are required to
comply with numerous federal, regional, state and local statutory and regulatory environmental standards and to maintain numerous environmental permits and governmental approvals required for their operation.
Transportation & Industrial
While the activities of our Transportation & Industrial segment are not subject to direct regulation, the commercialization of our technologies for certain applications, such as hybrid-electric vehicles, may be somewhat dependent on government regulations. EPACT 2005 contains numerous provisions that could affect the pace at which hybrid-electric technology is adopted by the automobile industry. For example, EPACT 2005 continued to provide tax incentives for purchasers of hybrid-electric vehicles and provided direct funding for research to advance the commercialization of hybrid and plug-in flexible fuel vehicles. EPACT 2005 also extended incentives for alternate fuel vehicles that could be considered competitors to hybrid-electric vehicles. Similarly, government initiatives such as the FreedomCAR and Fuel Partnership and the 21st Century Truck Partnership could play a significant role in accelerating the adoption of applicable technologies in the automotive and other related transportation industries. The United States Department of Energy (“DOE”) is directed by the Energy Policy and Conservation Act to consider establishing minimum efficiency standards for various consumer products, including central air conditioners and central air conditioning heat pumps. In 2004, DOE amended the minimum efficiency standards for new central air conditioners and heat pumps. The new standards went into effect on January 23, 2006, raising the Seasonal Energy Efficiency Ratio for residential air conditioners to 13 and increasing the Heating Seasonal Performance Factor for central air conditioning heat pumps to 7.7. Likewise, under EPACT 2005 in the U.S and various directives in the EU, standard general-purpose AC induction motors are subject to minimum operating efficiency standards. In general, higher efficiency standards for air conditioners, heat pumps and AC motors, which are currently under review at the relevant regulating agencies, could make certain applications of our technologies more attractive to manufacturers of those systems.
Employees
As of December 31, 2009, we had 42 full-time employees, including four dedicated to the Transportation & Industrial segment, eighteen dedicated to the Power Systems segment, and twenty in the sales, marketing and administrative departments. Currently, there are no employees under a collective bargaining agreement. We consider our employee relationships to be positive.
Executive Officers of the Registrant
The following table sets forth the name, position and age of each of our executive officers.
Name
Position
Age
Kraig T. Higginson
Chairman of the Board
Nicholas Goodman (a)
Chief Executive Officer
John T. Perry (b)
Chief Financial Officer
Richard D. Clayton
Principal Financial Officer, Executive Vice-President, General Counsel and Secretary
Steven R. Brown
Executive Vice-President
(a) Mr. Goodman began employment as Chief Executive Officer on January 25, 2010.
(b) Mr. Perry began employment on March 10, 2010. His duties as Chief Financial Officer will start on March 22, 2010. Mr. Perry will succeed Martin F. Petersen who resigned effective January 15, 2010. Since Mr. Perry will not have assumed his duties as Chief Financial Officer prior to when our December 31, 2009 Annual Report on Form 10-K is issued, Mr. Clayton will certify the December 31, 2009 Form 10-K as the Principal Financial Officer.
Kraig T. Higginson. Mr. Higginson has served as Chairman of the Board of Directors since October 2003. He has also served as the Company’s President from October 2003 to March 2004 and as the Company’s Chief
Executive Officer from March 2004 to January 2005. Mr. Higginson founded American Telemedia Network, Inc., a publicly-traded corporation that developed a nationwide satellite network of data and audio-visual programming. He served as President and Chief Executive Officer of Telemedia Network from 1984 through 1988. From 1988 through 2002, Mr. Higginson worked as a business consultant through Lighthouse Associates, an entity he controls.
Nicholas Goodman. Mr. Goodman began serving as Chief Executive Officer on January 25, 2010. Mr. Goodman has extensive experience growing power companies through project development and acquisition. From 2003 to 2010, he served as Chief Executive Officer of TDX Power, Inc. an electric utility holding company and power generation project developer. Under his leadership, TDX Power, Inc. has grown from $3 million to over $60 million in annual recurring revenues. At three different wholly owned projects of TDX Power, Inc., Mr. Goodman managed the initial development and conceptual design, as well as Federal licensing and permitting for Alaska’s largest hydroelectric power project (330 MW), Alaska’s second geothermal project and several of Alaska’s largest wind diesel power projects. Mr. Goodman was also responsible for securing project finance through a combination of public and private funding sources. In addition, he led the development of power plants for two military installations in Alaska as well as other sites in the U.S. and abroad. In 1999, Mr. Goodman founded Northern Renewables, a consulting and development firm dedicated to assisting renewable energy technology companies in Alaska and other areas in the United States. Mr. Goodman served as its Managing Director until 2003. From 1998 to 1999, he served as General Manager for Tidal Electric, a marine hydropower development company. Mr. Goodman holds a Bachelor of Arts Degree in Geography from Middlebury College, and a Masters of Science Degree in Natural Resource Development and Business Administration from the University of Vermont.
John T. Perry. Mr. Perry began employment on March 10, 2010. His duties as Chief Financial Officer will begin on March 22, 2010. Mr. Perry served as President and Chief Executive Officer of Nord Resources Corporation, a copper mining company with total assets in excess of $50 million, from 2007 until 2010. From 2005 until 2007, Mr. Perry served as Chief Financial Officer, Senior Vice President, Secretary and Treasurer. Mr. Perry was Vice President, Director with CB Richard Ellis, International Mining and Metals Group from 2003 to 2005. Prior to that, he held various positions with BHP Billiton Base Metals and BHP Copper Inc., including Vice President Finance with BHP Billiton Base Metals from 2002 to 2003, President, BHP Copper, Inc. from 1999 to 2002, and Vice President Finance and Administration for BHP Copper, Inc. He is a Certified Public Accountant and holds an undergraduate degree in Accounting and Finance as well as an MBA from the University of Arizona. He is also a director of Homeland Uranium Incorporated and Geovic Mining Company.
Richard D. Clayton. Mr. Clayton has served as Executive Vice President, General Counsel and Secretary since March 2007. From August 2009 until January 2010, Mr. Clayton also served as Interim Principal Executive Officer during the interim time necessary to successfully complete our search for our Chief Executive Officer and then as Interim Principal Financial Officer until March 22, 2010. From 2001 to 2007, Mr. Clayton practiced corporate law with Holland & Hart, LLP, specializing in mergers and acquisitions, corporate finance, and corporate governance. He also served as a member of the board of directors and executive vice president of Geneva Steel Company (NYSE listed), where his responsibilities included corporate finance, capital projects, energy and environmental matters. Mr. Clayton received BS degrees in accounting and finance from the University of Utah, and a JD degree from the University of Utah.
Steven R Brown. Mr. Brown joined Raser in January 2007 and has an extensive background in the start-up of technology based companies and project management of complicated and diverse projects. From June 2000 until he joined Raser, he was the owner operator of Construction Management Services, Inc. where he provided consulting services to government agencies, private owners, banks, law firms, and contractors throughout the United States. These services included engineering, construction management, on-site owner representation, cost estimating, scheduling, and construction claim litigation preparation and expert witness testimony. Mr. Brown also served as Senior Vice President at Headwaters, Inc. and was responsible for the development, construction and operations of twenty-four synthetic fuel facilities from 1995 to 2000. The facilities were constructed over a
two year period with an investment of $310 million and will generate $2.5 billion of Section 29 tax credits over the ten year period of their operations. Mr. Brown also served on Headwaters’ board of directors and assisted in the formulation and implementation of Headwaters’ technology licensing strategy. Mr. Brown has also been involved with new business development, operations, financial analysis, and business plan development in the telecommunications, mining, engineering and constructions industries. Mr. Brown received his Bachelor of Science in Civil Engineering and Masters of Business Administration from Brigham Young University.
Available Information
Our internet address is www.rasertech.com. We make available free of charge on or through our website our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). The public may also read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a web site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The content on any web site referred to in this Form 10-K is not incorporated by reference into this Form 10-K unless expressly noted.
ITEM 1A.
ITEM 1A. Risk Factors.
The following risk factors, among others, could cause our financial performance to differ significantly from the goals, plans, objectives, intentions, beliefs, and expectations expressed in this report. If any of the following risks and uncertainties or other risks and uncertainties not currently known to us or not currently considered to be material actually occur, our business, financial condition or operating results could be harmed substantially.
We will need to secure additional financing and if we are unable to secure adequate funds on terms acceptable to us, we will be unable to support our business requirements, build our business or continue as a going concern.
At December 31, 2009, we had approximately $42,000 in cash and cash equivalents and $11.3 million in restricted cash and marketable securities. As such, our cash balances are not sufficient to satisfy our anticipated cash requirements for normal operations and capital expenditures for the foreseeable future. Our operating activities used approximately $23.5 million of cash for the year ended December 31, 2009 and approximately $22.9 million of cash during the year ended December 31, 2008. We have incurred substantial losses since inception and we are not operating at cash breakeven. Obligations that may exert further pressure on our liquidity situation include the obligation to repay remaining amounts borrowed under our Line of Credit, which are due in July 2010, unless the remaining Line of Credit lender exercises his option to require repayment at any time starting up to the maturity date.
From time to time, we have raised additional capital through the sale of equity and equity-related securities. Most recently, on February 3, 2010, we completed the sale of $5.0 million convertible of Series A-1 Cumulative Convertible Preferred Stock (the “Preferred Stock”) to Fletcher International, Ltd. (“Fletcher”), an affiliate of Fletcher Asset Management, Inc. Our proceeds from the sale of the convertible preferred stock were approximately $4.7 million, after deducting underwriters’ fees, legal fees and expenses.
Our continuation as a going concern is dependent on efforts to secure additional funding, increase revenues, reduce expenses, and ultimately achieve profitable operations. The current economic environment will make it challenging for us to access the funds that we need, on terms acceptable to us, to successfully pursue our development plans and operations. The cost of raising capital in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. If we are
unable to raise sufficient, additional capital on reasonable terms, we may be unable to satisfy our existing obligations, or to execute our plans. In such case, we would be required to curtail or cease operations, liquidate or sell assets, modify our current plans for plant construction, well field development or other development activities, or pursue other actions that would adversely affect future operations. Further, reduction of expenditures could have a negative impact on our business. A reduction of expenditures would make it more difficult for us to execute our plans to develop geothermal power plants in accordance with our expectations. It would also make it more difficult for us to conduct adequate research and development and other activities necessary to commercialize our Symetron™ technologies.
In order to execute our business strategy and continue our business operations, we will need to secure additional funding from other sources through the issuance of debt, preferred stock, equity or a combination of these instruments. We may also seek to obtain financing through a joint venture, the sale of one or more of our projects or interests therein, entry into pre-paid power purchase agreements with utilities or municipalities, a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. We cannot be certain that funding that we seek from any of these sources will be available on reasonable terms or at all.
If we raise additional capital through the issuance of equity or securities convertible into equity, our stockholders may experience dilution. Any new securities we issue may have rights, preferences or privileges senior to those of the holders of our common stock, such as dividend rights or anti-dilution protections. We have previously issued warrants to acquire our common stock in connection with certain transactions. Some of these warrants continue to be outstanding and contain anti-dilution provisions. Pursuant to these anti-dilution provisions, the exercise price of the applicable warrants will be adjusted if we issue equity securities or securities convertible into equity securities at a price lower than the exercise price of the applicable warrants.
We may also seek to secure additional financing by incurring indebtedness. However, as a result of concerns about the stability of financial markets generally, and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. In addition, any indebtedness we incur could constrict our liquidity, result in substantial cash outflows, and adversely affect our financial health and ability to obtain financing in the future. Any such debt would likely contain restrictive covenants that may impair our ability to obtain future additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes, and a substantial portion of cash flows, if any, from our operations may be dedicated to interest payments and debt repayment, thereby reducing the funds available to us for other purposes. Any failure by us to satisfy our obligations with respect to these potential debt obligations would likely constitute a default under such credit facilities.
Financing needed to develop geothermal power projects may be unavailable.
A substantial capital investment will be necessary to develop each geothermal power project our Power Systems segment seeks to develop. Our continued access to capital through project financing or other arrangements is necessary for us to complete the geothermal power projects we plan to develop. We have had difficulty raising the capital we need in the current economic environment, and our future attempts to secure capital on acceptable terms may not be successful.
Market conditions and other factors may not permit us to obtain financing for geothermal projects on terms favorable to us. Our ability to arrange for financing on a substantially non-recourse or limited recourse basis, and the costs of such financing, are dependent on numerous factors, including general economic and capital market conditions, credit availability from banks, investor confidence, the success of our projects, the credit quality of the projects being financed, the political situation in the state in which the project is located and the continued existence of tax and securities laws which are conducive to raising capital. If we are not able to obtain financing
for our projects on a substantially non-recourse or limited recourse basis, or if we are unable to secure capital through partnership or other arrangements, we may have to finance the projects using recourse capital such as direct equity investments, which would have a dilutive effect on our common stock. Also, in the absence of favorable financing or other capital options, we may decide not to pursue certain projects. Any of these alternatives could have a material adverse effect on our growth prospects and financial condition.
In addition, the tax benefits originating from geothermal power projects are anticipated to provide a significant portion of the funding of the geothermal projects. This tax equity has traditionally been driven by the tax liability of the major financial industry companies. Many of these companies are currently experiencing significantly reduced income or incurring substantial losses. As a result, they are seeking fewer tax-advantaged investments and this may reduce the amount of readily available tax credit equity available for our geothermal projects or reduce the amount of tax equity that can be obtained as these investors seek higher rates of return for the tax equity they invest.
The United States Congress recently passed the Recovery Act that was subsequently signed into law by President Obama. The Recovery Act provides certain economic incentives, such as clean energy grants, that are designed to provide developers of geothermal and other clean energy projects with cash to help fund the projects. These incentives are designed, in part, to address some of the current problems in the tax equity markets and provide an alternative funding mechanism. Accordingly, part of our short-term strategy to obtain additional funding includes applications for loan guarantees and government grants.
In February of 2010, we received a grant from the U.S. Treasury under the Recovery Act totaling $33.0 million. Approximately $3.8 million will be used by us. The remaining proceeds received from the Grant will be placed into an escrow account and paid out in the following order on or about June 30, 2010; (i) first Prudential will potentially receive a pre-payment, together with a pre-payment penalty, of its outstanding debt, depending on the performance of the Project at the time; (ii) the project escrow accounts will be funded as required by the Thermo Financing Agreements; (iii) Merrill Lynch will receive its Redemption Amount (either $17.5 million or $20.0 million, subject to certain conditions); (iv) Pratt & Whitney Power Systems will receive any amounts left owing to it as the turbine supplier for the Project; and (v) any remaining amounts will be placed in a revenue escrow account and will ultimately flow through as a distribution to us.
One of our applications for loan guarantees was denied and we were not awarded small grants for three projects that we applied for in connection with certain exploration activities. We cannot predict whether we will be able to successfully obtain additional grants or loan guarantees under these new government programs.
Although we are seeking loan guarantees and grants from the government, we will still need to obtain financing from other sources for the development of our projects. Many of our projects will require funding for early-stage development activities, such as drilling, as well as more traditional project financing for the construction of the power plant.
We recently terminated our Commitment Letter with Merrill Lynch to finance up to 155 MW of future projects. The Commitment Letter was terminated as part of an overall restructuring of the project finance and tax equity agreements for the Thermo No. 1 plant. We are currently seeking other financing arrangements to fund the development of additional projects.
Early-stage development activities, such as drilling at potential project sites, preliminary engineering, permitting, legal fees and other expenses can be difficult to finance. Project financing is not typically available for these preliminary activities. As a result, we have generally had to fund these activities out of funds available for general corporate purposes. On December 7, 2009, we entered into the Co-Development Agreement with Evergreen, which could provide an alternative source of funding for drilling or other early-stage development activities at certain projects. Evergreen’s funding obligations with respect to each site selected for development are subject to the satisfaction of a number of conditions, including satisfactory due diligence, the completion of
certain milestones, the granting of a security interest, and the negotiation of definitive agreements relating to the financing of each project. Under the terms of the Co-Development Agreement, Evergreen would receive warrants to purchase shares of our common stock in connection with the funding of each project selected for development. The total amount of warrants to be issued will be dependent upon the amount of funding provided.
Evergreen is a newly formed clean-energy fund in the process of raising capital for its first investments in renewable energy projects. Evergreen has informed us that it is in discussions with institutional investors interested in making capital commitments to Evergreen. In connection with these discussions, we have provided diligence materials to Evergreen and Evergreen’s potential investors relating to our Thermo and Lightning Dock projects. The ability of Evergreen to perform its obligations and provide funding for one or more of our projects under the Co-Development Agreement is dependent upon Evergreen’s ability to obtain sufficient capital commitments from investors. Evergreen’s efforts to raise the funds it is seeking are beyond our control, and we cannot predict whether Evergreen will be able to successfully raise sufficient capital to fund one or more of our projects.
The terms of our outstanding preferred stock and certain other rights we have granted security holders may make it more difficult for us to sell additional securities.
Certain terms and conditions included in securities that we have sold, or rights granted to purchasers of securities we have sold, may make it more difficult for us to negotiate and complete sales of our securities in the future. The terms of our outstanding securities could also require us to issue additional shares to purchasers of securities we have sold, or adjust the price of outstanding warrants to purchase our common stock.
The terms of our outstanding Preferred Stock provide that each share of Preferred Stock is entitled to a quarterly dividend, payable in cash or shares of our common stock at an annual rate equal to the 3-month London Interbank Rate (“LIBOR”) plus 8%, but in no event higher than 14%. The terms of the Preferred Stock restrict our ability to pay dividends to our common stockholders unless we are current in our dividend obligations to the Preferred Stock and any dividend payment to our common stockholders is made equally to the holders of the Preferred Stock as if such holders had converted or redeemed their Preferred Stock for shares of our common stock. In addition, the holders of the Preferred Stock may redeem the shares of Preferred Stock at the earlier of July 28, 2010 or the date on which the price of our common stock exceeds $2.00 per share, or the date of a public announcement of the intention or agreement to engage in a transaction or series of transactions that may result in a change of control. The preferential dividend and redemption rights of the Preferred Stock may make investments in our securities less attractive to potential investors.
The holders of the Preferred Stock are also entitled to voting rights that require the majority vote of the outstanding Preferred Stock prior to making certain amendments or changes to our certificate of incorporation or bylaws, including the terms of the Preferred Stock. A majority vote of the Preferred Stock is also required prior to any future issuance of our securities, subject to certain exceptions, including an exception that allows us to issue up to $25 million of our securities as long as we have given the holders of the Preferred Stock the exclusive right to purchase such securities prior to their issuance. We cannot predict whether we will be able to obtain any approvals required by these voting requirements, and the uncertainties associated with these voting requirements could adversely affect our ability to negotiate with potential investors.
In connection with an offering of securities that we completed in July 2009, we granted the purchasers of those securities the right, subject to certain exceptions, to participate in any future equity financing by us prior to December 30, 2010. The participation right allows the investors to purchase up to 35% of any equity securities we offer. These participation rights may make investments in our securities less attractive to potential investors and could adversely affect our ability to negotiate with potential investors.
Outstanding warrants to purchase 7,012,632 shares of our common stock contain an exercise price reset feature that may be triggered upon certain events, such as the issuance of shares of common stock at a price
below the maximum warrant exercise price. If triggered, the exercise price reset feature results in a downward adjustment to the maximum warrant exercise price to an amount equal to the average of the then current maximum exercise price and the lowest price at which shares of our common stock are issued on the date when the event occurred. Other outstanding warrants to purchase 1,350,000 shares of our common stock provide for anti-dilution protection, which adjusts the exercise price of each warrant, from time to time upon the occurrence of certain events, including the issuance of shares of common stock at a price lower than the exercise price, stock splits, dividends, recapitalizations and similar events. These price adjustment provisions may result in dilution to potential investors, which could make investments in our securities less attractive to potential investors, and could adversely affect our ability to negotiate with potential investors.
We have agreed to issue additional shares to one institutional investor, Fletcher, if, prior to any exercise of warrants by Fletcher that we issued in 2008, we announce the sale of additional equity securities. The issuance of additional shares to Fletcher pursuant to this agreement may result in dilution to potential investors, which could make investments in our securities less attractive to potential investors, and could adversely affect our ability to negotiate with potential investors.
The geothermal power production development activities of our Power Systems segment may not be successful.
We are devoting a substantial amount of our available resources to the power production development activities of our Power Systems segment. To date, we have placed one geothermal power plant in service, and we continue our efforts to ramp up production of that plant. However, our ability to successfully complete that plant and develop additional projects is uncertain.
In connection with our first power plant, Thermo No. 1, we have experienced unexpected difficulties and delays in developing a well field that will produce sufficient heat to operate the plant at full capacity. While we have gained valuable experience that could benefit future projects, we could experience similar unexpected difficulties at future projects, which could adversely affect the economics of those projects. As a result, we cannot be certain that we will be able to operate any of our plants at full capacity on an economic basis.
Our success in developing a particular geothermal project is contingent upon, among other things, locating and developing a viable geothermal site, negotiation of satisfactory engineering, procurement and construction agreements, negotiation of satisfactory power purchase agreements, receipt of required governmental permits, obtaining interconnection rights, obtaining transmission service rights, obtaining adequate financing, and the timely implementation and satisfactory completion of construction. We may be unsuccessful in accomplishing any of these necessary requirements or doing so on a timely basis.
We have limited operating experience and revenue, and we are not currently profitable. We expect to continue to incur net losses for the foreseeable future, and we may never achieve or maintain profitability.
We have a limited operating history and, from our inception, we have earned limited revenue from operations. We have incurred significant net losses in each year of our operations, including a net loss applicable to common stockholders of approximately $20.2 million and $45.5 million for the years ended December 31, 2009 and 2008, respectively. As a result of ongoing operating losses, we had an accumulated deficit of approximately $109.7 million on cumulative revenues from inception of approximately $3.2 million as of December 31, 2009. In addition, at December 31, 2009, we had negative working capital totaling $6.4 million.
Under our current growth plan, we do not expect that our revenues and cash flows will be sufficient to cover our expenses unless we are able to successfully place a number of power plants in service. As a result, we expect to continue to incur substantial losses until we are able to generate significant revenues. Our ability to generate significant revenues and become profitable will depend on many factors, including our ability to:
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secure adequate capital;
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identify and secure productive geothermal sites;
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verify that the properties in which we have acquired an interest contain geothermal resources that are sufficient to generate electricity;
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acquire electrical transmission and interconnection rights for geothermal plants we intend to develop;
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enter into power purchase agreements for the sale of electrical power from the geothermal power plants we intend to develop at prices that support our operating and financing costs;
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enter into additional tax equity partner agreements with potential financing partners that will provide for the allocation of tax benefits to them and for the contribution of capital by them to our projects or to successfully utilize new incentive provisions being implemented by the United States government;
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finance and complete the development of multiple geothermal power plants;
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manage construction, drilling and operating costs associated with our geothermal power projects;
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successfully license commercial applications of our motor, generator and drive technologies;
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enforce and protect our intellectual property while avoiding infringement claims;
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comply with applicable governmental regulations; and
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attract and retain qualified personnel.
Our independent registered public accounting firm’s report on our 2009 financial statements questions our ability to continue as a going concern.
Our independent registered public accounting firm’s report on our financial statements as of December 31, 2009 and 2008 and for the three year period ended December 31, 2009 expresses doubt about our ability to continue as a going concern. Their report includes an explanatory paragraph stating that there is substantial doubt about our ability to continue as a going concern due to the lack of sufficient capital, as of the date their report was issued, to support our business plan through the end of 2010.
We will need to secure additional financing in the future and if we are unable to secure adequate funds on terms acceptable to us, we will be unable to support our business requirements, build our business or continue as a going concern. Accordingly, we can offer no assurance that the actions we plan to take to address these conditions will be successful. Inclusion of a “going concern qualification” in the report of our independent accountants or any future report may have a negative impact on our ability to obtain financing and may adversely impact our stock price.
The current worldwide political and economic conditions, specifically disruptions in the capital and credit markets, may materially and adversely affect our business, operations and financial condition.
Recently, general worldwide economic conditions have experienced a downturn due to the credit conditions resulting from the subprime-mortgage turmoil and other factors, slower economic activity, concerns about inflation and deflation, decreased consumer confidence, reduced corporate profits and capital spending, recent international conflicts, recent terrorist and military activity, and the impact of natural disasters and public health emergencies. If the current market conditions continue or worsen, our business, operations and financial condition will likely be materially and adversely affected.
The United States credit and capital markets have become increasingly volatile as a result of adverse conditions that have caused the failure and near failure of a number of large financial services companies. If the capital and credit markets continue to experience volatility and the availability of funds remains limited, our ability to obtain needed financing on favorable terms could be severely limited. In the current environment, lenders may seek more restrictive lending provisions and higher interest rates that may reduce our ability to obtain financing and increase our costs. Also, lenders may simply be unwilling or unable to provide financing.
Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect our access to capital needed for our operations and development plans. If we are unable to obtain adequate financing, we could be forced to reduce, delay or cancel planned capital expenditures, sell assets or seek additional equity capital, or pursue other actions that could adversely affect future operations. Failure to obtain sufficient financing or a reduction of expenditures may cause delays and make it more difficult to execute our plans to develop geothermal power plants in accordance with our expectations. It would also make it more difficult to conduct adequate research and development and other activities necessary to commercialize our Symetron™ technologies.
The market price for our common stock has experienced significant price and volume volatility and is likely to continue to experience significant volatility in the future. Such volatility may cause investors to experience dramatic declines in our stock price from time to time, may impair our ability to secure additional financing and may otherwise harm our business.
The closing price of our common stock declined significantly during 2009. The closing price fluctuated from a low of $0.89 per share to a high of $4.71 per share during the period from January 1, 2009 to March 12, 2010. Our stock price is likely to experience significant volatility in the future as a result of numerous factors outside of our control, including the level of short sale transactions. As a result, the market price of our stock may not reflect our intrinsic value. In addition, following periods of volatility in our stock price, there may be increased risk that securities litigation, governmental investigations or enforcement proceedings may be instituted against us. Any such litigation, and investigation or other procedures, regardless of merits, could materially harm our business and cause our stock price to decline due to potential diversion of management attention and harm to our business reputation.
In addition, if the market price for our common stock remains below $5.00 per share, our common stock may be deemed to be a penny stock, and therefore subject to rules that impose additional sales practices on broker-dealers who sell our securities. For example, broker-dealers must make a special suitability determination for the purchaser and have received the purchaser’s written consent to the transaction prior to sale. Also, a disclosure schedule must be delivered to each purchaser of a penny stock, disclosing sales commissions and current quotations for the securities. Monthly statements are also required to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks. Because of these additional conditions, some brokers may choose to not effect transactions in penny stocks. This could have an adverse effect on the liquidity of our common stock.
The volatility in our stock price could impair our ability to raise additional capital. Further, to the extent we do raise additional funds through equity financing, we may need to issue such equity at a substantial discount to the market price for our stock. This, in turn, could contribute to the volatility in our stock price. In addition, in connection with future equity financing transactions, we may be required to issue additional shares of stock to investors who purchased securities from us in prior transactions, and future equity financings may result in adjustments to the exercise price of our outstanding warrants. These factors could also contribute to volatility in our stock price.
The financial performance of our Power Systems segment is subject to changes in the legal and regulatory environment.
Our geothermal power projects will be subject to extensive regulation. Changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs and require additional capital expenditures. Future changes could also reduce or eliminate certain benefits that are currently available.
Federal and state energy regulation is subject to frequent challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We may not be able to obtain or maintain all
regulatory approvals or modifications to existing regulatory approvals that may be required in the future. In addition, the cost of operation and maintenance and the financial performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
In order to promote the production of renewable energy, including geothermal energy, the federal government has created several significant tax incentives. These tax incentives are instrumental to our ability to finance and develop geothermal power plants by providing increased economic benefits. If the available tax incentives were reduced or eliminated, the economics of the projects would be adversely affected and there could be reductions in our overall profitability or the amount of funding available from tax equity partners. Some projects may not be viable without these tax incentives.
Available federal tax incentives include deductibility of intangible drilling costs, accelerated depreciation, depletion allowances and the ITC, all of which currently are permanent features of the Internal Revenue Code with respect to geothermal power projects. In addition, the Recovery Act extended the availability of the PTC, for geothermal projects placed in service before 2014 and created a new grant program for geothermal projects that are placed in service in 2009 or 2010, regardless of when construction begins, or for which construction begins in 2009 or 2010 and which are placed in service before 2014.
The ITC is claimed in the year in which the qualified project is placed in service, and the amount of the credit is a specified percentage (10% or 30%) of the eligible costs of the facility. All or some of the ITC is subject to recapture if the property eligible for the credit is sold or otherwise disposed, or ceases to be eligible property, within five years after being placed in service. In lieu of claiming the ITC, a project owner generally can claim the PTC during the first ten years after the project is placed in service. The amount of the PTC is adjusted for inflation. For 2009, the amount was $21.00 per megawatt hour of electricity produced from the facility and sold to unrelated parties. As extended by the Recovery Act, the PTC applies to Qualifying Facilities that are placed in service before 2014. The amount of the PTC also is subject to phase-out if the national average price of electricity produced from qualified energy resources exceeds an inflation adjusted threshold.
In addition, pursuant to the Recovery Act, an owner may elect to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or the PTC. For a geothermal project, the amount of the grant is 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the date the U.S. Treasury Department deems the application is properly submitted and complete. All or some of the grant is subject to recapture if the property eligible for the grant is sold or otherwise disposed, or ceases to be eligible property within, five years after being placed in service. None of the grant should be included in federal taxable income, but may be included in applicable state taxable income.
Owners of projects also are permitted to depreciate for tax purposes most of the cost of the power plant on an accelerated basis, generally, over a five-year period. If an owner elects to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or PTC, or if the owner elects to receive the ITC, the basis of the property for depreciation purposes is reduced by an amount equal to 50 percent of the grant or ITC, whichever is applicable.
All of these programs are subject to review and change by Congress from time to time. For example, recent legislation has been introduced to remove equipment sourced outside of the United States from the eligible basis used in calculating the Section 1603 grant. In addition, several of the programs are currently scheduled to expire, and continuation of those incentives will require affirmative Congressional action. Moreover, there are ambiguities as to how some of the provisions of the Recovery Act will operate.
Many of the tax incentives associated with geothermal power projects generally are beneficial only if the owners of the project have sufficient taxable income to utilize the tax incentives. Due to the nature and timing of these tax incentives, it is likely that the tax incentives available in connection with our geothermal power plants
(other than the grant in lieu of the ITC and PTC) will exceed our ability to efficiently utilize these tax benefits for at least several years of operations. Therefore, an important part of our strategy involves partnering with investors that are able to utilize the tax incentives to offset taxable income associated with their operations unrelated to our geothermal power plants. For example, a corporation in an unrelated industry may be willing to finance the development of a geothermal power plant in exchange for receiving the benefit of the tax incentives, which it could then use to reduce the tax liability associated with its regular operations.
Tax reform has the potential to have a material effect on our business, financial condition, future results and cash flow. Tax reform could reduce or eliminate the value of the tax subsidies currently available to geothermal projects. Any restrictions or tightening of the rules for lease or partnership transactions, whether or not part of major tax reform, could also materially affect our business, financial condition, future results and cash flow. In addition, changes to the Internal Revenue Code could significantly increase the regulatory-related compliance and other expenses incurred by geothermal projects which, in turn, could materially and adversely affect our business, financial condition, future results and cash flow. Any such changes could also make it more difficult for us to obtain financing for future projects.
A significant part of our business strategy is to utilize the tax and other incentives available to developers of geothermal power generating plants to attract strategic alliance partners with the capital sufficient to complete these projects. Many of the incentives available for these projects are new and highly complex. There can be no assurance that we will be successful in structuring agreements that are attractive to potential strategic alliance partners. If we are unable to do so, we may be unable to complete the development of our geothermal power projects and our business could be harmed.
The exploration, development, and operation of geothermal energy resources by our Power Systems segment is subject to geological risks and uncertainties, which may result in decreased performance, increased costs, or abandonment of our projects.
Our Power Systems segment is involved in the exploration, development and operation of geothermal energy resources. These activities are subject to uncertainties, which vary among different geothermal resources. These uncertainties include dry holes, flow-constrained wells, wells that become obstructed during drilling, uncontrolled releases of pressure and temperature decline, and other factors, all of which can increase our operating costs and capital expenditures or reduce the efficiency of our power plants. In addition, the high temperature and high pressure in geothermal energy resources requires special resource management and monitoring. Because geothermal resources are complex geological structures, we can only estimate their geographic area. The viability of geothermal projects depends on different factors directly related to the geothermal resource, such as the heat content (the relevant composition of temperature and pressure) flow of the geothermal resource, the useful life (commercially exploitable life) of the resource and operational factors relating to the extraction of geothermal fluids. Although we believe our geothermal resources will be fully renewable if managed appropriately, the geothermal resources we intend to exploit may not be sufficient for sustained generation of the anticipated electrical power capacity over time. Further, any of our geothermal resources may suffer an unexpected decline in capacity. In addition, we may fail to find commercially viable geothermal resources in the expected quantities and temperatures, which would adversely affect our development of geothermal power projects.
The operation of geothermal power plants depends on the continued availability of adequate geothermal resources. Although we believe our geothermal resources will be fully renewable if managed properly, we cannot be certain that any geothermal resource will remain adequate for the life of a geothermal power plant. If the geothermal resources available to a power plant we develop become inadequate, we may be unable to perform under the power purchase agreement for the affected power plant, which in turn could reduce our revenues and materially and adversely affect our business, financial condition, future results and cash flow. If we suffer degradation in our geothermal resources, our insurance coverage may not be adequate to cover losses sustained as a result thereof.
Our ability to operate a geothermal plant at full capacity depends significantly on the characteristics of the production wells we drill to use for the plant. The wells need to provide sufficient heat at flow rates that can be maintained without a significant increase in the parasitic load associated with the plant. The parasitic load refers to the amount of electricity used by the plant and well field to maintain operations. A significant portion of the parasitic load results from pumps and other equipment used to maintain the flow of geothermal water from the earth through the plant and back into the earth through reinjection wells. Generally, water with a higher temperature will allow the plant to operate with a slower rate of flow, which results in a decrease in the parasitic load because less electricity is required to maintain the necessary flow rate. Water with lower temperatures, on the other hand, requires a higher flow rate to operate the plant, which increases the parasitic load. Unless the water produced by a well is hot enough to increase the amount of power generated by the plant without a corresponding increase to the parasitic load, the well will not result in a net increase in the amount of power available for sale from the plant. Therefore, the overall temperature of the water produced by the production wells is critical to our ability to operate the plant at full capacity. Similarly, a deeper resource increases parasitic load because the pumps have to lift the water a greater distance. We cannot be certain whether wells will increase net production at a plant until the wells are brought online and the impact to the parasitic load at the plant has been determined.
We have experienced certain delays and cost overruns on the Thermo No. 1 plant, and we may experience similar delays and cost overruns on subsequent projects.
We completed major construction of the cooling towers and transmission lines and installed the power generating units at the Thermo No. 1 plant in the fourth quarter of 2008. We completed the commissioning of the plant in the first quarter of 2009. In April 2009, we began selling electricity generated by the Thermo No. 1 plant to the City of Anaheim pursuant to a power purchase agreement we previously entered into with Anaheim.
During the year ended December 31, 2009, we delivered 25,200 MW hours of electricity to the City of Anaheim. The Thermo No. 1 plant is currently transmitting approximately 6 MW of electricity to the City of Anaheim, which represents approximately half of the plant’s designed capacity. Thus far, we have been unable to operate the plant at full capacity due to insufficient heat and flow from the production wells that provide geothermal water to the plant. In the fall of 2009 we undertook a comprehensive review of the plant and well field operations at the Thermo No. 1 plant and, together with outside experts and our financing partners, developed a plan for increasing the output of the Thermo No. 1 plant. The key component of this plan was to re-work certain wells in order to eliminate down flow of a shallower, cooler zone of geothermal fluids which was mixing with the deeper, hotter zones. In general, this cooler zone contains geothermal fluids in the range of 200 Fahrenheit, while the deeper zone contains temperatures greater than 300 Fahrenheit. We believe that well field work and optimization of certain operations at the plant, have the potential to significantly increase the net power production from the plant during 2010. However, we have not completed all of the necessary drilling, stimulation work and testing, and we cannot be certain the additional modifications to the well field will allow us to operate the Thermo No. 1 plant at full capacity.
The Thermo No. 1 plant is the first ever large-scale commercial application of the PWPS Pure-Cycle units and the first plant built under our rapid-deployment approach so delays and overruns are not entirely unexpected. Some of the key drivers of the delays and cost overruns are as follows:
Well Field Development:
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Increased costs to broaden previous well field plans.
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Complications encountered by drilling contractors.
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High demand for drilling services and related materials due to the rapid increase in the price of oil.
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Higher than expected loads for well field pumps.
Construction:
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Wider than necessary step-outs for injection wells, which increased piping and electrical costs, due to concerns of lenders.
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Construction of primary access road improvements to accommodate wider access to Thermo No. 1 than previously anticipated.
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Additional costs incurred to connect piping from additional production wells to the plant.
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Additional costs incurred relating to establishing the greater Thermo area.
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Increased prices for steel, concrete and other commodities due to high demand.
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Payment of overtime and other additional costs in order to accelerate the construction schedule.
Equipment:
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Expenses associated with installing PWPS power generating units for the first time, which allowed us to identify design changes for the benefit of future plants.
Transmission:
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In anticipation of future plants, we built a larger transmission infrastructure.
If we are unable to find adequate solutions for the problems we are encountering with the construction and operation of the Thermo No. 1 plant, we may experience similar delays and cost overruns on subsequent projects.
Our Power Systems segment operations may be materially adversely affected if we fail to properly manage and maintain our geothermal resources.
Our geothermal power plants use geothermal resources to generate electricity. When we develop a geothermal power plant, we conduct hydrologic and geologic studies. Based on these studies, we consider all of the geothermal resources used in our power plants to be fully renewable.
Unless additional hydrologic and geologic studies confirm otherwise, there are a number of events that could have a material adverse effect on our ability to generate electricity from a geothermal resource and/or shorten the operational duration of a geothermal resource, which could cause the applicable geothermal resource to become a non-renewable wasting asset. These events include:
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Any increase in power generation above the amount our hydrological and geological studies indicate that the applicable geothermal resource will support;
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Failure to recycle all of the geothermal fluids used in connection with the applicable geothermal resource; and
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Failure to properly maintain the hydrological balance of the applicable geothermal resource.
While we intend to properly manage and maintain our geothermal resources in order to ensure that they are fully renewable, our ability to do so could be subject to unforeseen risks and uncertainties beyond our control.
Our Power Systems segment may be materially adversely affected if we are unable to successfully utilize certain heat transfer technologies in our geothermal power projects.
Our Power Systems segment intends to utilize certain heat transfer technologies in its geothermal power projects. One of the providers of these heat transfer technologies is PWPS. PWPS’s heat transfer technologies are designed to enable the generation of power from geothermal resources that are lower in temperature than those resources used in traditional flash steam geothermal projects.
PWPS’s heat transfer technologies have a limited operating history and have only been deployed in a limited number of geothermal power projects. Although we are using these technologies in our Thermo No. 1 plant, that power plant has only been operating for a short time. As a result, we cannot be certain that PWPS’s heat transfer technologies or other vendors’ heat transfer technologies can be successfully implemented. If we are not able to successfully utilize heat transfer technologies in our geothermal power projects and we are unable to utilize appropriate substitute technologies, we may be unable to develop our projects and our business, prospects, financial condition and results of operations could be harmed.
The costs of compliance with environmental laws and of obtaining and maintaining environmental permits and governmental approvals required for construction and/or operation of geothermal power plants are substantial, and any non-compliance with such laws or regulations may result in the imposition of liabilities, which could materially and adversely affect our business, financial condition, future results and cash flow.
Our geothermal power projects are required to comply with numerous federal, regional, state and local statutory and regulatory environmental standards. Geothermal projects must also maintain numerous environmental permits and governmental approvals required for construction and/or operation. Environmental permits and governmental approvals typically 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 we fail to comply with any statutory or regulatory environmental standards, we may become subject to a regulatory enforcement action and the operation of the projects could be adversely affected or be subject to fines, penalties or additional costs.
The geothermal power projects developed by our Power Systems segment could expose us to significant liability for violations of hazardous substances laws because of the use or presence of such substances.
The geothermal power projects developed by our Power Systems segment will be subject to numerous federal, regional, state and local statutory and regulatory standards relating to the use, storage and disposal of hazardous substances. We may use industrial lubricants, water treatment chemicals and other substances at our projects that could be classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or near the projects, we could become liable for the investigation and removal of those substances, regardless of their source and time of release. If we fail to comply with these laws, ordinances or regulations or any change thereto, we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, 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.
In order to finance the development of our geothermal power projects, we may transfer a portion of our equity interest in the individual projects to a third party and enter into long-term fixed price power purchase agreements. Under generally accepted accounting principles, this may result in the deconsolidation of these subsidiaries, and the reflection of only our net ownership interests in our financial statements.
Each of the geothermal power projects our Power Systems segment develops will likely be owned by a separate subsidiary. The geothermal power projects developed by these subsidiaries will likely be separately financed. To obtain the financing necessary to develop the geothermal power projects, we may transfer a portion of our equity interest in the individual subsidiaries to a third party and enter into long-term fixed price power purchase agreements. Depending upon the nature of these arrangements and the application of generally accepted accounting principles, we may be required to deconsolidate one or more or all of these subsidiaries, which would result in our share of the net profits or loss generated by the deconsolidated entities being presented as a net amount in our financial statements. As a result, our financial statements would not reflect the gross revenues and expenses of the deconsolidated entities. However, we do not expect the effect of such deconsolidation, if required, to have an impact on our stockholders’ equity (deficit), net income/loss or earnings/loss per share.
Our foreign projects expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions, and policies of foreign governments, any of which risks may delay or reduce our ability to profit from such projects.
We have accumulated a large portfolio of geothermal interests in four western continental states and a geothermal concession in Indonesia. These geothermal interests are important to our ability to develop geothermal power plants. We continue to accumulate additional interests in geothermal resources for potential future projects. Our foreign operations are subject to regulation by various foreign governments and regulatory authorities and are subject to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in the United States, which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. Furthermore, existing laws or regulations may be amended or repealed, and new laws or regulations may be enacted or issued. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign operations are also subject to significant political, economic and financial risks, which vary by country, and include:
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changes in government policies or personnel;
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changes in general economic conditions;
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restrictions on currency transfer or convertibility;
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changes in labor relations;
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political instability and civil unrest;
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changes in the local electricity market;
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breach or repudiation of important contractual undertakings by governmental entities; and
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expropriation and confiscation of assets and facilities.
Our foreign projects may expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects.
Risks attributable to fluctuations in currency exchange rates can arise when any of our foreign subsidiaries borrow funds or incur operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary’s ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary’s overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad, or restrictions on the conversion of local currency into foreign currency, would have an adverse effect on the operations of our foreign projects and foreign manufacturing operations, and may limit or diminish the amount of cash and income that we receive from such foreign projects and operations.
A significant portion of our net revenue is attributed to payments made by power purchasers under power purchase agreements. The failure of any such power purchaser to perform its obligations under the relevant power purchase agreement or the loss of a power purchase agreement due to a default would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
A significant portion of our net revenue is attributed to revenues derived from power purchasers under the relevant power purchase agreements. The City of Anaheim has accounted for 100%, of our revenues for the year ended December 31, 2009. We do not make any representations as to the financial condition or creditworthiness of any purchaser under a power purchase agreement, and nothing in this annual report should be construed as such a representation.
There is a risk that the City of Anaheim or any future power purchasers may not fulfill their respective payment obligations under their power purchase agreements. If any of the power purchasers fails to meet its payment obligations under its power purchase agreements, it could materially and adversely affect our business, financial condition, future results and cash flow.
If any of our domestic projects loses its current Qualifying Facility status under PURPA, or if amendments to PURPA are enacted that substantially reduce the benefits currently afforded to Qualifying Facilities, our domestic operations could be adversely affected.
Most of our domestic projects are Qualifying Facilities pursuant to PURPA and are eligible for regulatory exemptions from most provisions of the FPA and certain state laws and regulations, which largely exempts the projects 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 projects were to lose its Qualifying Facility status, such project could become subject to the full scope of the FPA and applicable state regulation. The application of the FPA and other applicable state regulation to our domestic projects could require our operations to comply with an increasingly complex regulatory regime that may be costly and greatly reduce our operational flexibility.
In addition, pursuant to the FPA, FERC has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of public utilities in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. Qualifying Facilities are largely exempt from the FPA. If a domestic project were to lose its Qualifying Facility status, it would become a public utility under the FPA, and the rates charged by such project pursuant to its power purchase agreements would be subject to the review and approval of FERC. FERC, upon such review, may determine that the rates currently set forth in such power purchase agreements are not appropriate and may set rates that are lower than the rates currently charged. In addition, FERC may require that some or all of our domestic projects refund amounts previously paid by the relevant power purchaser to such project. Such events would likely result in a decrease in our future revenues or in an obligation to disgorge revenues previously received from our domestic projects, either of which would have an adverse effect on our revenues. Even if a project does not lose its Qualifying Facility status, pursuant to a final rule issued by FERC for projects above 20 MW, if a project’s power purchase agreement is terminated or otherwise expires, and the subsequent sales are not made pursuant to a state’s implementation of PURPA, that project will become subject to FERC’s ratemaking jurisdiction under the FPA. Moreover, a loss of Qualifying Facility status also could permit the power purchaser, pursuant to the terms of the particular power purchase agreement, to cease taking and paying for electricity from the relevant project or, consistent with FERC precedent, to seek refunds of past amounts paid. This could cause the loss of some or all of our revenues payable pursuant to the related power purchase agreements, result in significant liability for refunds of past amounts paid, or otherwise impair the value of our projects. If a power purchaser were to cease taking and paying for electricity or seek to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers or that we would have sufficient funds to make such payments. In addition, the loss of Qualifying Facility status would be an event of default under the financing arrangements currently in place for some of our projects, which would enable the lenders to exercise their remedies and enforce the liens on the relevant project.
Pursuant to the EPACT 2005, FERC was also given authority to prospectively lift the mandatory obligation of a utility under PURPA to offer to purchase the electricity from a Qualifying Facility if the utility operates in a workably competitive market. Existing power purchase agreements between a Qualifying Facility and a utility are not affected. If the utilities in the regions in which our domestic projects operate were to be relieved of the mandatory purchase obligation, they would not be required to purchase energy from the project in the region under Federal law upon termination of the existing power purchase agreement or with respect to new projects, which could materially and adversely affect our business, financial condition, future results and cash flow.
Some of our leases will terminate if we do not achieve commercial production during the primary term of the lease, 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 we achieve commercial production or pursuant to other terms of extension. The land covered by some of our leases is undeveloped and has not yet achieved commercial production of the geothermal resources. Leases that cover land which remains undeveloped and does not achieve commercial production and leases that we allow to expire, will terminate. In the event that a lease is terminated and we determine that we will need that lease once the applicable project is operating, we would need to enter into one or more new leases with the owner(s) of the premises that are the subject of the terminated lease(s) in order to develop geothermal resources from, or inject geothermal resources into, such premises or secure rights to alternate geothermal resources or lands suitable for injection, all of which may not be possible or could result in increased cost to us, which could materially and adversely affect our business, financial condition, future results and cash flow.
Claims have been made that some geothermal plants cause seismic activity and related property damage.
There are approximately two-dozen geothermal plants operating within a fifty-square-mile region in the area of Anderson Springs, in Northern California, and there is general agreement that the operation of these plants causes a generally low level of seismic activity. Some residents in the Anderson Springs area have asserted property damage claims against those plant operators. There are significant issues whether the plant operators are liable, and to date no court has found in favor of such claimants. While we do not believe the areas that we are developing, as noted above, will present the same geological or seismic risks, there can be no assurance that we would not be subject to similar claims and litigation, which may adversely impact our operations and financial condition.
Our Transportation & Industrial segment may be unable to successfully license our intellectual property.
A significant part of our long-term business strategy for our Transportation & Industrial segment is based upon the licensing of our Symetron™ technologies to electric motor, controller, alternator and generator manufacturers, suppliers and system integrators. We expect the sales cycle with respect to the licensing of our technology to be lengthy, and there can be no assurance that we will achieve meaningful licensing revenues in the time frames that we expect.
Our Symetron™ technologies are relatively new and commercially unproven. While we have completed some laboratory testing, our technologies have not yet been durability tested for long-term applications. We can provide no assurance that our technologies will prove suitable for our target business segments. Our potential product applications require significant and lengthy product development efforts. To date, we have not developed any commercially available products. It may be years before our technology is proven viable, if at all. During our product development process, we may experience technological issues that we may be unable to overcome. Superior competitive technologies may be introduced or potential customer needs may change resulting in our technology or products being unsuitable for commercialization. Because of these uncertainties, our efforts to license our technologies may not succeed.
We are currently focusing on commercializing our Symetron™ technologies in the transportation and industrial markets. We cannot predict the rate at which market acceptance of our technologies will develop in these markets, if at all. Additionally, we may focus our product commercialization activities on a particular industry or industries, which may not develop as rapidly as other industries, if at all. The commercialization of our products or the licensing of our intellectual property in an industry or industries that are not developing as rapidly as other industries could harm our business, prospects, financial condition and results of operations.
The demand for our technologies may be dependent on government regulations and policies such as standards for Corporate Average Fuel Economy, or CAFE, Renewable Portfolio Standards, or RPS, the Clean Air
Act and Section 45 of the Internal Revenue Code. Changes in these regulations and policies could have a negative impact on the demand for the power we plan to generate and our technologies. Any new government regulations or policies pertaining to our products or technologies may result in significant additional expenses to us and our potential customers and could cause a significant reduction in demand for our technologies and thereby significantly harm our Transportation & Industrial segment.
The recent economic downturn has had a dramatic, adverse effect on the automotive industry and other large industrial manufacturers that would be in a position to use and benefit from our technologies. As a result, we believe our ability to commercialize our Symetron™ technologies will be limited until economic conditions improve. We intend to evaluate the prospects for our Transportation & Industrial segment on an ongoing basis. If we believe there are attractive opportunities, we will devote the resources to pursue those opportunities to the extent we believe appropriate. If, on the other hand, we determine that the risks and uncertainties for this business segment are too great in light of the current economic climate, we may choose to further reduce the resources devoted to these efforts. We may also be required to develop a new long-term business strategy for the Transportation & Industrial segment, or discontinue operating this business segment.
We may not be able to enforce or protect the intellectual property that our Transportation & Industrial segment is seeking to license.
The success of our Transportation & Industrial segment is dependent upon protecting our proprietary technology. We rely primarily on a combination of copyright, patent, trade secret and trademark laws, as well as confidentiality procedures and contractual provisions to protect our proprietary rights. These laws, procedures and provisions provide only limited protection. We have applied for patent protection on most of our key technologies. We cannot be certain that our issued United States patents or our pending United States and international patent applications will result in issued patents or that the claims allowed are or will be sufficiently broad to protect the inventions derived from our technology or prove to be enforceable in actions against alleged infringers. Also, additional patent applications that we may file for our current and future technologies may not be issued. We have received three trademark registrations in the United States and ten trademark registrations internationally. We have also applied for five additional trademark registrations in the United States and one additional trademark registration internationally which may never be granted.
The contractual provisions we rely on to protect our trade secrets and proprietary information, such as our confidentiality and non-disclosure agreements with our employees, consultants and other third parties, may be breached and our trade secrets and proprietary information may be disclosed to the public. Despite precautions that we take, it may be possible for unauthorized third parties to copy aspects of our technology or products or to obtain and use information that we regard as proprietary. In particular, we may provide our licensees with access to proprietary information underlying our licensed applications which they may improperly appropriate. Additionally, our competitors may independently design around patents and other proprietary rights we hold.
Policing unauthorized use of our technology may be difficult and some foreign laws do not protect our proprietary rights to the same extent as United States laws. Litigation may be necessary in the future to enforce our intellectual property rights or determine the validity and scope of the proprietary rights of others. Litigation could result in substantial costs and diversion of resources and management attention resulting in significant harm to our business.
If third parties assert that our current or future products infringe their proprietary rights, we could incur costs and damages associated with these claims, whether the claims have merit or not, which could significantly harm our business. Any future claims could harm our relationships with existing or potential customers. In addition, in any potential dispute involving our intellectual property, our existing or potential customers could also become the targets of litigation, which could trigger indemnification obligations under license and service agreements and harm our customer relationships. If we unsuccessfully defend an infringement claim, we may lose our intellectual property rights, which could require us to obtain licenses which may not be available on acceptable terms or at all.
We license patented intellectual property rights from third party owners. If such owners do not properly maintain or enforce the patents underlying such licenses, our competitive position and business prospects could be harmed. Our licensors may also seek to terminate our licenses.
We are a party to licenses that give us rights to third-party intellectual property that is necessary or useful to our business. Our success will depend in part on the ability of our licensors to obtain, maintain and enforce our licensed intellectual property. Our licensors may not successfully prosecute the patent applications to which we have licenses. Even if patents are issued in respect of these patent applications, our licensors may fail to maintain these patents, may determine not to pursue litigation against other companies that are infringing these patents, or may pursue such litigation less aggressively than we would. Without protection for the intellectual property we license, other companies might be able to offer substantially identical products for sale, which could adversely affect our competitive business position and harm our business prospects.
Our licensors may allege that we have breached our license agreement with them, and accordingly seek to terminate our license. If successful, this could result in our loss of the right to use the licensed intellectual property, which could adversely affect our ability to commercialize our technologies, products or services, as well as harm our competitive business position and our business prospects.
Our Transportation & Industrial segment could incur significant expenses if products built with our technology contain defects.
If our Transportation & Industrial segment successfully licenses our technology, products built with that technology may result in product liability lawsuits for any defects that they may contain. Detection of any significant defects may result in, among other things, loss of, or delay in, market acceptance and sales of our technology, diversion of development resources, injury to our reputation, or increased service and warranty costs. A material product liability claim could significantly harm our business, result in unexpected expenses and damage our reputation.
We face significant competition in each of our business segments. If we fail to compete effectively, our business will suffer.
Our Power Systems segment faces significant competition from other companies seeking to develop the geothermal opportunities available. Some of our competitors for geothermal projects have substantial capabilities and greater financial and technical resources than we do. As a result, we may be unable to acquire additional geothermal resources or projects on terms acceptable to us.
Our Power Systems segment also competes with producers of energy from other renewable sources. This competition may make it more difficult for us to enter into power purchase agreements for our projects on terms that are acceptable to us.
We believe our Transportation & Industrial segment will face significant competition from existing manufacturers, including motor, controller, alternator, and transportation vehicle companies. We may also face significant competition from our future partners. These partners may have better access to information regarding their own manufacturing processes, which may enable them to develop products that can be more easily incorporated into their products. If our potential partners improve or develop technology that competes directly with our technology, our business will be harmed.
In each of our business segments, we face competition from companies that have access to substantially greater financial, engineering, manufacturing and other resources than we do, which may enable them to react more effectively to new market opportunities. Many of our competitors may also have greater name recognition and market presence than we do, which may allow them to market themselves more effectively to new customers or partners.
We may pursue strategic acquisitions that could have an adverse impact on our business.
Our success depends on our ability to execute our business strategies. Our Power Systems segment is seeking to develop geothermal power plants. Our Transportation & Industrial segment is seeking to license our intellectual property to electric motor and controller manufacturers, suppliers and system integrators. Executing these strategies may involve entering into strategic transactions to acquire complementary businesses or technologies. In executing these strategic transactions, we may expend significant financial and management resources and incur other significant costs and expenses. There is no assurance that the execution of any strategic transactions will result in additional revenues or other strategic benefits for either of our business segments. The failure to enter into strategic transactions, if doing so would enable us to better execute our business strategies, could also harm our business, prospects, financial condition and results of operations.
We may issue company stock as consideration for acquisitions, joint ventures or other strategic transactions, and the use of common stock as purchase consideration could dilute each of our current stockholder’s interests. In addition, we may obtain debt financing in connection with an acquisition. Any such debt financing could involve restrictive covenants relating to capital-raising activities and other financial and operational matters, which may make it more difficult for us to obtain additional capital and pursue business opportunities, including potential acquisitions. In addition, such debt financing may impair our ability to obtain future additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes, and a substantial portion of cash flows, if any, from our operations may be dedicated to interest payments and debt repayment, thereby reducing the funds available to us for other purposes and could make us more vulnerable to industry downturns and competitive pressures.
If we are unable to effectively and efficiently maintain our controls and procedures to avoid deficiencies, there could be a material adverse effect on our operations or financial results.
As a publicly-traded company, we are subject to the reporting requirements of the Exchange Act and the Sarbanes-Oxley Act of 2002. These requirements may place a strain on our systems and resources. Our management is required to evaluate the effectiveness of our internal control over financial reporting as of each year end, and we are required to disclose management’s assessment of the effectiveness of our internal control over financial reporting, including any “material weakness” (within the meaning of Public Company Accounting Oversight Board, or PCAOB, Auditing Standard No. 5) in our internal control over financial reporting. On an on-going basis, we are reviewing, documenting and testing our internal control procedures. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required.
No material weaknesses were identified in connection with the audit of our 2009 financial statements. However, weaknesses or deficiencies could be identified in the future. If we fail to adequately address any deficiencies, it could have a material adverse effect on our business, results of operations and financial condition. Ultimately, if not corrected, any deficiencies could prevent us from releasing our financial information and periodic reports in a timely manner, making the required certifications regarding, and complying with our other obligations with respect to our consolidated financial statements and internal controls under the Sarbanes-Oxley Act. Any failure to maintain adequate internal controls over financial reporting and provide accurate financial statements may subject us to litigation and would cause the trading price of our common stock to decrease substantially. Inferior controls and procedures could also subject us to a risk of delisting by the New York Stock Exchange and cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.
If we fail to comply with the New York Stock Exchange listing standards and maintain our listing on the New York Stock Exchange, our business could be materially harmed and our stock price could decline.
Our shares of common stock are listed on the New York Stock Exchange. Pursuant to the Sarbanes-Oxley Act of 2002, national securities exchanges, including the New York Stock Exchange, have adopted more
stringent listing requirements. Our common stock could be delisted from the NYSE if we trade below $1.00 or if we fail to meet other listing criteria. Although we are currently in compliance with the minimum share price listing rule, our common stock recently traded below $1.00 for a short period of time. In order to maintain our listing on the NYSE, we must continue to meet the minimum share price listing rule, the minimum market capitalization rule and other continued listing criteria. Under the NYSE continued listing criteria, the average closing price of our common stock must not be below $1.00 per share for 30 or more consecutive trading days. In the event that the average closing price of our common stock is below $1.00 per share over a consecutive 30-day trading period, we would have a six-month cure period to attain both a $1.00 share price and a $1.00 average share price over 30 trading days.
We may not be able to maintain our compliance with all of the listing standards of the New York Stock Exchange. Any failure by us to maintain our listing on the New York Stock Exchange could materially harm our business, cause our stock price to decline, and make it more difficult for our stockholders to sell their shares.
We rely on key personnel and the loss of key personnel or the inability to attract, train, and retain key personnel could have a negative effect on our business.
We believe our future success will depend to a significant extent on the continued service of our executive officers and other key personnel. Of particular importance to our continued operations are our executive management and technical staff. We do not have key person life insurance for any of our executive officers, technical staff or other employees. If we lose the services of one or more of our current executive officers or key employees, or if one or more of them decide to join a competitor or otherwise compete directly or indirectly with us, our business could be harmed.
In recent years we have experienced turnover in certain key positions. On August 5, 2009, our Chief Executive Officer resigned due to health reasons. He has since been replaced by Nick Goodman whom we announced as the new Chief Executive Officer on January 11, 2010. On January 13, 2010 we announced that our Chief Financial Officer had resigned. On February 25, 2010, we announced that we hired John Perry as our new Chief Financial Officer . Mr. Perry began employment on March 10, 2010 and will begin his duties as our Chief Financial Officer on March 22, 2010. The replacement of our Chief Executive Officer and our Chief Financial Officer could result in transitional issues that could make it more difficult to execute our business plans in a timely manner.
Our future success also depends on our ability to attract, train, retain and motivate highly skilled technical and administrative personnel. Since we have limited resources to attract qualified personnel, we may not be successful in recruiting, training, and retaining personnel in the future, which would impair our ability to maintain and grow our business.
Our limited cash resources have in the past required us to rely heavily on equity compensation to hire and retain key personnel, and we expect this to continue in the future. This practice may result in significant non-cash compensation expenses and dilution to our stockholders.
We may record impairment charges which would adversely impact our results of operations.
We review our intangible assets and long-lived assets for impairment annually and whenever events or changes in circumstances indicate that the carrying amounts of these assets may not be recoverable as required by generally accepted accounting principles.
One potential indicator of impairment is whether our fair value, as measured by our market capitalization, has remained below our net book value for a significant period of time. Whether our market capitalization triggers an impairment charge in any future period will depend on the underlying reasons for the decline in stock price, the significance of the decline, and the length of time the stock price has been trading at such prices.
In the event that we determine in a future period that impairment exists for any reason, we would record an impairment charge in the period such determination is made, which would adversely impact our financial position and results of operations.
The large number of shares eligible for public sale could cause our stock price to decline.
The market price of our common stock could decline as a result of the resale of shares of common stock that were previously restricted under Rule 144. In addition, if our officers, directors or employees sell previously restricted shares for tax, estate planning, portfolio management or other purposes, such sales could be viewed negatively by investors and put downward pressure on our stock price. Approximately 67.1 million shares were free of restrictive legend as of December 31, 2009, up from approximately 40.6 million as of December 31, 2008. The occurrence of such sales, or the perception that such sales could occur, may cause our stock price to decline.
On February 3, 2010, we completed the sale of 5,000 shares of the Preferred Stock, pursuant to which we raised $5.0 million, before deducting underwriters’ fees, legal fees and other expenses. Each share of the Preferred Stock will pay a quarterly dividend, payable in cash or shares of common stock equal to an annual rate of LIBOR plus eight percent (8%), but in no event higher than 14%, subject to adjustment. Each share of the Preferred Stock will be convertible into shares of our common stock at a price of $5.00 per share, such price being subject to adjustment for stock splits, recombinations, stock dividends and the like. The holders of the Preferred Stock will have the right to redeem the shares of the Preferred Stock purchased at the earlier of six months after the issue date or the date on which the price of our common stock equals or exceeds $2.00 per share, or the date of a public announcement of the intention or agreement to engage in a transaction or series of transactions that may result in a change of control of our Company. The redemption price for each share of the Preferred Stock into shares of our common stock will be at least $1.22 per share of our common stock, subject to adjustment under certain circumstances and (b) 120% of the Prevailing Market Price (as defined in the Certificate of Rights and Preferences of the Preferred Stock) at the first redemption date. We also issued warrants (the “Preferred Warrants”) to purchase up to an additional 14,000 shares of the Preferred Stock. The issuance of any additional shares of common stock pursuant to the terms of the Preferred Stock will dilute the holders of our common stock and the possibility of these additional issuances of common stock may put downward pressure on our stock price.
Sales of a substantial number of shares of our common stock or other securities in the public markets, or the perception that these sales may occur, could cause the market price of our common stock or other securities to decline and could materially impair our ability to raise capital through the sale of additional securities.
Our reported financial results may be adversely affected by changes in United States generally accepted accounting principles.
United States generally accepted accounting principles are subject to interpretation by the Financial Accounting Standards Board, or FASB, the American Institute of Certified Public Accountants, the SEC, and various bodies formed to promulgate and interpret appropriate accounting principles. A change in these principles or interpretations could have a significant effect on our financial results. For example, prior to January 1, 2009, we were required to record certain warrants with exercise price reset features as equity, if the warrants were considered to be indexed to our own stock. However, for periods after January 1, 2009, we are required to record certain warrants with exercise price reset features as derivative liabilities and record the quarterly changes in fair market value as gains or losses in the financial statements. A significant increase in the fair value of the warrants liability can result in a significant loss recorded during the corresponding period in the financial statements.
We have never declared or paid dividends on our common stock and we do not anticipate paying dividends on our common stock in the foreseeable future.
Our business requires significant funding, and we currently invest more in project development than we earn from operating our projects and sales of our technology. In addition, the agreements governing our debt and the
terms of our Preferred Stock restrict our ability to pay dividends on our common stock. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently plan to invest all available funds and future earnings in the development and growth of our business. As a result, capital appreciation, if any, of our common stock will be the sole source of potential gain for our common stockholders in the foreseeable future.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments.
None.
ITEM 2.
ITEM 2. Properties.
We lease our corporate office located at 5152 North Edgewood Drive, Suite 200, Provo, Utah. On January 1, 2009, we entered into a new lease agreement that expanded the corporate office space from 11,400 square feet to 19,300 square feet. Monthly rent also increased from approximately $19,900 per month to approximately $34,400 per month. The new lease expires on December 31, 2011.
We also lease our Symetron™ testing facility in Utah County, Utah. The testing facility has approximately 12,000 square feet. Effective June 1, 2009, we modified the lease agreement which reduced the monthly rent from approximately $6,400 to $3,500 per month. Under the modified lease agreement, the term of the lease is month to month with a 60 day notice prior to termination of the agreement. The modification to the lease agreement expires on May 31, 2010. We are currently evaluating whether to extend this lease for a longer period of time. The corporate offices and facilities are well maintained and in good condition.
During 2008, we entered into an agreement with a private land owner adjacent to our geothermal leased property in Hidalgo County, New Mexico. Under the agreement, we are permitted to store our cooling tower equipment, pumps and other equipment that have been delivered to New Mexico for construction of our Lightning Dock geothermal power plant. All equipment is stored outside with monthly rent computed based on the number of units stored at the site which totals approximately $8,400 per month. The agreement continues on a month to month basis until all equipment is removed from the property.
We have entered into various geothermal and surface rights lease agreements, primarily through our wholly-owned subsidiaries, in which we obtained the right to develop and construct geothermal power plants. These leased properties are included in our Power Systems segment and are classified as “power project leases”. The following table sets forth our geothermal leases at December 31, 2009:
The “Greater Thermo Area and Other Projects” as used in this table excludes the Thermo No. 1 plant and parcels which are in the closes proximity to the Thermo No. 1 plant. This acreage includes other parcels which we consider part of the greater Thermo area. Our holdings in the greater Thermo area total approximately 51,000. The typical project will generally have a parcel of 480-1,000 acres dedicated to it. These larger acreage numbers represent the total acreage of the leases on which these projects are currently being proposed. However, prior to finalizing project financing for each of these, we anticipate segregating these leases so that only a small portion (480-1,000 acres as stated above) will be dedicated to a typical 10-20 MW project.
As described above, our portfolio of potential geothermal interests consists of interests in a large number of properties. We acquired many of our interests in these properties at a relatively low cost based on a very preliminary evaluation of geothermal potential. Generally, we do not consider a geothermal lease or other interest to be material to our operations unless we have determined to initiate the development of a geothermal power project that is dependent on the applicable lease or interest. Information with respect to each of our material property interests is set forth in Item 1 - “Business-Current Geothermal Power Projects” of this report.
ITEM 3.
ITEM 3. Legal Proceedings.
On August 17, 2009, Kay Mendenhall (“Mendenhall”), an individual, and Spindyne, Inc. (“Spindyne”), a Utah corporation, filed a complaint in Fourth Judicial District Court, Utah County, Utah against Jack H. Kerlin, an individual, Kraig Higginson, an individual, and Raser Technologies, Inc. Mendenhall and Spindyne allege that, around the time that Raser was formed, Kerlin, on behalf of Spindyne, assigned to Raser the rights to use certain proprietary technology that was owned by Spindyne. Mendenhall and Spindyne allege that they were not properly compensated for that technology. In general, the complaint alleges, among other claims, breach of contract, breach of implied covenant of good faith and fair dealing, and intentional interference with contract and prospective economic relations. The complaint seeks damages in an amount to be determined at trial for the value of the alleged technology. Neither Spindyne nor Mendenhall have any relationship with us or Mr. Higginson, our Chairman. The alleged technology at issue in the complaint is not currently in use and has never been used by us or, to the knowledge of the Company, Mr. Higginson. We believe the complaint to be completely without merit and are vigorously defending it.
On May 26, 2009, Bakersfield Pipe and Supply, Inc. (“Bakersfield”) filed a complaint in Fifth Judicial District Court, Beaver County, Utah against Thermo No. 1 BE-01, LLC, Intermountain Renewable Power, LLC and Raser Technologies, Inc., alleging breach of contract. The court has entered a formal judgment against us, and Bakersfield has requested the court to grant a decree of foreclosure, which would authorize Bakersfield to sell all of our property at the Thermo project (including associated transmission easements) at a sheriff’s sale. The complaint sought monetary damages of approximately $1.4 million plus interest and fees. We have accrued for these amounts and hope to reach a settlement with Bakersfield prior to any foreclosure on the Thermo project. Our ability to avoid foreclosure, however, will depend upon our ability to satisfy amounts owed to Bakersfield pursuant to the judgment or any settlement we are able to negotiate with Bakersfield.
Raser is not subject of any other legal proceedings and we are unaware of any proceedings presently contemplated against Raser by any federal, state or local government agency.
ITEM 4.
ITEM 4. (Removed and Reserved)
PART II
ITEM 5.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information.
Our common stock is listed on the NYSE exchange under the trading symbol of “RZ.”
Below are the high and low closing sales prices for Raser common stock for each quarter of 2009 and 2008. Closing prices were obtained from the ArcaEx®, now “NYSE Arca.” and, since December 22, 2008 from NYSE.
On March 16, 2010, the closing price for Raser common stock was $1.01 per share.
Holders.
As of December 31, 2009 there were approximately 315 holders of record of our common stock. This does not include an indeterminate number of stockholders who may hold their shares through a broker-dealer in “street name.”
Dividends.
We are required to pay a quarterly dividend to the holders of our Preferred Stock, payable in cash or shares of common stock equal to an annual rate of LIBOR plus eight percent (8%), but in no event higher than 14%, subject to adjustment. We are limited in dividend payments that we can make to our common stockholders unless such dividend payment is made equally to the holders of the Preferred Stock as if such holders had converted or redeemed (whichever is greater) their Preferred Stock for shares of our common stock immediately prior to the payment of such dividend. We have never declared or paid any cash dividends with respect to our common stock. We currently anticipate that we will retain all future earnings for the operation and expansion of our business and do not intend to declare dividends with respect to our common stock in the foreseeable future.
Securities Authorized for Issuance under Equity Compensation Plans.
The following table sets forth the number of shares of our common stock underlying outstanding options and warrants that have been issued under our equity compensation plans as of December 31, 2009:
In March 2004, our Board of Directors adopted the Raser Technologies, Inc. Amended and Restated 2004 Long-Term Incentive Plan (the “Plan”), and in May 2004, our board recommended and our stockholders approved the Plan. The Plan was adopted to facilitate (1) grants of a wider range of stock incentive awards, including restricted stock, stock appreciation rights, performance shares and performance units, (2) an automatic annual increase to the number of shares of common stock reserved for issuance under the Plan beginning in 2005 equal to the lesser of 1,750,000 shares of common stock, 3% of the outstanding shares of common stock on the first day of each fiscal year, or an amount determined by the Board of Directors, and (3) optional automatic, nondiscretionary annual stock option grants for employees and non-employee directors. As of December 31, 2009, we were authorized to issue up to 9,693,173 shares of common stock pursuant to the Plan.
The performance graph represents our cumulative total stockholder returns through December 31, 2009, as compared to the Standard and Poor’s Small Cap 600 Index, and the Standard and Poor’s Industrial Index.
ITEM 6.
ITEM 6. Selected Financial Data.
The following table sets forth our selected consolidated financial data for the years ended December 31, 2009, 2008, 2007, 2006 and 2005. We have derived the selected consolidated financial data related to the statements of operations for the years ended and as of December 31, 2009, 2008 and 2007 from our audited consolidated financial statements set forth in Part II Item 8 of this annual report. We have derived the selected consolidated financial data related to the balance sheets for the years ended December 31, 2007, 2006 and 2005 from our audited consolidated financial statements not included herein.
The information set forth below should be read in conjunction with Part II Item 7
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following management’s discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. This discussion contains forward-looking statements based on current expectations that involve risks and uncertainties, such as our plans, objectives, expectations and intentions, as set forth in Part I of this report under “Special Note Regarding Forward-Looking Statements.” Our actual results and the timing of events could differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth in Part I Item 1A and elsewhere in this report. The historical results set forth in this discussion and analysis are not necessarily indicative of trends with respect to any actual or projected financial performance.
Overview
We are an environmental energy technology company focused on geothermal power development and technology licensing. We operate two business segments: Power Systems and Transportation & Industrial. Our Power Systems segment develops clean, renewable geothermal electric power plants and anticipates also developing bottom-cycling operations in the future. Our Transportation & Industrial segment focuses on using our Symetron™ family of technologies to improve the efficiency of electric motors, generators and power electronic drives used in electric and hybrid electric vehicle propulsion systems. Through these two business segments, we are employing a strategy to produce a positive impact on the environment and economically beneficial results for our stockholders. By executing our strategy, we aim to become both a producer of clean, geothermal electric power as well as a provider of electric and hybrid-electric vehicle technologies and products.
Sources of Revenue
Currently, our primary source of revenue is from the sale of electricity generated by our Thermo No. 1 plant to the City of Anaheim. Revenue related to the sale of electricity is recorded based upon output delivered at rates specified under relevant contract terms in the period when the electricity is delivered. The Thermo No. 1 plant began generating and transmitting nominal quantities of “test” electricity in December 2008. However, since the “test” electricity generated was insignificant and not sold under a power purchase agreement, no revenue was recognized prior to April 2009. In April 2009, we began selling electricity generated by the Thermo No. 1 plant to the City of Anaheim under our power purchase agreement with the City of Anaheim. During 2009, we sold approximately 25,200 MW hours of electricity to the City of Anaheim.
The Thermo No. 1 plant is currently generating about 7 MW of gross electrical power. After deducting the plant parasitic load to power the plant, the net power sold by the Thermo No. 1 plant to the City of Anaheim is approximately 6 MW. Both the gross output and the net output of the plant are below the amounts the plant was designed to produce. We are working to improve the electrical output of the plant. However, even if we are able to operate the Thermo No. 1 plant at or near full capacity, the current and expected revenues from the Thermo No. 1 plant are not expected to have a material effect on our liquidity or our needs for additional financing of future projects.
Our Transportation & Industrial segment is seeking to generate revenues by licensing our Symetron™ technologies to third parties. In the past, our Transportation & Industrial segment has generated a small amount of revenues from research and development subcontracts, as well as the development of a small number of PHEV demonstration vehicles. During 2010, our Transportation & Industrial segment plans to continue to focus primarily on commercializing the applications contemplated by our agreements with FEV Inc. and HHI. However, the recent economic downturn has had a dramatic adverse effect on the automotive industry and other large industrial manufacturers that would be in a position to use and benefit from our technologies. As a result, we believe our ability to commercialize our Symetron™ technologies will be limited until economic conditions improve, and we do not expect to generate significant revenues from this business segment for the foreseeable future. In the interim, we have taken steps to reduce the resources committed to new developmental efforts. We
intend to evaluate the prospects for our Transportation & Industrial segment on an ongoing basis. If we believe there are attractive opportunities, we will devote the resources to pursue those opportunities to the extent we believe appropriate. If, on the other hand, we determine that the risks and uncertainties for this business segment are too great in light of the current economic climate, we may choose to further reduce the resources devoted to these efforts.
Although progress is being made by each of our business segments, significant revenues may not be generated as expected by either of our segments, if at all.
Significant Expenses
We have incurred significant losses since our inception. As of December 31, 2009, we had incurred an accumulated deficit of approximately $109.7 million on cumulative revenues since inception of approximately $3.3 million. Our net loss applicable to common stockholders for the years ended December 31, 2009, 2008 and 2007 totaled $20.2 million, $45.5 million, and $15.7 million, respectively.
During the twelve months ended December 31, 2009 our average recurring monthly cash expenditure rate for operations decreased to $1.4 million per month from approximately $1.7 million per month for the twelve months ended December 31, 2008. The decrease was due largely to lower professional services fees and reduced staff levels in our Transportation & Industrial business segment. We expect that our average monthly cash expenditure rate will increase again in the future as we implement our plans to develop additional geothermal power plants.
For the year ended December 31, 2009, our operating expenses consisted primarily of cost of revenue, general and administrative expenses, power project development expenses and research and development expenses. Cost of revenue for each of the periods presented includes direct costs attributable to our operating geothermal power plant including operation and maintenance expenses such as depreciation and amortization, salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and certain transmission charges. Payments made to government agencies and private entities on account of site leases where plants are located are also included in cost of revenue. Royalty payments, included in cost of revenue, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenue derived from the associated geothermal rights. Cost of revenue prior to 2009 included the direct labor, materials and overhead expenses required to perform work on research and development subcontracts, which are now complete.
General and administrative expenses for all periods presented include expenses related to our marketing, sales, accounting, legal, investor relations, human resources and other administrative functions. General and administrative expenses also include non-cash equity-based compensation paid to employees, consultants and service providers. We have made significant use of non-cash equity-based compensation to conserve cash and provide incentives to our employees. We expect to continue to use equity-based compensation to provide incentives to our employees and certain service providers.
Power project development expenses for the years ended December 31, 2009 and 2008 primarily include professional services for mapping, environmental and geological studies and other prospecting costs related to the exploration for geothermal resources. Power project development expenses also include certain legal costs to design the project debt and tax equity financing structure and other operating agreements as well as certain consulting costs relating to project oversight. We expect that our power project development expenses will increase in future periods as we pursue the development of additional power projects and continue to explore for geothermal resources.
Critical Accounting Policies and Estimates
Certain of our accounting policies are particularly important to the understanding of our financial position and results of operations. The application of these policies requires management to use significant judgment to determine the appropriate assumptions to be used in making certain estimates about the effects of matters that are inherently uncertain when reporting financial results. Such estimates are based upon management’s historical experience, the terms of existing contracts, management’s observance of trends in the transportation, industrial and power production industries, information provided by our customers and information available to management from other outside sources, as appropriate. Such policies and estimation procedures have been reviewed with our Audit Committee. We describe specific risks related to these critical accounting policies below. In addition, our significant accounting policies are more fully described in Note 1 of our audited consolidated financial statements set forth in Part II item 8 of this annual report.
Regarding all of our accounting policies, we caution that future results rarely develop exactly as forecasted, and the best estimates routinely require adjustment. Our critical accounting policies include the following:
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Accounting for geothermal activities
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Capitalization of costs
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Derivative financial instruments
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Revenue recognition
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Investments
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Allowance for uncollectible accounts
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Impairment of long-lived assets (tangible and intangible)
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Asset retirement obligations
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Valuation allowance against deferred income taxes
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Equity based compensation
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Business consolidations
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Fair value measurements
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Deferred finance costs
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U.S. Department of Treasury Grant under Section 1603 of the Recovery Act
Accounting for Geothermal Energy Activities
Each geothermal power project we develop consists of three phases. During the first phase, the site is identified and evaluated. During the second phase, the power plant, transmission lines and pipelines are constructed and the production and reinjection wells are drilled. The third and final phase is the production phase, during which the power plant is operated over its useful life.
Site Identification and Evaluation Phase. The first step in the site identification and evaluation phase is the identification of potential project sites. As part of the identification process, we incur a variety of costs, which may include costs for topographical studies, geological and geophysical studies, rights to access and study properties, technical materials and maps. Regardless of whether we pursue a project at a particular site, all of the costs associated with the identification of a potential site are considered exploratory in nature and are expensed as incurred.
The next step in the site identification and evaluation phase is land acquisition, pursuant to which we acquire land, lease land, or otherwise obtain the appropriate property interests to develop a potential project.
Lease acquisition costs, including lease bonuses, legal costs, permit costs, and the fair value of other forms of compensation to acquire leases are capitalized as power project leases when incurred. The power project leases are not amortized until the related power plant constructed on the leased property is placed in service. At that time, the related power project leases are capitalized as geothermal property plant and equipment and amortized over the estimated useful life of the geothermal power plant. From time to time, we also purchase land outright to develop. Any land we purchase outright is not amortized and is stated in our financial statements at historical cost.
Once we have acquired an interest in a geothermal property, we also incur costs to carry and maintain the undeveloped property until we are in a position to determine whether or not to pursue a project on the property. These costs can include delay rentals, certain taxes on the properties, legal costs for title defense, and the maintenance of land and lease records. All of these costs are expensed when incurred.
After, or occasionally prior to, the time we acquire an interest in a property, we conduct additional internal and external studies to determine whether to initiate the development of a project at the site. As part of this process, we may drill slim holes or conduct other activities to help identify the general location and characteristics of the potential geothermal resource. All of these costs, including slim holes, are considered exploratory in nature and are expensed as incurred.
Construction Phase. We only decide to pursue a project at a site if we determine, with a high degree of confidence, that; (i) the site contains an adequate renewable geothermal resource to support a power plant that will continually produce electricity without any substantial degradation of the heat resource; and (ii) we can effectively transmit and sell the electricity generated at a facility. Once we have made this determination for a site, the project begins the second development phase, which consists of drilling production and reinjection wells, as well as constructing the power plant, transmission lines and pipelines from the well field to the power generating units.
Before drilling and construction can begin, we must obtain the appropriate permits. Permitting costs are capitalized as part of the project costs. We capitalize permitting costs and record them as either well field development-in-progress or construction-in-progress.
After obtaining appropriate permits, we begin to develop the well field for the project by drilling large diameter production holes. In general, these holes are 20 to 22 inches in diameter at the surface and telescope down to between nine (9) and fourteen (14) inches, depending upon the depth of the well and other conditions. Each hole we drill will result in either a production well, a reinjection well, or an unsuccessful well. Production wells and reinjection wells will ultimately be used in the production of electricity at the geothermal power plant. Therefore, drilling costs for production wells and reinjection wells are capitalized. Drilling costs associated with unsuccessful wells are expensed in the period in which we determine they cannot be used in the production of electricity. Capitalized costs associated with well field development-in-progress are reclassified as geothermal property, plant and equipment once the plant is placed in service and amortized over the estimated useful life of the plant, or 35 years.
Construction of the geothermal power plant, the related transmission lines and the required substation normally occur either concurrent with or subsequent to the drilling of the production and reinjection wells. The costs associated with construction of the power plant and related transmission lines are accumulated and capitalized over the construction period. We begin to depreciate the construction related costs over the estimated useful life of the plant once the power plant is placed in service. The estimated useful life of our power plants is estimated to be 35 years.
As part of the financing for a project, we incur costs to obtain a report from an independent engineer verifying the production capacity of the well field. The costs associated with the engineer’s report are expensed as consulting costs and other financing-related costs, such as legal costs, broker fees, and accounting fees are capitalized when incurred.
Although we placed the Thermo No. 1 plant in service in the first quarter of 2009, we have experienced certain difficulties in ramping up the production of electricity at the Thermo No. 1 plant to full capacity. In light of these difficulties, we have drilled additional new wells and performed certain recompletion work to stimulate and improve the existing wells to increase the output of electrical production at the power plant since we placed the power plant into service. The costs associated with the additional drilling and recompletion work are also capitalized as betterments that increase production and the useful life of the wells as incurred. These costs are amortized over the estimated useful life of our power plants or 35 years. We have made significant judgments with respect to the capitalization of drilling costs. Our financial results could differ if we had made different judgments relating to the capitalization of drilling costs or if management’s judgments prove to be incorrect.
Certain tax incentives are available to us through these renewable energy projects. Some of these tax incentives, such as the Internal Revenue Code Section 45 production tax credit, have “placed in service” deadlines in order to qualify for such incentives. We have incurred and may incur in the future, significant additional costs during this phase in order to meet the placed in service deadline. In 2008, the deadline for use of the production tax credit relating to geothermal power plants was extended to December 31, 2013, subject to future extensions. Also refer to discussion of the U.S. Department of Treasury grant under Section 1603 of the Recovery Act below.
Production Phase. The final phase of a project is the energy production phase. The energy production phase begins when the plant begins selling electricity to a third party in accordance with a power purchase agreement. Operating costs incurred during the energy production phase are expensed as incurred. Prepaid commissions, if any, pursuant to power purchase agreements relating to the project are amortized over the life of agreements. In April 2009, we began selling electricity produced at the Thermo No. 1 plant to the City of Anaheim. Accordingly, we also began amortizing prepaid commissions over the life of the power purchase agreements.
Capitalization of Costs
Our determination to move forward with the process to construct the power plant, transmission lines, production wells and pipelines for a geothermal power project is based on management’s determination, with a high degree of confidence, that a given site contains adequate renewable geothermal resources to support a plant that will continually produce electricity without any substantial degradation of the heat resource. This determination involves significant management judgment and is based on the information available at the time. Once this determination has been made, we begin to capitalize certain construction-related costs. Although management’s determination to proceed with construction activities and capitalize construction-related costs is based on a high degree of confidence that a sufficient geothermal resource exists, the information available and the uncertainties associated with potential geothermal resources could later prove our management’s judgments to be incorrect. If management’s judgments with respect to a project prove to be incorrect, we may have to write-off significant costs associated with that project that were previously capitalized, which could have a material adverse effect on our results of operations.
With respect to the power generating units at our Thermo No. 1 plant, we expect to incur maintenance costs each five years to maintain the optimal operating efficiency of the power plant. Under current accounting guidance, we may elect to either capitalize the planned major maintenance costs and amortize the costs over the five year period or expense the costs when incurred. We estimate that the actual planned major maintenance costs may range between $3.0 million and $4.0 million at each planned maintenance event. Since the PureCycle units are based upon a new technology, there is no historical basis to estimate what the actual costs will be. Therefore, we have elected to recognize the planned major maintenance costs when incurred which will have the effect of increasing the operating costs in those years that the planned major maintenance costs are incurred.
Derivative Financial Instruments
During the normal course of business, from time to time, we issue warrants and options to vendors as consideration to perform services or settle outstanding debt. We may also issue warrants as part of a debt or equity placement offering. We do not enter into any derivative contracts for speculative purposes.
Warrants that contain round down or price reset features are subject to classification as liabilities for financial statement purposes. Beginning in 2009, as required by the Derivatives and Hedging Topic of the FASB Accounting Standards Codification, we began accounting for our warrants with exercise price reset features as liabilities. These liabilities are measured at fair value with the changes in fair value at the end of each period reflected as current period income or loss unless the derivatives qualify as hedges of future cash flows and are accounted for as such. We utilize the Black-Scholes option pricing model or a Binomial pricing model to compute the fair value of the liabilities associated with the outstanding warrants, depending upon the complexity of their contractual terms. In computing the fair value of the warrants liabilities at the end of each period, we use significant judgments with respect to the risk free interest rate, the volatility of our stock prices, and estimated life of the warrants. The effects of these judgments, if proven incorrect, could have a significant negative impact to our financial statements. For further discussion, refer to Note 17. “Warrants” and Note 19. “Fair Value Measurements.”
Revenue Recognition
Revenue is recognized when earned in accordance with applicable accounting standards and guidance, including Staff Accounting Bulletin or SAB, No. 104, Revenue Recognition, as amended.
Revenue generated through our Power Systems segment is expected to be primarily through the sale of electricity in accordance with power purchase agreements we intend to execute with investor owned utilities and municipalities. In April 2009, we began generating and selling electricity from out Thermo No. 1 plant to the City of Anaheim. Pursuant to our power purchase agreement with the City of Anaheim, we are required to deliver electricity and the related renewable energy credits produced by our Thermo No. 1 power plant. While the electricity is delivered daily, the renewable energy credits are due monthly. Revenue related to the sale of electricity and delivery of the renewable energy credits are recorded based upon electricity output delivered at rates specified under relevant contract terms in accordance with our power purchase agreement. In the State of California, the renewable energy credits cannot be sold separately from the electricity and must be sold under an executed power purchase agreement. In addition, the City of Anaheim has no right of return under the power purchase agreement. Accordingly, the renewable energy credits are not considered to be a separate unit of accounting from the electricity; therefore, we recognize revenue upon delivery of the electricity. During the year ended, December 31, 2009, we sold approximately 25,200 MW of electricity to the City of Anaheim and recognized revenue totaling $2.2 million. Prior to April 2009, we began generating and transmitting nominal quantities of “test” electricity at our Thermo No. 1 plant, however we recognized no revenue from the production of this “test” electricity. The power purchase agreement with the City of Anaheim is exempt from derivative treatment due to the normal sales contract exception. Management has made judgments with respect to the classification of the power purchase agreement with the City of Anaheim as a normal sales contract. The effect of these judgments, if incorrect, could have a negative impact on the revenue recognized in our financial statements.
Pursuant to the Thermo financing agreements’ we agreed to serve as the engineering, procurement and construction contractor (“EPC contractor”) for the Thermo No. 1 plant and guaranteed the completion of the construction of the Thermo No. 1 plant. Accordingly, as EPC contractor, we received intercompany revenues from our Thermo Subsidiary for the completion of certain construction related milestones. In addition, we agreed to serve as the Operations and Management manager (“O&M manager”) for the Thermo No. 1 plant and we expect to receive quarterly fees for the services we perform. We also expect to receive fees from our Thermo Subsidiary relating to achieving substantial completion of the Thermo No. 1 plant and for providing general administrative services. However, since the Thermo Subsidiary is a consolidated entity, these intercompany revenues and fees are eliminated in consolidation.
Revenue from our Transportation & Industrial segment is generated, or expected to be generated, from (1) the sale of prototypes of our motors or PHEV demonstration vehicles to private companies for testing and simulation and (2) fees and royalties generated by the sales of products and solutions of our licensed manufacturing partners. Revenue from subcontracted engineering services is recognized under the percentage of completion method. Costs incurred to achieve the performance criteria are deferred and recognized concurrent
with the recognition of revenue unless they are determined to be unrecoverable. For contracts in which the fee is estimated to equal 100% of the cost to complete the contract, we recognize revenue as the cost is incurred to complete the project using zero as our estimate of profit under the percentage-of-completion method. If estimated costs exceed projected revenues for a reporting period, we recognize a loss on the contract. Under the percentage of completion method, changes in the estimated time and cost to complete the contract may affect the time period over which the unrecognized revenues and related costs are recognized.
The revenue from the sale of prototypes is recognized when the prototype is delivered to the customer. We accepted an initial deposit of $200,000 for production of two extended range PHEVs. The initial deposit was recorded as unearned revenue until the vehicles are delivered. If we accept deposits for vehicles we are ultimately unable to deliver, the deposit is returned.
Investments
We classify investment securities as either available-for-sale or held-to-maturity. Available-for-sale securities and are recorded at fair market value, based on quoted market prices, and unrealized gains and losses are recorded as a component of comprehensive income (loss). Realized gains and losses, which are calculated based on the specific-identification method, are recorded in operations as incurred. We did not have short-term investments classified as available-for-sale during the years ended December 31, 2009 and 2008, respectively. Accordingly, there was no unrealized gain or loss relating to available-for-sale short-term investments recorded for the year ended December 31, 2009 or 2008, respectively.
Held-to-maturity securities include U.S. Government Strips that have coupon dates and coupon amounts that correspond with the amount of interest payable for first four semi-annual interest payments to the holders of our Convertible Notes. The held-to-maturity securities are carried and amortized at cost.
Available-for-sale and held-to-maturity securities are assessed for impairment periodically. To determine if the impairment is other-than-temporary, we consider the duration and severity of the loss position, the strength of the underlying collateral, the term to maturity, and credit rating. For investments that are deemed other-than-temporarily impaired, losses are recorded and payments received on these investments are recorded using the cost recovery method. All of our current investments in securities consist of held-to-maturity securities backed by the United States government. As a result, we do not believe there was any impairment of our investments in held-to maturity securities during 2009 or 2008, respectively. In determining whether there was any impairment of available-for-sale and held-to-maturity securities, we must make judgments relating to the classification of our investments as either available-for-sale or held-to-maturity. If these judgments prove to be incorrect, it could have an adverse effect on our results of operations and financial position.
Allowance for Uncollectible Accounts
Contractual rights to future payments associated with trade accounts receivable and notes receivable are evaluated to determine the likelihood of collecting amounts due. The evaluation includes a review of available financial information related to the debtors’ ability to pay, historical payment pattern, security positions, government regulations, most recent communications and an assessment of current economic conditions in determining the net realizable value of our receivables. We also review our allowance for uncollectible accounts in aggregate for adequacy following this assessment. Changes in the customer’s economic environment could reduce our ability to fully collect the receivable. Currently, our only significant customer is the City of Anaheim. Based upon our review of the City of Anaheim’s ability to pay, historical payment pattern and the current economic conditions, we believe that no allowance is necessary relating to the collection of revenue from the City of Anaheim as of December 31, 2009. In determining our allowance for doubtful accounts, we made certain judgments with respect to the collectability of our outstanding accounts receivables. If these judgments prove to be incorrect, it could have an adverse effect on our results of operations and financial position.
Impairment of long-lived assets (tangible and intangible)
Administrative equipment is recorded at cost and depreciated on a straight-line basis over estimated useful lives of the assets, ranging from three to seven years. Leasehold improvements are recorded at cost and depreciated over the remaining life of the lease.
Costs of internally developing, maintaining or restoring patents and trademarks that are specifically identifiable and have determinate lives are capitalized. The costs of patents are amortized on a straight-line basis over the estimated useful life or 20 years from the date of the first filing. The costs of trademarks are capitalized but not amortized because their useful lives are considered indefinite. Costs incurred to acquire our global heat transfer technology license have been capitalized and amortized on a straight-line basis over the estimated useful life of the related patents underlying and accompanying the license, or 11.5 years.
We assess recoverability of our patents and trademarks by determining whether the amortization of the balance over its remaining life can be recovered through undiscounted future operating cash flows. The amount of impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate which reflects our average cost of funds. Abandoned patents and trademarks are expensed in the period abandoned.
We periodically review our long-lived assets, including our well field drilling costs, geothermal power plant and transmission line construction costs, equipment and certain intangible assets for impairment when events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We evaluate, at each balance sheet date, whether events and circumstances have occurred that indicate possible impairment.
The carrying value of other long-lived assets such as the well field drilling costs, geothermal power plant, transmission line construction costs, equipment and certain intangible assets is considered impaired in accordance with applicable accounting guidance when the anticipated cumulative undiscounted cash flows of the related asset or group of assets is less than the carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the estimated fair value of the long-lived asset using a discount rate which reflects our average cost of funds. In connection with performing the impairment analysis, we reduced the cost basis of our Thermo No. 1 plant at December 31, 2009 by the amount of the U.S. Treasury grant we received as reimbursement of the qualified costs incurred to construct the plant on February 19, 2010 totaling $33.0 million. We also exercised significant judgments including the assumption that our geothermal power plant will produce electricity over 35 years, a power purchase agreement will be renewed after its expiration at or near the then current terms of our current power purchase agreement, the maintenance costs associated with keeping the power generating units in operating condition after expiration of our current maintenance agreement in 10 years will be adjusted downward to reflect our expected internal costs and escalated at the current contracted rates of the current maintenance agreement over the estimated useful life of the plant over 35 years.
In accordance with accounting guidance, we evaluated our long-lived assets for impairment as of December 31, 2009 and determined that none of our long-lived assets analyzed in 2009 have been impaired. However, management has exercised significant judgments with respect to our assumptions included in our impairment analysis. If these judgments prove to be incorrect and result in an impairment of our long-lived assets, it could have a material negative impact on our results of operations and financial position.
For further discussion of the impairment of our well costs, refer to Note 5, “Geothermal Property, Plant and Equipment”. We also determined in the fourth quarter of 2009 that, under current accounting guidance, none of our current additional wells at our Thermo No. 1 plant should be expensed as non-commercial wells at this time. We will continue to monitor the production levels of our well for future impairment.
Asset Retirement Obligations
We have incurred certain liabilities related to the retirement of assets in connection with drilling wells and constructing the Thermo No. 1 plant. These liabilities include our obligations to plug wells upon termination of
our operating activities, dismantle geothermal power plants upon cessation of operations and perform 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 power project lease. Such liability is accreted to its future value each period, and the capitalized cost is amortized over the useful life of the related geothermal power plant or 35 years. As of December 31, 2009, the present value of our asset retirement obligations totals $2.7 million. At retirement, we will either settle the obligation for its recorded amount or incur a gain or a loss with respect thereto, as applicable. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, estimated inflation rates, retirement costs and the estimated timing of settling asset retirement obligations.
Valuation Allowance Against Deferred Income Taxes
Deferred income tax assets and liabilities are recorded when there is a difference between the financial reporting and tax treatment of financial transactions. We recorded a valuation allowance to offset the entire net deferred tax asset as of December 31, 2009, 2008 and 2007, respectively. The valuation allowance was recorded due to the losses incurred and the uncertainties regarding the future taxable income and recoverability of such deferred tax assets. We continually evaluate the estimated recoverability of deferred tax assets.
Equity Based Compensation
From time to time, we issue stock and option awards to employees as compensation for their employment. We record equity based compensation for employees at the fair value of the stock or option award on the grant date. The fair value is recognized over the requisite service period of the employee. Compensation expense is adjusted for equity awards that do not vest due to the fact that service or performance conditions are not satisfied. However, compensation expense already recognized is not adjusted if market conditions are not met, such as when stock options expire “out-of-the-money,” or when options expire unexercised.
For performance-based equity compensation, management assesses the likelihood that the event will successfully occur and computes the fair value of the instrument at each quarterly balance sheet date. When the performance is assessed as “probable,” expense is recognized on a pro rata basis over the estimated service period. When the performance is assessed as less than “probable,” no expense is recognized.
From time to time, we issue shares of common stock, stock options to purchase shares of common stock, and warrants containing underlying shares of our common stock as payment for services or purchase of assets to certain service providers, contractors and other non-employees. We record equity compensation for stock, stock options or warrants issued for services based upon the fair value of the instruments on the earlier of the date of a performance commitment agreement or the date when performance is completed. Expense is recognized over the requisite service period of the stock award.
Stock issued for the purchase of assets or settlement of debt is also valued based on the fair value of the stock on the date the stock is issued or required to be issued per the purchase agreement, or the fair value of the assets acquired, whichever is more readily determinable. The assets purchased or the amount of debt settled are recorded based on the more readily determinable fair value of the stock issued or price of the assets acquired or amount of the debt settled. See Note 16. “Common Stock” for more information regarding our stock compensation plans.
Options and warrants granted to employees and contractors are valued by applying the fair value based method to stock-based compensation in each period utilizing the Black-Scholes option pricing model, a generally accepted valuation model for determining the fair value of options. The maximum term of each option is ten years. With respect to stock options granted and warrants issued during the years ended December 31, 2009, 2008 and 2007, we computed the fair value using the Black-Scholes option-pricing model.
In determining the fair value of stock issued for services, we must make judgments relating to pre-requisite service periods, estimated option lives, risk free rates, stock volatility, forfeiture rate and likelihood of completing an applicable performance conditions. If these judgments prove to be incorrect, it could have a material effect on our results of operations.
Business Consolidations
The consolidated financial statements include our accounts and the accounts of our consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made in the prior year’s consolidated financial statements to conform to the current year presentation.
We must undertake significant project financing to complete the geothermal power projects we intend to develop. We anticipate that will be able to finance our activities through financing of tax benefits by tax equity partners, joint ventures or other methods of equity financing. In August 2008, Merrill Lynch had obtained a noncontrolling interest in the Thermo Subsidiary, which it acquired as part of the original financing arrangements for the Thermo No. 1. plant. Effective December 11, 2009, Merrill Lynch withdrew from the Thermo Subsidiary resulting in Raser becoming the sole partner. Accordingly, we agreed to redeem Merrill Lynch’s equity interest in the Thermo No. 1 plant and entered into a note payable for up to $24.5 million, subject to certain conditions. On February 19, 2010, we received $33.0 million from a federal grant resulting in the principal balance of the note payable being reduced to $20.0 million, subject to certain conditions. As a result of Merrill Lynch’s withdrawal from the partnership, we recorded the difference between the December 11, 2009 noncontrolling interest of $29.2 million and the $20.0 million note payable as additional paid in capital totaling $9.2 million.
Whenever we enter into an arrangement with tax equity, joint venture or other equity partners, we evaluate the voting rights of the subsidiary and the noncontrolling holder’s substantive participative and protective rights. We also evaluate the conditions outlined in variable interest entity accounting guidance and determine whether that the financing arrangement should not be classified as a variable interest entity and that the subsidiary was properly consolidated for financial statement purposes. In determining whether our subsidiaries should be classified as consolidated entities or variable interest entities, we must make judgments about the voting and other rights contained subsidiary arrangements and whether the subsidiary is a variable interest and other conditions outlined in variable interest entity accounting guidance. If these judgments prove to be incorrect, it could result in the deconsolidation of our subsidiary and have a material impact on our results of operations and financial position.
As of December 31, 2009, based upon in the redemption of Merrill Lynch’s equity interest in the Thermo Subsidiary, we re-evaluated the conditions outlined in the variable interest entity accounting guidance and determined that the Thermo Subsidiary should not be classified as variable interest entity under the new financing arrangements and that the Thermo Subsidiary should continue to be consolidated for financial statement purposes. In August 2008, we evaluated the voting, participative and protective rights and the variable interest entity conditions and determined that the Thermo Subsidiary should be accounted for as a consolidated subsidiary.
Fair Value Measurement
Under the FASB Accounting Standards Codification, we are permitted to elect to measure financial instruments and certain other items at fair value, with the change in fair value recorded in earnings. We elected not to measure any eligible items using the fair value option. Consistent with Fair Value Measurement Topic of the FASB Accounting Standards Codification, we implemented guidelines relating to the disclosure of our methodology for periodic measurement of our assets and liabilities recorded at fair market value.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A three-tier fair value hierarchy
prioritizes the inputs used in measuring 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). These tiers include:
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Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets;
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Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable such as quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active; and
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Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions, such as valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.
Our Level 1 assets primarily include our cash and cash equivalents (including our money market accounts), accounts receivable, notes receivable, interest receivable, accounts payable and accrued liabilities due to the immediate or short-term maturities of these financial instruments. Valuations are obtained from readily available pricing sources for market transactions involving identical assets or liabilities. Our Level 2 assets include our restricted cash certificate of deposit. Valuations are generally obtained from third party pricing services for identical or comparable assets or liabilities (and validated through back testing to trade data or confirmation that the pricing service’s significant inputs are observable) or determined through use of valuation methodologies using observable market inputs such as market interest rates. Our Level 3 assets include the portion of our asset retirement that is included in our power project leases.
The carrying value and estimated fair value of our debt instruments at December 31, 2009 were as follows:
* Represents the face value of the debt without consideration of the deferred financing costs of $33,399 as of December 31, 2009.
** Represents the face value of the debt without consideration of the imputed interest rate of 15% from December 11, 2009 to June 30, 2010 resulting in a discount of $1,232,846 as of December 31, 2009.
*** Due to the original issue discount, cash proceeds of debt are less than the face value of the debt. Therefore, the effective interest rate of 9.5% is greater than the 7% stated rate. Represents face value of debt without consideration of the original issue discount of $4,469,479 as of December 31, 2009.
The estimated value of our short-term 10.00% amended unsecured line of credit, long term 15.00% promissory note, and long-term 9.50% senior secured note was determined by management who based its judgment relating to fair value on discounted cash flow analysis that were developed with the assistance of a third-party valuation consultant. Our cash flow model utilized the projected cash outflows and a discount rate, which was derived from market and non-market inputs. Our estimate of the value of our short-term 10.00% amended unsecured line of credit, long term 15.00% promissory note, and long-term 9.50% senior secured note secured note depends on judgments relating to the projected cash flows and discount rate. If these judgments prove to be incorrect, it could have a material effect on our results of operations and financial position.
To estimate the fair value of our long-term 8.00% convertible senior note, we used a third party pricing service that estimated the fair value based upon theoretical values based on assumptions that market participants would use to price the Convertible Notes.
Deferred Finance Costs
Deferred finance costs are recorded at cost and include costs relating to undertaking debt financing activities. Deferred finance costs are amortized over the life of the maturity of the respective debt and recorded as interest expense. Original issue discounts are recorded as reductions to the related long-term debt for financial statement purposes and accreted up to the face value of the respective debt instrument over the life of the maturity of the respective debt and recorded as interest expense. Costs associated with equity financings are recorded as a reduction of additional paid in capital. If related financing is not successfully completed, these costs will be expensed in the period when the related financing is determined to be unsuccessful. At December 31, 2009, our deferred finance costs totaled $6.9 million. The acceleration of debt terms or extinguishment of debt related to these financing fees would result in accelerating the recognition of interest expense in the period in which the event occurred.
U.S. Department of Treasury Grant under Section 1603 of the Recovery Act
Pursuant to the Recovery Act, an owner of a qualified geothermal power plant may elect to receive a grant from the U.S. Treasury Department of up to 30% of certain qualifying construction and drilling costs in lieu of claiming either ITCs or the PTC. The amount of the grant for a qualified geothermal power plant is up to 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the later of the date of the application for the grant is deemed complete or the date the project is placed in service.
On December 8, 2009, we submitted our application for a U.S. Department of Treasury grant under Section 1603 of the Recovery Act (the “Grant”) totaling approximately $33.0 million. On February 19, 2010, we received the Grant totaling $33.0 million.
We elected to reduce the cost basis of our Thermo No. 1 plant by the amount of the grant we received from the U.S. Department of Treasury Grants under Section 1603 of the Recovery Act on the date the Grant was deemed complete by the U.S. Department of Treasury. By electing to reduce the cost basis, the depreciation expense going forward will also be reduced by approximately, $0.8 million per year. An alternative method would be to record the amount received from the grant as a deferred credit and amortize it over the useful life of the Thermo No. 1 plant on a straight-line basis. We elected to reduce the cost basis of our Thermo No. 1 plant because this approach more accurately reflects the reimbursement nature of the grant. Had we elected to amortize a deferred credit over the estimated life of the plant instead of reducing the cost basis of the Thermo No. 1 plant and decreasing the amount of depreciation, the net effect to net income or loss would be zero.
Results of Operations
The following table sets forth our results of operations for the years ended December 31, 2009, 2008 and 2007:
Comparison of Years Ended December 31, 2009 and 2008
Revenue
During the year ended December 31, 2009, we recognized revenue totaling $2.2 million. Revenue increased $2.0 million from the year ended December 31, 2008. During the second quarter of 2009, we began selling electricity generated by our Thermo No. 1 plant to the City of Anaheim. During the year ended December 31, 2009, we generated and sold approximately 25,200 MW hours of electricity, resulting in revenue totaling $2.2 million. Revenue for 2008 reflects payments we received pursuant to a research and development subcontract with ARINC, which we completed in the first quarter of 2008. We accounted for this subcontract on a percentage of completion basis.
Cost of revenue
We reported cost of sales for the years ended December 31, 2009 and 2008 totaling $6.5 million and $0.1 million, respectively. The increase in cost of sales was primarily due to sales of electricity from the Thermo
No. 1 plant during the year ended December 31, 2009. Cost of revenue includes depreciation expense totaling $2.3 million, parasitic load costs totaling $1.0 million, our initial property tax assessment for 2009 totaling $0.8 million, consulting and insurance costs totaling $0.7 million, maintenance costs for the Thermo No. 1 power generating units totaling $0.7 million, chemicals and lubricants totaling $0.2 million, and payroll related costs of $0.4 million. Although the gross margin was negative for the year ended December 31, 2009, we expect the revenue from the Thermo No. 1 plant to exceed the cost of revenue in the future as a result of our efforts to improve electric output at Thermo No. 1 and an expected decline in certain consulting expenses and parasitic load costs associated with the plant. Cost of revenue for the year ended December 31, 2008 primarily resulted from costs associated with completing the ARINC subcontract objectives during the first quarter of 2008.
Operating expenses
General and Administrative. General and administrative expenses increased by approximately $0.4 million from $9.8 million to $10.2 million for the years ended December 31, 2008 and 2009, respectively. Equity-based non-cash employee compensation expense, increased by $0.3 million to $2.5 million for the twelve months ended December 31, 2009, primarily as a result of two directors electing to participate in the new director compensation plan. As a result, the directors forfeited a cumulative total of 65,000 unvested options and were awarded a cumulative total of 52,000 shares that had an incremental and overall fair value of $0.5 million on the date of grant. Equity-based non-cash service provider compensation for the year ended December 31, 2009 decreased by approximately $0.1 million from the prior year primarily due to fewer grants of options to service providers. Professional services decreased by approximately $0.5 million during the year ended December 31, 2009 as compared to 2008. The higher professional fees during 2008 consisted primarily of professional services associated with the overall tax equity financing structure for the Thermo No. 1 financing arrangements. Employment related costs remained relatively flat at $2.9 million during the year ended December 31, 2009 compared to 2008, reflecting minimal administrative employee turnover. Office expenses increased by $0.7 million for the year ended December 31, 2009 as compared to 2008. The increase was primarily due to $0.2 million of additional office related expenses associated with corporate expansion during 2009, additional NYSE stock exchange listing fees of $0.2 million and increased Delaware franchise taxes of $0.3 million. The increase in stock exchange listing fees and Delaware franchise taxes was due primarily to an increase in the number of shares of common stock issued and outstanding during 2009.
Power Project Developments. Power project development expenses during the year ended December 31, 2009 totaled $9.1 million, compared to $10.4 million for the year ended December 31, 2008. Equity-based non-cash employee and contractor compensation for the year ended December 31, 2009 remained relatively flat at $0.8 million as compared to the year ended December 31, 2008 as a result of maintaining relatively the same levels of stock option awards to employees during both 2009 and 2008. Employment related costs for power project development employees increased during the year ended December 31, 2009 by $0.4 million over 2008 as we increased our work force levels to execute our business plan. During 2009, professional services decreased by $4.7 million from 2008. The higher professional fees during 2008 consisted primarily of professional services associated with the overall tax equity financing structure for the Thermo No. 1 financing arrangements and geological engineering consulting fees associated with the development of the Thermo No. 1 plant. Property related expenses such as delay rentals, completed transmission line capacity studies and insurance increased during the year ended December 31, 2009 over the same prior year period by approximately $0.1 million due to delay rentals on the anniversary date of each of the geothermal leases we acquired during 2008. We also incurred $0.8 million of costs related to testing and sealing off upper production zones in two wells that were previously expensed and are currently used for monitoring and testing the well field during the year ended December 31, 2009. These expenses were not incurred during 2008. In addition, office expenses increased by approximately $1.6 million during the year ended December 31, 2009 as compared to 2008. This increase in office expenses was primarily due to a cancellation fee relating to an April 2009 deposit refund from PWPS totaling $1.5 million.
Unsuccessful and Impaired Wells. Unsuccessful and impaired wells expense decreased $13.6 million during the year ended December 31, 2009 from 2008. The decrease was primarily due to higher expense amounts in
2008, including $10.6 million related to expensing two wells at the Thermo No. 1 plant and $3.0 million related to expensing of one well at the Truckee project. As a result of evaluating the combined production capacity of the Thermo No. 1 plant and the combined electricity producing capacity of the production wells, in accordance with our policy, we identified two completed production-sized wells that are unlikely to be used for the production of electricity. The determination that the Truckee well was impaired was based primarily on the difficult financing environment and our decision to focus on the development of other projects. As a result of these factors, we determined the future undiscounted cash flows from the Truckee were uncertain. Management believes that the Truckee well could still be used in the production of electricity as either a production or re-injection well in the future, should we decide to resume active development of the Truckee project. Based upon our internal impairment analysis of our current wells, we concluded that, as of December 31, 2009, none of our remaining wells should be expensed.
Research and Development. Research and Development expense decreased from $4.8 million in the year ended December 31, 2008 to $1.9 million for the year ended December 31, 2009. Equity based non-cash employee compensation for the year ended December 31, 2009 remained relatively flat at $0.6 million. This was due primarily to offsetting factors relating to decreasing headcount from the prior year while issuing stock grants to employees as part of their severance agreements during the current year as a result our decision to reduce the cash requirements at our design center. Cash based employee compensation during the twelve months ended December 31, 2009 decreased by approximately $0.8 million compared to the year ended December 31, 2008, reflecting a reduction in the number of employees performing research and development activities. Professional services decreased by approximately $1.5 million during the year ended December 31, 2009 over the same period of 2008. This increase was primarily to the substantial completion of the consulting work relating to the PHEV early in 2009. The portion of engineering expenses that could be attributed to cost of sales decreased approximately $0.6 million during the twelve months ended December 31, 2009 from the comparable 2008 period due primarily to the decreased materials consumed in testing our PHEV prototype.
Interest and Other Income. Interest income for the year ended December 31, 2009 decreased to $0.1 million from $0.4 million for the same period in 2008. The decrease was due primarily to lower average monthly cash balances and decreased interest rates due to the overall economic conditions during the twelve months ended December 31, 2009 compared to the 2008 period. Interest expense for the year ended December 31, 2009 increased $8.2 million from the same period in 2008. This increase is primarily due to placing the Thermo No. 1 plant into service during the first quarter of 2009. Once the plant was placed in service, we could no longer capitalize interest expense associated with the financing for the construction of the plant. Gain on derivatives increased $15.0 million during the year ended December 31, 2009 compared to year ended December 31, 2008 due primarily to the decrease in the fair value of outstanding warrants that contain anti-dilutive features. We incurred a loss on the extinguishment of debt during the year ended December 31, 2009 primarily due to issuing warrants associated with the October 2009 registered direct stock offering to the participants in our unsecured Line of Credit (“LOC”). In addition to selling 3.2 million shares of our common stock to the participants in the LOC, we also issued warrants to acquire 1.6 million shares of our common stock at a strike price of $1.61 per share. The fair value of the warrants issued in connection with the October 2009 registered direct offering resulting in the loss on extinguishment of debt totaled $2.2 million. Other expenses decreased by $0.5 million during the year ended December 31, 2009 as compared to the same prior year period due to liquidated damages we incurred under a registration rights agreement. We were unable to have a registration statement declared effective by the SEC during the period required by the agreement due to comments we received from the SEC. These comments were subsequently resolved and the registration statement was declared effective. We recorded a gain on the federal grant totaling $3.0 million during the year ended December 31, 2009. The gain resulted from allocating a portion of the $33.0 U.S. Treasury grant to two wells that we use for monitoring and have capitalized for tax purposes, but we have expensed for book purposes because they are not used commercially to produce electricity at the Thermo No. 1 plant.
Noncontrolling Interest. Noncontrolling interest represented the non-controlling tax equity partner’s claim on the assets of Thermo No. 1. In previous filings, noncontrolling interest was referred to as minority interest.
Noncontrolling interest decreased by approximately $4.2 million during the year ended December 31, 2009 over the same period in 2008. Noncontrolling interest for the year ended December 31, 2009 includes an adjustment resulting from a correction of an error from a prior period that resulted from modifying our hypothetical liquidation at book value computation to include a basis difference that arises under the recast-financial-statements approach. Such modification resulted in a decrease in non-controlling interest occurred in the first quarter of 2009 totaling $2.1 million. Noncontrolling interest also increased approximately $1.9 million during the year ended December 31, 2009 due primarily to the accrual of liquidation preferences in accordance with the Thermo Financing Agreements. Effective December 11, 2009, the tax equity partner withdrew from the Thermo Subsidiary and will no longer have claim on the assets of the partnership.
Comparison of Years Ended December 31, 2008 and 2007
Revenue
During the year ended December 31, 2008, we recognized revenue totaling $0.2 million. Revenue decreased $0.1 million from the year ended December 31, 2007 as a result of completing our research and development subcontract with ARINC in the first quarter of 2008. We accounted for this subcontract on a percentage of completion basis.
Operating expenses
Cost of sales. We reported cost of sales for the years ended December 31, 2008 and 2007 totaling $0.1 million and $0.6 million, respectively. The decrease in cost of sales for 2008 compared to the prior year is primarily related to a $342,000 loss during the first quarter of 2007 resulting from costs greater than originally anticipated to complete the ARINC subcontract objectives that did not occur in 2008.
General and Administrative. General and administrative expenses decreased to approximately $9.8 million for the year ended December 31, 2008 from approximately $10.1 million for the year ended December 31, 2007. This decrease was primarily due to a reduction in equity-based non-cash employee compensation expense, which declined to $2.2 million for the twelve months ended December 31, 2008, compared to $2.7 million for the same period of 2007. Equity-based non-cash compensation expense was higher during the year ended December 31, 2007 due to the vesting of a larger number of executive stock and option grants. Equity-based non-cash service provider compensation for the year ended December 31, 2008 decreased by approximately $0.8 million from the same period in 2007. While no shares issued to service providers were expensed as general and administrative during 2008, 200,000 shares of common stock were issued to a provider of financial advisory services during the year ended December 31, 2007 totaling $1.0 million. We also granted to a service provider 95,000 options to purchase shares of our common stock during 2008 totaling $0.2 million. This decrease is partially offset by increased professional services associated with financing structuring, which increased approximately $0.6 million during the year ended December 31, 2008 over the same period in 2007. Employment related costs increased approximately $0.5 million during the year ended December 31, 2008 compared to the same period of 2007, reflecting higher average salaries and employment levels required to support the ramp up in activity of the Power Systems segment. Office expenses totaled $0.7 million for the year ended December 31, 2008, which represents an increase of $0.1 million when compared to the same period in 2007. The increase is primarily due to increased service fees to administer the cash payments for the Thermo No. 1 plant and additional office related expenses due to current year corporate expansion.
Power Project Developments. Power project development expenses during the year ended December 31, 2008 totaled $10.4 million, compared to $2.6 million for the year ended December 31, 2007. Equity-based non-cash employee and contractor compensation for the year ended December 31, 2008 increased $0.5 million over the year ended December 31, 2007 as a result of stock option grants to new employees. Employment related costs for power project development employees increased during the year ended December 31, 2008 by $1.3 million over the same period of 2007 as we increased our work force levels to execute our business plan. During the 2008, professional services increased by $4.6 million from 2007. The higher professional fees during
2008 consisted primarily of professional services associated with the overall tax equity financing structure for the Thermo No. 1 financing arrangements and geological engineering consulting fees associated with the development of the Thermo No. 1 plant. Property related expenses such as delay rentals, completed transmission line capacity studies and insurance increased during the year ended December 31, 2008 over 2007 by approximately $0.6 million due to delay rentals on the anniversary date of each of the geothermal leases we acquired. In addition, since we began construction of our Thermo No. 1 plant in 2008, we incurred costs related to performing transmission line capacity studies and certain insurances that were not incurred in the previous year. During the year ended December 31, 2008, other expenses also increased by $0.6 million as compared to 2007. The higher expenses in 2008 consisted primarily of a write-off associated with a promissory note that we deemed to be uncollectible and certain lease acquisition costs relating to properties in California, Utah and Washington that we expensed in 2008.
Unsuccessful and Impaired Wells. Unsuccessful and impaired wells expense increased $13.6 million during the year ended December 31, 2008 over 2007. The increase was primarily due to higher expense amounts in 2008, including $10.6 million related to expensing two wells at the Thermo No. 1 plant and $3.0 million related to expensing of one well at the Truckee project. As a result of evaluating the combined production capacity of the Thermo No. 1 plant and the combined electricity producing capacity of the production wells, in accordance with our policy, we identified two completed production-sized wells that are unlikely to be used for the production of electricity at the Thermo No. 1 plant.
The determination that the Truckee well was impaired was based primarily on the difficult financing environment and our decision to focus on the development of other projects. As a result of these factors, we determined the future undiscounted cash flows from the Truckee were uncertain. Management believes that the Truckee well could still be used in the production of electricity as either a production or re-injection well in the future, should we decide to resume active development of the Truckee project.
Research and Development. Research and Development expense increased from $3.4 million in the year ended December 31, 2007 to $4.8 million for the year ended December 31, 2008. Equity based non-cash employee compensation for the year ended December 31, 2008 decreased by approximately $0.1 million from the prior year primarily due to the termination of employment of an employee during 2008. Cash based employee compensation during the twelve months ended December 31, 2008 decreased by approximately $0.4 million compared to the year ended December 31, 2007, reflecting a reduction in the number of employees performing research and development activities. Professional services increased by approximately $1.2 million during the year ended December 31, 2008 over the same period of 2007. This increase was due to the timing of consulting work performed by our PHEV consultants and the hiring of a former key employee as a consultant. The portion of engineering expenses that could be attributed to cost of sales increased approximately $0.5 million during the twelve months ended December 31, 2008 over the comparable 2007 period due primarily to the increased materials consumed in testing our PHEV prototype.
Interest and Other Income. Interest income for the year ended December 31, 2008 decreased to $0.4 million from $0.8 million for the same period in 2007. The decrease was due primarily to lower average monthly cash balances and decreased interest rates due to the overall economic conditions during the twelve months ended December 31, 2008 compared to the 2007 period. Interest expense for the year ended December 31, 2008 increased $3.2 million from the same period in 2007. The increase was due to accrued interest expense relating to the issuance of the Convertible Notes and the non-recourse Thermo Note. Other expense also increased $0.8 million during the year ended December 31, 2008 over the same period in 2007 due to liquidated damages we incurred under a registration rights agreement. We were unable to have a registration statement declared effective by the SEC during the period required by the agreement due to comments we received from the SEC. These comments were subsequently resolved and the registration statement was declared effective.
Noncontrolling Interest. Noncontrolling interest for the year ended December 31, 2008 includes the portion of the net loss that is allocated to a third party that owns a noncontrolling interest in our Thermo Subsidiary totaling $1.8 million. There was no noncontrolling in 2007.
Liquidity and Capital Resources
The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. As reflected in the accompanying consolidated financial statements, as of December 30, 2009, we had approximately $41,800 in cash and cash equivalents on hand and restricted cash and marketable securities of approximately $11.3 million and accounts payable and accrued liabilities of $16.7 million. Cash used in operations totaled approximately $23.5 million, $22.9 million, and $6.7 million for the years ended December 31, 2009, 2008 and 2007, respectively. Our accumulated deficit at December 31, 2009 totaled $109.7 million. We have incurred substantial losses since inception, and we are not operating at cash breakeven.
Our ability to secure liquidity in the form of additional financing or otherwise is crucial for the execution of our plans and our ability to continue as a going concern. Our current cash balance, together with cash anticipated to be provided by operations, will not be sufficient to satisfy our anticipated cash requirements for normal operations and capital expenditures for the foreseeable future. During 2008 and 2009, economic conditions have weakened significantly and global financial markets have experienced significant liquidity challenges. Despite these challenges, we have been able to obtain a limited amount of financing.
Our independent registered public accounting firm’s report on our financial statements expresses doubt about our ability to continue as a going concern. The report includes an explanatory paragraph stating that there is substantial doubt about our ability to continue as a going concern due to the Company incurring significant losses, the use of significant cash in operations, and the lack of sufficient capital, as of the date the report was issued, to support our business plan through the end of 2010 or later.
We are not currently generating significant revenues, and our cash and cash equivalents will continue to be depleted by our ongoing development efforts as well as our general and administrative expenses. Until we are in a position to generate significant revenues, we will need to continue to raise additional funds to continue operating as a going concern. We may seek this additional funding through the issuance of debt, preferred stock, equity or a combination of these instruments. We may also seek to obtain financing through government funding from grants, loan guarantees and private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, entry into pre-paid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. We cannot be certain that funding from any of these sources will be available on reasonable terms or at all. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we may need to curtail or cease operations, modify our current plans for plant construction, well field development and other development activities, or extend the time frame over which these activities will take place.
Recent Financing Activities
We completed an offering of 5,000 shares of the Preferred Stock at a negotiated price of $1,000 per share for a total purchase price of $5,000,000, and the Preferred Warrant to purchase an additional 14,000 shares of Preferred Stock. These securities were purchased by Fletcher The net proceeds to the Company from the sale of the Preferred Stock, after deducting the underwriter fees of $250,000, were approximately $4.75 million. The holder of the Preferred Stock is entitled to a quarterly dividend payable in cash or shares of our common stock at an annual rate equal to LIBOR plus eight (8) percent, but in no event higher than 14%, subject to adjustment. Each share of Preferred Stock is convertible into shares of our common stock at a price of $5.00 per share. The
holders of the Preferred Stock may also redeem the shares of Preferred Stock at the earlier of July 28, 2010 or the date on which the Daily Market Price (as defined in the Certificate of Rights and Privileges) exceeds $2.00 per share. The redemption price is the greater of (a) $1.2277 per share and (b) 120% of the Prevailing Market Price (as defined in the Certificate of Rights and Privileges), subject to certain adjustments. As consideration for acting as underwriter in the Preferred Stock transaction with Fletcher, we paid to CapStone underwriter fees of $250,000 and issued to Capstone a warrant (the “Private Underwriter Warrant”) to purchase 171,568 shares of our common stock, at an exercise price of $1.275 per share. The Private Underwriter Warrant is exercisable at the option of the holder for a period of five years commencing 181 days after the issue date of the Private Underwriter Warrant.
During 2009, we established an Unsecured Line of Credit Agreement and Promissory Note, dated January 27, 2009 and amended on July 22, 2009 (the “Line of Credit”), among Radion Energy, LLC (“Radion”), Ocean Fund, LLC (“Ocean Fund”), Primary Colors, LLC (“Primary Colors”) and R. Thomas Bailey, an individual (collectively, the “LOC Lenders”). During 2009 we borrowed a total of $13.5 million under the Line of Credit. In October 2009, we sold shares of our common stock and warrants to acquire shares of our common stock to three of the LOC Lenders for a total purchase price of $5.4 million. We received the purchase price in the form of promissory notes, which were then used as an offset to settle our outstanding obligations to the participating LOC Lenders under the Line of Credit and reduce our outstanding borrowings under the Line of Credit to $5.3 million. This transaction reduced our liabilities, but did not change our available cash. Although the $5.3 million of outstanding borrowings under the Line of Credit are due in July 2010, the remaining LOC Lender is a related party and has informed us that he does not intend to exert further pressure on our liquidity situation. Therefore, we may seek to extend the maturity date for these borrowings or otherwise modify the payment terms of the Line of Credit if we are unable to repay the outstanding borrowings. We cannot provide any assurance, however, that we will be able to modify the terms of the Line of Credit, and if we are unable to repay the outstanding borrowings when due, we would be in default under the terms of the Line of Credit. Any default under the Line of Credit would also trigger a cross-default under the Convertible Notes.
In July, 2009, we completed a $25.5 million registered offering of common stock and warrants. We sold an aggregate of 8,550,339 units (“Units”) primarily to institutional investors. Each Unit consists of one share of our common stock, and one warrant to purchase 0.50 share of the Common Stock pursuant to a Warrant to Purchase Common Stock. The per share exercise price of the July 2009 Warrants is $4.62. The investors purchased the Units for a negotiated price of $2.98 per Unit. Our net proceeds from the offering, after deducting placement agents’ fees and offering expenses totaling $1.7 million, were approximately $23.8 million. Under the subscription agreements with each investor, the investors have the right, subject to certain exceptions, to participate in any future equity financing by us prior to December 30, 2010. The participation right allows the registered direct investors to purchase up to 35% of the securities offered.
On November 14, 2008, we sold 2,000,000 shares of our common stock at a fixed price of $5.00 per share in a private placement with Fletcher. We also sold to Fletcher 2,360,417 shares of our common stock on December 12, 2008 for $4.23654 per share, which represented a price per share equal to $10.0 million divided by 110% of the average of the daily volume-weighted average price on the NYSE Arca exchange for the common stock for the ten business days ending on and including December 11, 2008. The gross proceeds from the closing of the November 14, 2008 and December 12, 2008 private placement transactions were $20,000,000, before deducting fees and commissions. We paid commissions of $1,232,000 to a placement agent in connection with the closing of the private placement transactions. In connection with this private placement, we issued warrants to purchase up to a maximum of 7,458,532 of our shares of common stock. Under our agreements with Fletcher, we were required to file a registration statement with the SEC to register the resale of the shares of common stock acquired by Fletcher. Although we timely filed that registration statement, the registration statement was not declared effective by the SEC until the SEC staff completed its review of our filings on May 26, 2009. Due to this delay, we were obligated to pay damages to Fletcher. As of December 31, 2009, we had accrued $800,000 to reflect the amounts owed to Fletcher. Subsequently, in connection with the sale of the Preferred Stock to Fletcher in February 2010, the accrued fees were waived.
During the third quarter of 2008, we raised net proceeds of approximately $24.2 million from the sale of shares of our common stock pursuant to an ATM Equity Offering Sales Agreement with Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated. Also during the third quarter of 2008, we obtained project financing for the Thermo No. 1 plant. The project financing arrangements for the Thermo No. 1 plant included approximately $31.2 million of permanent non-recourse debt financing for the Thermo No. 1 plant with a fixed annual interest rate of 7.00%. The financing arrangements for the Thermo No. 1 plant are described in more detail below.
In March 2008, we raised gross proceeds of $50.0 million, before deducting fees and commissions from the issuance of the Convertible Notes. We placed approximately $7.9 million of the proceeds in an escrow account to secure payment of the first four interest payments payable on the Convertible Notes. We also used approximately $15.0 million of the proceeds to enter into a forward stock purchase transaction, pursuant to which we will repurchase shares of our common stock, and approximately $5.9 million of net proceeds to fund a call spread option transaction. On April 1, 2008, the initial purchaser of the Convertible Notes exercised its overallotment option and we sold an additional $5.0 million aggregate principal amount of Convertible Notes. We placed approximately $0.8 million of the proceeds from the overallotment exercise in an escrow account to secure payment of the first two years of interest payable on the additional Convertible Notes issued pursuant to the overallotment exercise.
Our outstanding Convertible Notes pay interest semi-annually on April 1 and October 1 of each year at a rate of 8.00% per annum. As described above, we placed an aggregate of approximately $8.7 million in an escrow account to secure payment of the first two years of interest payable on the Convertible Notes. The Convertible Notes are convertible, at the holder’s option, at an initial conversion rate of 108.3658 shares of common stock per $1,000 principal amount of Convertible Notes. The conversion rate is subject to adjustment. If a fundamental change occurs, holders will have the right to require us to repurchase for cash all or any portion of their notes at 100% of the principal amount of the notes to be repurchased plus accrued and unpaid interest. Holders who convert their notes in connection with certain fundamental changes may also be entitled to a make whole premium in the form of additional shares of our common stock. The maturity date of the Convertible Notes is April 1, 2013.
Although we were able to obtain limited financing through the sources described above, these sources of funding alone will be insufficient for us to properly execute our current business plan. We have substantial short-term and long-term obligations, and need to obtain additional financing to meet these obligations. However, the current economic environment makes it challenging for us to obtain the financing that we need, on terms acceptable to us.
The cost of raising capital in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity on terms that are similar to existing debt, and reduced, or in some cases ceased, to provide funding to borrowers. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we will be unable to satisfy our existing obligations, or execute our plans. In such case, we would be required to curtail or cease operations, liquidate or sell assets, modify our current plans for plant construction, well field development and other development activities, or extend the time frame over which these activities will take place, or pursue other actions that could adversely affect future operations. Federal and state governments have recognized the financing challenges faced by many businesses and have established programs to help companies engaged in the development of renewable energy projects. These programs include loan guarantee, government grant and other programs. Accordingly, part of our short-term strategy to obtain additional funding includes applications for loan guarantees and government grants.
In February of 2010, we received a grant from the U.S. Treasury under the Recovery Act that will enable us to redeem the interest of the tax equity investor in our Thermo No. 1 plant and make other modifications to the financing arrangements for the Thermo No. 1 plant. We continue to review filing requirements for additional loan guarantees and grants under the Recovery Act and other stimulus programs. While we are optimistic that we can qualify for such grants, we cannot predict whether we will be able to successfully obtain loan guarantees or grants under government programs. In the third quarter of 2009, we and Indonesia Power submitted a joint application for a U.S. Trade and Development Agency (“USTDA”) grant for an exploration program on the resource in Indonesia. During the first quarter of 2010, Indonesia Power received notice of approval of the grant from USTDA. We have been appointed by Indonesia Power as sole source contractor to the project. Under the grant, USTDA will reimburse us up to $934,000 which is 70% of the overall estimated costs of $1,343,000 to be incurred for the exploration program. Accordingly, 30%, or $409,000, of the overall costs required as part of the cost matching provision will not be reimbursed. Any costs incurred in excess of $1,343,000 will not be reimbursed.
We intend to continue to seek financing arrangements to fund our development activities from a variety of sources, which may include the issuance of debt, preferred stock, equity or a combination of these instruments. We also continue to evaluate a variety of alternatives to finance the development of our geothermal power projects. These alternatives include project financing and tax equity financing, government funding from grants, loan guarantees or private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, entry into prepaid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. The amount and timing of our future capital needs will depend on many factors, including the timing of our development efforts, opportunities for strategic transactions, and the amount and timing of any cash flows we are able to generate. We cannot be certain that funding will be available to us on reasonable terms or at all.
Certain Commitments
At December 31, 2009, we had approximately $16.7 million in accounts payable and accrued expenses. Approximately $4.3 million of this amount was owed to PWPS for power generating units received for the Thermo No. 1 plant. Under the terms of our agreement with PWPS, these amounts are not due and payable until specific tests have been successfully completed. If these tests indicate a problem with the generating units that prevented the timely completion of the Thermo No. 1 plant, we may be entitled to retain a portion of the amount owed as liquidated damages. The remaining balance of our accounts payable and accrued expenses is for amounts owed for well field development, other equipment and construction costs for the Thermo No. 1 plant and for general and administrative costs.
As part of our geothermal power project development efforts, we have made a variety of financial commitments. Currently, our most significant financial commitments relate to our obligations under our purchase agreements with PWPS and other vendors. These purchase agreements allow us to order and purchase generating units, transformers, pumps, cooling towers, transmission lines, power substations, fire safety equipment and other major electronic components for use in our geothermal power plants. We also have obligations to pay delay rentals and other expenses associated with the geothermal resources on properties in which we have acquired an interest. As of December 31, 2009, we were obligated to pay the vendors and the lessors of our geothermal leases approximately $12.4 million in 2010; $1.3 million in 2011; $1.4 million in 2012; $1.5 million in 2013; and $1.6 million in 2014.
In 2008, we entered into a series of purchase agreements with UTC Power Corporation (“UTCP”), a subsidiary of United Technologies, Inc. The agreements provided for the purchase of power generating units for use at our Thermo No. 1 plant and other projects we planned to develop. The original agreements were subsequently assigned to PWPS.
At March 31, 2009, we had taken delivery of 163 power generating units pursuant to these agreements, including 50 units that were installed at the Thermo No. 1 plant and capitalized as “Geothermal property, plant and equipment” on our condensed consolidated balance sheet. Subsequently, during 2008 and 2009, we amended our agreements with PWPS. Under the amended agreements, title for the 113 power generating units previously delivered to us was transferred back to PWPS. We and PWPS also agreed that, until the earlier of April 9, 2012 and the date on which we have installed 200 power generating units (in addition to the power generating units installed at our Thermo No. 1 plant site.
PWPS will be the exclusive provider of heat-to-electricity equipment used for each merchant power plant project we develop if PWPS can provide equipment meeting the needs of the project. We are currently evaluating whether PWPS or other power generating equipment can meet our power generating needs at our Lightning Dock location. Pursuant to our agreement, PWPS agreed that we would receive preferential pricing until April 9, 2011. We had previously paid deposits for the generating units totaling $8.9 million. As part of the amended agreements, $1.5 million of these deposits was retained by PWPS as a restructuring charge, and the remaining $7.4 million of deposits was refunded.
Project Financing
We will need to finance each of the geothermal power plants we develop on a project by project basis. We previously entered into a Commitment Letter with Merrill Lynch to finance up to 155 MW of future projects. Merrill Lynch provided financing for the construction of our Thermo No. 1 plant in accordance with this Commitment Letter. The Commitment Letter was subsequently terminated as part of an overall restructuring of the project finance and tax equity agreements for the Thermo No. 1 plant. As a result, we have no existing commitments to finance the construction of the power plants we intend to develop.
The Thermo Financing
On August 31, 2008, we finalized the Thermo Financing Agreements that provided for approximately $31.2 million of permanent non-recourse debt financing for the Thermo No. 1 plant with a fixed annual interest rate of 7.00%. The Thermo Subsidiary received proceeds from the debt financing of approximately $26.1 million for construction of the Thermo No. 1 plant after an original issue discount of approximately $5.0 million. From the proceeds of the debt financing, we received approximately $14.1 million from the Thermo Subsidiary as repayment for construction costs at the Thermo No. 1 plant that were incurred by us prior to closing the project financing. Under the Thermo Financing Agreements, approximately $20.8 million of tax equity capital for the tax benefits associated with the Thermo No. 1 plant was provided to the Thermo Subsidiary by ML Holdings. Our equity contribution to the Thermo Subsidiary of approximately $29.0 million was comprised primarily of the partially completed well field.
Under the Thermo Financing Agreements, Merrill Lynch was entitled to receive 99% of all residual cash flows from the Thermo No. 1 plant after paying all expenses and debt service until the Flip Date. After the Flip Date, Merrill Lynch was entitled to receive 5% of the residual cash flows for the remaining useful life of the Thermo No. 1 plant. In connection with the Thermo Financing Agreements and the Thermo No. 1 plant financing, we and our affiliates entered into certain other ancillary agreements, including a Pledge Agreement with Deutsche Bank to secure payment and performance under the Credit Agreement. The Pledge Agreement granted Deutsche Bank a continuing security interest in and lien on certain membership interests or other interests in the Thermo No. 1 plant. We also entered into a Guaranty Agreement in favor of the Thermo No. 1 plant and ML Holdings, pursuant to which we guaranteed certain obligations of certain parties to the Thermo Financing Agreements.
Under the Thermo Financing Agreement, the Thermo No. 1 power plant was initially required to achieve “Final Completion” (as defined in the Thermo Financing Agreements) by June 30, 2009. After the Recovery Act was passed in February of 2009, it became apparent that the Thermo No. 1 plant would benefit from taking
advantage of a U.S. Department of Treasury renewable energy grant under Section 1603 of the Recovery Act in lieu of tax credits offered under the Internal Revenue Code At the same time, we were working on increasing the output of the Thermo No. 1 plant and were not in a position to achieve Final Completion by the June 30, 2009 deadline. In December of 2009, we completed negotiations with the Thermo No. 1 financing partners, Prudential and Merrill Lynch, and entered into several amendments to the Thermo Financing Agreements, or the Restructuring Amendments.
On December 4, 2009, pursuant to the Restructuring Amendments, the original Limited Liability Company Agreement was amended to enable the Thermo Subsidiary to apply for a Section 1603 grant, or the Grant. The Grant is available to companies with qualified renewable energy projects. Qualified renewable energy projects may receive a cash grant in lieu of ITCs or PTCs.
As part of the Restructuring Amendments, the Thermo Subsidiary and Merrill Lynch entered into a Redemption Agreement pursuant to which Merrill Lynch withdrew from the Thermo Subsidiary. The redemption of Merrill Lynch’s interest was effective on December 11, 2009. According to the Thermo Note, the Redemption Amount to be paid to Merrill Lynch is variable depending on a number of factors. As a result of receiving Grant proceeds of $33.0 million on February 19, 2010, the Redemption Amount has been adjusted to either $17.5 million or $20.0 million, If we reduce the amount of our Convertible Notes by greater than 50% before June 30, 2010, the Redemption Amount will be $17.5 million. Otherwise the Redemption Amount will remain at $20.0 million, plus interest until paid.
The Thermo Note is subject to payment out of Grant proceeds under the order of priority for payments described below. Pursuant to the Raser Note, we provided Merrill Lynch with both a Guaranty of the Thermo Note and a separate note to guaranty the payment in the event the escrowed funds are unavailable or insufficient to pay the Redemption Amount. If the Redemption Amount is not fully paid by the escrowed funds prior to June 30, 2010, Merrill Lynch will have no remaining claim against the Thermo Subsidiary for any shortfall but will look only to the Raser Note to pay the shortfall. The Raser Note may be secured by certain assets currently securing Prudential’s debt which are scheduled to be released from Prudential upon achieving Final Completion.
In February 2010, we amended the Restructuring Amendments to extend the date of Final Completion to June 30, 2010. Under the terms of the Restructuring Amendments, approximately $3.8 million was distributed to us. The remaining proceeds received from the Grant were placed into an escrow account and will be paid out in the following order on or about June 30, 2010: (i) first Prudential will potentially receive a pre-payment, together with a pre-payment penalty, of its outstanding debt, depending on the performance of the Thermo No. 1 plant at the time; (ii) project escrow accounts will be funded as required by the Thermo Financing Agreements; (iii) Merrill Lynch will receive its Redemption Amount (as described above); (iv) Pratt & Whitney Power Systems will receive any amounts left owing to it as the turbine supplier for the Thermo No. 1 plant; and (v) any remaining amounts will be placed in a revenue escrow account and will ultimately flow through as a distribution to us.
Construction Financing for Future Projects
We intend to seek appropriate financing arrangements for the construction of future power plants on a project-by-project basis, once a project is ready to move to the construction phase. The timing of construction for the geothermal power plants we intend to develop, as well as the specific sites we choose to develop and construct, will depend on a number of factors, including drilling results, permitting and our ability to obtain adequate financing.
Our Commitment Letter with Evergreen Clean Energy
We are exploring potential alternatives to finance the drilling of production and reinjection wells for our projects. On December 7, 2009, we entered into the Co-Development Agreement with Evergreen, which could
provide an alternative source of funding for drilling or other early-stage development activities at certain projects. Evergreen’s funding obligations with respect to each site selected for development are subject to the satisfaction of a number of conditions, including satisfactory due diligence, the completion of certain milestones, the granting of a security interest, and the negotiation of definitive agreements relating to the financing of each project. Moreover, Evergreen is a newly formed clean-energy fund in the process of raising capital for its first investments in renewable energy projects. Therefore, the ability of Evergreen to perform its obligations and provide funding for one or more of our projects under the Co-Development Agreement is dependent upon Evergreen’s ability to obtain sufficient capital commitments from investors.
We have provided diligence materials to Evergreen and Evergreen’s potential investors relating to our Thermo No. 2 and Lightning Dock projects. Under the terms of the Co-Development Agreement, we must meet the following development milestones before Evergreen will commit to fund a project: (i) acquire the development site through lease or purchase; (ii) provide a detailed third-party report on the geothermal resource; (iii) prepare a pro-forma projection for the proposed project; (iv) make substantial progress in the negotiation of power purchase agreements and construction financing arrangements; and (v) drill and test the first geothermal well for the project. If we satisfy the milestones, Evergreen will have 20 business days to issue a development commitment and proceed with final documentation or decline the project. Once Evergreen issues a development commitment for a specific project, the Co-Development Agreement contemplates that the definitive documentation will contain the following key terms: (i) Evergreen will reimburse us for the costs of drilling the first well on the project; (ii) Evergreen will finance all future well-field drilling and testing activities up to a maximum amount, expected to be approximately $25.0 million for a typical project; (iii) Evergreen will receive an equity interest in the project, expected to be approximately 50% for a typical project; (iv) Evergreen will make a buy-in payment to us of $5.0 million per typical project; (v) after a project is operating commercially, Evergreen will receive a preferential distribution of cash flows from the project to repay its investment plus a rate of return of 15% and then we will receive distributions until we receive our return on investment; and (vi) once Evergreen’s and our target returns are achieved, project cash flows will be distributed in accordance with the respective ownership interests in the project. The agreement also provides that Evergreen will receive warrants to purchase shares of our common stock in connection with each funding under the Commitment Letter. The amount of warrants issued will be dependent upon the amount of funding provided.
Consolidated Statements of Cash Flows
Operating Activities. Cash consumed by operating activities for the year ended December 31, 2009 consisted primarily of a net loss applicable to common stockholders of approximately $20.2 million, adjusted for approximately $4.0 million of stock-based compensation and stock issued for services and $2.8 million in depreciation, amortization and accretion primarily due to placing the Thermo No. 1 plant in service and beginning depreciating the asset during the second quarter of 2009. We also adjusted our net loss applicable to common stockholders for our loss on extinguishment of debt resulting from issuing warrants associated with the October 2009 registered direct stock offering to the participants in our unsecured Line of Credit (“LOC”). In addition to selling 3.2 million shares of our common stock to the participants in the LOC, we also issued warrants to acquire 1.6 million shares of our common stock at a strike price of $1.61 per share. The fair value of the warrants issued in connection with the October 2009 registered direct offering resulting in the loss on extinguishment of debt totaled $2.2 million. Certain of the capital expenditures for our $33.0 million federal grant qualified as reimbursable costs for tax purposes and were previously expensed for book purposes. Accordingly, for those capital expenditures that had been previously expensed for book purposes, we recorded a gain on the federal grant totaling $3.0 million. We adjusted our net loss applicable to common stockholders for the non-controlling interest in our Thermo No. 1 subsidiary totaling $0.7 million and recognized gain on derivatives totaling $15.0 million due to decreases in the fair value of our warrants that have been classified as liabilities due to price reset features contained in the warrants. We adjusted our net loss applicable to common stockholders for amortization of our deferred financing fees totaling $6.0 million primarily relating to the settlement of a portion of the LOC debt in October 2009 in which the outstanding discount relating to that debt was expensed. Accounts payable and accrued liabilities decreased from $64.5 million at December 31, 2008, to $16.7 million at December 31, 2009, which included a $33.4 million reduction in accounts payable as a result of
returning the title to 113 PureCycle units pursuant to the PWPS Agreement, settlement of outstanding obligations in stock totaling $3.5 million and normal vendor payments of approximately $10.9 million. Accounts receivable from the City of Anaheim increased by $0.3 million relating to the generation of electricity by our Thermo No. 1 plant. Other assets decreased by approximately $0.1 million due to closing our July 2009 financing transaction for which we applied certain prepaid fees to the cost of the closing.
Cash consumed by operating activities for the year ended December 31, 2008 consisted primarily of a net loss applicable to common stockholders of approximately $45.5 million, adjusted for approximately $3.8 million of stock-based compensation and stock issued for services and $13.6 million related to management’s determination to impair and expense two wells at the Thermo No. 1 plant that were not likely to be used in the production of electricity and impair and expense one well at the Truckee project as a result of the current economic conditions and tightening credit markets that caused us to reprioritize our cash uses and concentrate our efforts on our largest known resources instead of Truckee. Accounts payable and accrued liabilities increased from $4.2 million at December 31, 2007, to $64.5 million at December 31, 2008, primarily due to accrued expenses for well field development, geothermal power plant construction, transmission line construction, and the purchase of power systems equipment for the Thermo No. 1 plant. The portion of accrued liabilities relating to well field development, construction-in-progress and power systems equipment, totaling $60.0 million, has been reclassified as a non-cash item to decrease the change in accrued liabilities. Deferred revenues increased by approximately $0.2 million, reflecting a down payment received for our anticipated PHEV. Noncontrolling interest in operations of our subsidiary totaled $3.5 million at December 31, 2008, representing the allocated loss since the time a noncontrolling interest in the Thermo Subsidiary was acquired by a third party in connection with the equity financing arrangements for the Thermo No. 1 plant and certain liquidation preferences that the noncontrolling interest holder would receive upon liquidation. We prepaid commissions arising from entering into the City of Anaheim power purchase agreement totaling $0.4 million at December 31, 2008 and we have also made deposits to manufacture prototypes of our Transportation & Industrial segment designs totaling $0.4 million.
Cash consumed by operating activities for the year ended December 31, 2007 consisted primarily of a net loss applicable to common stockholders of approximately $15.7 million, adjusted for approximately $4.9 million of stock-based compensation and stock issued for services. Interest receivable at December 31, 2007 decreased by approximately $0.4 million compared to December 31, 2006 as a result of the repayment of a note receivable in March 2007. Accounts payable and accrued liabilities increased $3.7 million to $4.3 million at December 31, 2007 due primarily to accrued fees for professional services relating to well field development and design and the Commitment Letter. Other current assets increased by approximately $0.3 million reflecting an increase in prepaid insurance during 2007.
Investing Activities. We maintain a portion of our available unrestricted cash in deposit accounts in two banks in Utah. At times, cash balances in these accounts may exceed federally insured limits. From time to time, we purchase investments in marketable debt securities as a means of temporarily investing the proceeds from financings until the funds are needed for operating purposes. Due to the nature of these investments, we consider it reasonable to expect that their fair market values will not be significantly impacted by a change in interest rates, and that they can be liquidated for cash on short notice. Our investments are intended to establish a high-quality portfolio that preserves principal, meets liquidity needs, avoids inappropriate concentrations and delivers an appropriate yield in relationship to our investment guidelines and market conditions. Concentration of credit risk is normally managed by diversifying investments among a variety of high credit-quality issuers.
We invest a portion of our unrestricted cash in an AIM Funds money market account, which is not affiliated with the bank where we maintain our deposit accounts. The money market account earns interest based on a variable rate. At December 31, 2009, our balance in the money market account was $11,600 and the interest rate applicable to the money market account was 0.10 percent per annum. The average interest rate applicable to the money market account during the quarter ended and year ended December 31, 2009 was 0.12 percent and 0.24 percent per annum, respectively.
Cash from our checking account is swept nightly into an interest bearing account. At December 31, 2009, we had a balance of $18,700 in this sweep account and the interest rate applicable to the sweep account was 0.50 percent per annum. We also maintain cash in a non-interest bearing deposit account and an interest bearing money market account at a separate bank. At December 31, 2009, we had a balance of $10,800 in these account and the interest rate applicable to the money market account was 0.10 percent per annum.
Project financing proceeds received by our subsidiaries are subject to the terms and conditions of those arrangements. An independent administrative agent was appointed to administer all of the Thermo Subsidiary’s cash deposits and disbursements. The independent administrative agent deposited our restricted cash into a money market fund managed by the JP Morgan Fund, which earns interest at a variable rate. At December 31, 2009, we had a balance of $9.1 million invested in this money market fund and the interest rate applicable to the fund was 0.00 percent per annum. Due to the nature of the investments included in the money market accounts, we consider it reasonable to expect that the fair market values of these investments will not be significantly impacted by a change in interest rates, and that they can be liquidated for cash on short notice.
Investing activities used approximately $10.9 million of cash in the year ended December 31, 2009. During the year ended December 31, 2009, we paid $20.7 million for construction costs relating to the Thermo No. 1 plant and $15.6 million relating to drilling the Thermo No. 1 well field. As a result, these construction and well field expenses were primarily paid through our Thermo No. 1 restricted cash account currently totaling $9.1 million. We were refunded certain deposits from drilling and construction contractors totaling $2.6 million that we used to pay our well field development and construction costs. We also purchased certain equipment for the operation of the Thermo No. 1 plant totaling $0.3 million and the purchase of additional water rights totaling $0.1 million in New Mexico. Cash was provided from our marketable equity securities totaling $4.4 million that matured on March 31 and September 30, 2009 that were used to pay the April 1 and October 1, 2009 interest payments of the Convertible Notes (as defined below). Cash was also provided as a result of entering into the PWPS Agreement described above. Pursuant to the PWPS Agreement, we received $7.1 million as a net refund of deposits previously paid to UTCP.
Investing activities consumed approximately $106.2 million in the year ended December 31, 2008, reflecting a net increase in deposits of $0.6 million for the purchase of electric generating units for use in the geothermal power plants we intend to develop in the future. During 2008, we also purchased $32.9 million of equipment for geothermal well field development projects, primarily in Utah, and we incurred construction costs on the Thermo No. 1 plant totaling $38.8 million. We deposited approximately $2.8 million primarily with drilling vendors, transmission line contractors, and utilities to conduct transmission line capacity and routing studies on our behalf. We paid $1.8 million for land and $1.0 million for water rights in the Thermo No. 1 plant area primarily for transmission line easements and for water use operations. We also paid $0.8 million in connection with the acquisition of leases and the exercise of certain options relating to interests in geothermal properties in Oregon, Nevada and Utah. In connection with the issuance of the Convertible Notes, we invested a portion of the proceeds totaling $8.7 million into four discounted U.S. Treasury Strips that mature separately on each of the first four semi-annual interest payment dates of the Convertible Notes. The U.S. Treasury Strips were placed into an escrow account to secure the first four interest payments on the Convertible Notes. On October 1, 2008, we received proceeds from the maturity of the securities totaling $2.3 million which was used to pay the first semi-annual interest payment on the Convertible Notes. These expenditures were partially offset by cash provided by investing activities, including the net change in the notes receivable totaling $0.2 million. In connection with the Thermo Financing Agreements, the funds received through the financing were deposited into restricted money market fund accounts for the purposes of paying for the well field costs to complete the drilling and certain equipment costs to complete the construction of the geothermal power plant resulted in a change in restricted cash totaling $20.9 million.
Investing activities consumed approximately $9.9 million in the year ended December 31, 2007, reflecting deposits of $3.6 million towards the purchase of electric turbines for use in the geothermal power plants we intend to develop. We have also made deposits of $0.6 million to fulfill certain bonding requirements in
connection with certain testing equipment and prototypes used by our Transportation & Industrial segment. During 2007, we also purchased $4.8 million of equipment for geothermal well field development projects in Nevada and Utah. We also paid $5.4 million in connection with the acquisition of leases and the exercise of certain options relating to interests in unproved geothermal properties, including $4.1 million for the purchase of a lease giving us the rights to develop geothermal power plants on certain BLM property in New Mexico. During 2007, we also purchased certain power project development equipment for $0.6 million. Additionally, we paid approximately $0.3 million on equipment and fees relating to filings for patents and trademarks. These expenditures were partially offset by cash provided by investing activities, including the collection in full of a note receivable in the amount of $5.0 million and a change in the status from restricted to unrestricted of $0.3 million of our certificate of deposit.
Financing Activities. Financing activities provided approximately $33.0 million and $124.7 million of cash in the year ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, we obtained the Unsecured Line of Credit to provide working capital for general corporate purposes. As of December 31, 2009, we had borrowed a total of $13.5 million under the Line of Credit. We also completed a registered direct offering in July of 2009 of 8,550,339 units (“Units”) primarily to institutional investors. Each Unit consisted of one share of our common stock, and one warrant to purchase 0.5 shares of our common stock. The investors agreed to purchase the Units for a negotiated price of $2.98 per Unit, resulting in net proceeds, after deducting placement agents’ fees and estimated offering expenses, totaling $23.6 million. During the year ended December 31, 2009, we made principal payments of $2.9 million on the Line of Credit balance and our Thermo Subsidiary also made principal payments of $0.7 million on the 7.00% senior secured note (non-recourse). We incurred financing costs related to the offerings above totaling $0.5 million.
We completed the issuance of the Convertible Notes and the related overallotment option totaling $55.0 million on April 1, 2008. In connection with the sale of the Convertible Notes, we incurred financing fees of $2.2 million, which was paid to Merrill Lynch. We also entered into a call spread option transaction and a forward stock purchase transaction totaling $5.9 million and $15.0 million, respectively. We used the remaining net proceeds from the offering for general corporate purposes and to continue well field and other development activities for our geothermal power projects. In connection with the purchase of a BLM lease in New Mexico, we entered into a promissory note payable and received cash for $0.9 million in February 2008. On June 17, 2008, we entered into an ATM (at-the-market) Equity Offering Sales Agreement with Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, pursuant to which we were able to offer and sell through Merrill Lynch, as our sales agent, from time to time, shares of our common stock with an aggregate sales price of up to $25,000,000. During the third quarter of 2008, we raised net proceeds totaling $24.2 million from our participation in the ATM equity program. In addition, pursuant to the Thermo Financing Agreements, we received a capital contribution for minority interest in our Thermo Subsidiary totaling $24.5 million. Under the same Thermo Financing Agreements, we also entered into an 18 year permanent non-recourse senior secured note bearing annual interest at 7.00% and received net proceeds totaling $26.1 million. Most recently, on November 14, 2008, we sold 2,000,000 shares of our common stock at a fixed price of $5.00 per share in a private equity transaction or $10.0 million. We also sold 2,360,417 shares of our common stock on December 12, 2008 for $4.23654 per share, which is a price per share equal to $10.0 million divided by 110% of the average of the daily volume-weighted average price on the NYSE Arca exchange for the common stock for the ten business days ending on and including December 11, 2008. The gross proceeds from the closing of the November 14, 2008 and December 12, 2008 private placement transactions were $20,000,000, before deducting fees and commissions. We paid commissions of $1,232,000 to a placement agent in connection with the closing of the private placement transactions. During the year ended December 31, 2008, we also received approximately $0.7 million from the exercise of other outstanding stock options and warrants.
As of December 31, 2009, we had stockholders’ equity of approximately $16.8 million and approximately $41,800 in cash and cash equivalents and restricted cash and marketable securities of approximately $11.3 million. Our cash balance, together with cash anticipated to be provided by customer sales will not be sufficient to satisfy our anticipated cash requirements for normal operations and capital expenditures for the year ending
December 31, 2010 or later. To strengthen our financial position, we intend to seek additional funding to be used for general corporate purposes, as well as geothermal development activities, including advancing well field development activities and project permitting. We intend to seek funding for our capital needs through the issuance of debt, preferred stock, equity, government grants, loan guarantees, prepaid power purchase agreements with utilities or municipalities, or a combination of these instruments. We may also seek to obtain financing through private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. We expect that we will be able to secure sufficient financing to satisfy our anticipated cash requirements for normal operations and capital expenditures through at least December 31, 2010, although current economic and market conditions will make it challenging for us to do so. We intend to seek separate financing commitments with respect to each geothermal power project we intend to develop in order to fund construction and other development costs. We cannot be certain that we can obtain financing on terms acceptable to us or at all. If we are not able to raise additional capital, we will not have sufficient cash to fund our operations. In such case, we would be required to curtail or cease operations, liquidate or sell assets, modify our current plans for plant construction, well field development and other development activities, or extend the time frame over which these activities will take place, or pursue other actions that would adversely affect future operations.
Dividends related to convertible preferred stock. There were no dividends related to convertible stock during the years ended December 31, 2009, 2008 and 2007, respectively. As of December 31, 2009, we had no shares of preferred stock outstanding. On February 3, 2010, we issued the Preferred Stock to Fletcher in consideration for $5.0 million. The holder of the Preferred Stock is entitled to a quarterly dividend payable in cash or shares of our common stock at an annual rate equal to LIBOR plus eight (8) percent, but in no event higher than 14%, subject to adjustment.
Off-Balance Sheet Arrangements
As of December 31, 2009, we had the following off-balance sheet arrangements as defined by item 303(a)(4)(II) of SEC Regulation S-K.
As described above, if there are insufficient funds remaining in the project accounts on the Final Completion Date, after the payout of any potential buy-down amounts, to pay the remaining amounts owed to PWPS, we will reimburse PWPS for any remaining unpaid amounts owed to it. To secure payment of our obligations to reimburse PWPS, we provided a security interest PWPS in five patents relating to our Transportation & Industrial segment. We are unable to estimate the maximum potential obligation we may have for future reimbursement payments to PWPS at this time. We believe that the likelihood that we will be obligated to reimburse PWPS for liquidated damages under our amended agreements is “remote” and, accordingly, no liability was recorded for the year ended December 31, 2009.
Contractual Obligations and Commitments
We lease our corporate office located at 5152 North Edgewood Drive, Suite 200, Provo, Utah. The corporate office has 19,300 square feet with monthly rent of approximately $34,400. The lease expires on December 31, 2011.
We lease our Symetron™ testing facility in Utah County, Utah. The current lease for this facility provides rent of approximately $3,500 per month. The term of the lease is month to month with a 60 day notice prior to termination of the agreement. Unless terminated earlier, the lease agreement expires on May 31, 2010.
We currently lease a plot of land adjacent to our Lightning Dock project in Hidalgo County, New Mexico. Under the lease, we are permitted to store our power generating units, cooling tower equipment, pumps and other equipment that have been delivered for use at our Lightning Dock project. All equipment is stored outside with
monthly rent computed on a per unit basis of approximately $8,400 per month. The lease continues on a month to month basis until all equipment is removed from the property.
Total rent expense for all of our office space, testing facilities and outdoor storage site leases for the year ended December 31, 2009 was approximately $446,800. Total rent expense for all of our office space, testing facilities and outdoor storage site leases for the years ended December 31, 2008 and 2007 was approximately $316,200, and $265,000, respectively. The properties covered by these leases are well maintained and in good condition.
Pursuant to a Road Construction and Maintenance Agreement with Beaver County, Utah we are obligated to post a $100,000 improvement bond, or provide for a mutually agreed upon equivalent. We are currently in the process of securing the improvement bond.
The table below summarizes our operating lease obligations pursuant to our non-cancelable leases, our long-term debt and our executed purchase obligations as of December 31, 2009:
The contractual purchase obligations set forth above are not recorded as liabilities in our consolidated financial statements. Our equipment purchase obligations are recorded as liabilities when the equipment is received by us or the risk of loss has been legally transferred to us. Amounts payable pursuant to our operating leases are expensed during the reporting period in which the amounts are due and payable. The operating lease obligations include operating leases for our corporate headquarters and our testing facility.
The purchase obligations set forth in the table above include our amended agreements with PWPS for the purchase of power generating units and certain other agreements with vendors of equipment and services. As of December 31, 2009, we were obligated to pay the vendors approximately $12.4 million in 2010; $1.3 million in 2011; $1.4 million in 2012; $1.5 million in 2013; and $1.6 million in 2014, as reflected in the table above. Since our geothermal lease agreements are not considered to be operating leases the purchase obligations also include delay rental payments that we have agreed to make in order to maintain our granted rights to the leased properties.
The asset retirement obligations set forth in the table above include our future obligation to dismantle the geothermal power plant, plug and abandoned our production-sized wells that we have drilled and restore the property to its original state at the end of the power plant’s useful life which is estimated at 35 years. We have also incurred an obligation to plug and abandon certain wells at our Lightning Dock project and our Thermo No. 1 plant within one year. Therefore, we have estimated the present value of the asset retirement liabilities for the Thermo No. 1 plant and for each of the respective wells. In connection with our asset retirement obligation, we have posted drilling bonds with the Nevada Department of Minerals totaling $50,000, the Utah Division of Water Rights totaling $50,000 and the Oregon Department of Geology & Mineral Industries totaling $25,000 to ensure that we comply with the local plug and abandonment requirements associated with drilling wells.
We have employment commitments with our chief executive officer and the future chief financial officer. However, amounts due under these employment contracts are not reflected in the table above.
Recently issued accounting pronouncements
In January 2010, the Financial Accounting Standards Board (the “FASB”) issued new accounting guidance relating to improving disclosures about fair value measurement. The new accounting guidance requires new disclosures and clarifies certain existing disclosure requirements about fair value measurements. A reporting entity is required to disclose significant transfers in and out of Level 1 and Level 2 fair value measurements, to describe the reasons for the transfers and to present separately information about purchases, sales, issuances and settlements for fair value measurements using significant unobservable inputs. This new accounting guidance is effective on January 1, 2010, except for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective on January 1, 2011 and early adoption is permitted. We do not expect that the adoption of will have a material impact on our financial position, results of operations or cash flows.
In October 2009, the FASB issued new accounting guidance relating to multiple-deliverable revenue arrangements. The new accounting guidance changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable to be based on the relative selling price. The selling price used for each deliverable should be based on vendor-specific objective evidence if available, third-party evidence if vendor specific evidence is not available, or the estimated selling price. Although the effective date of this new pronouncement is January 1, 2011, early adoption is permitted. We elected to adopt this new guidance effective January 1, 2010 which had not material impact on our financial condition, results of operations or cash flows in prior years.
In October 2009, the FASB issued new accounting guidance relating to lending shares in contemplation of convertible debt issuances or other financings. The new accounting guidance amends the accounting and reporting guidance for debt (and certain preferred stock) with specific conversion features or other options. The effective date of this new guidance is January 1, 2010. Since we did not enter into a share lending arrangement upon the issuance of our convertible debt, implementation of this new guidance will not impact on our financial position, results of operations or cash flows.
In September 2009, the FASB issued new accounting guidance to provide implementation guidance for uncertainty in income taxes for “pass through entities.” The amendments clarify that management’s determination of the taxable status of the entity is a tax position subject to the standards required for accounting for uncertainty in income taxes. This new guidance became effective on July 1, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
In August 2009, the FASB issued new accounting guidance to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. This new guidance became effective on July 1, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
In June 2009, the FASB issued new accounting guidance relating to codification of accounting principles and authoritative hierarchy. On the effective date of this Statement, the Codification superseded all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification will become non-authoritative. The new accounting guidance was effective for financial statements issued for interim and annual periods ending after September 15, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
In June 2009, the FASB issued new accounting guidance to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This new accounting guidance becomes effective as of the beginning of each reporting entity’s first
annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. Based upon current assumptions, we believe that adoption of this new accounting guidance will not immediately change the designation of our Thermo Subsidiary from being a consolidated entity for financial statement purposes. However, we will continue to evaluate events under this new pronouncement that may result in the deconsolidation of the Thermo Subsidiary as they arise.
In March 2008, the FASB issued new accounting guidance relating to disclosures about derivative instruments and hedging activities. The new accounting guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, results of operations and cash flows. The new standard also improves transparency about how and why a company uses derivative instruments and how derivative instruments and related hedged items are accounted for under the Accounting Standards Codification. It is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We adopted this new accounting guidance effective January 1, 2009 and addressed the relevant disclosures accordingly.
In December 2007, the FASB issued new accounting guidance relating to non-controlling interests in consolidated financial statements. In the new accounting guidance, the FASB established accounting and reporting standards that require non-controlling interests to be reported as a component of equity, changes in a parent’s ownership interest while the parent retains its controlling interest to be accounted for as equity transactions, and any retained non-controlling equity investment upon the deconsolidation of a subsidiary to be initially measured at fair value. This new accounting guidance was effective January 1, 2009 and retroactive application was prohibited. We adopted this new accounting guidance effective January 1, 2009 which primarily resulted in moving the presentation of non-controlling interest to the “Stockholders’ equity” section of our condensed consolidated balance sheets.
We also adopted the recent accounting revisions relating to the classification and measurement of redeemable securities. The accounting revisions require that securities with redemption features that are not solely within the control of the company should be classified outside of permanent equity as temporary equity. We adopted these revisions effective January 1, 2009. As a result of the adoption, we classified “non-controlling interest” as temporary equity outside of the permanent equity section.
In December 2007, the FASB issued new accounting guidance relating to collaborative arrangements. This new accounting guidance prescribes the accounting for parties of a collaborative arrangement to present the results of activities for the party acting as the principal on a gross basis and report any payments received from (made to) other collaborators based on other applicable GAAP or, in the absence of other applicable GAAP, based on analogy to authoritative accounting literature or a reasonable, rational, and consistently applied accounting policy election. Further, this new accounting guidance clarified the determination of whether transactions within a collaborative arrangement are part of a vendor-customer (or analogous) relationship, subject other accounting considerations. This new accounting guidance is effective for collaborative arrangements that exist on January 1, 2009 and application is retrospective. We adopted this new accounting guidance effective January 1, 2009 and the adoption had no material effect on our financial position or results of operations.
In June 2008, the FASB ratified new accounting guidance relating to determining whether an instrument (or embedded feature) is indexed to our own stock. The new accounting guidance provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. It also clarifies the impact of foreign currency denominated strike prices and market-based employee stock option valuation instruments on the evaluation. This new accounting guidance was effective for fiscal years beginning January 1, 2009 which we adopted on January 1, 2009. The adoption of this new accounting guidance resulted in our warrants with anti-dilutive provisions being classified as derivatives. For further discussion of the adoption of this new accounting guidance, please refer to Note 17. “Warrants” and Note 19. “Fair Value Measurements” below.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk.
Disclosures About Market Risk
In addition to the risks inherent in our operations, we are exposed to financial, market, political and economic risks. The following discussion provides information regarding our exposure to the risks of changing interest rates.
As of December 31, 2009, we had approximately $41,800 in cash and cash equivalents and $9.1 million in restricted cash, that were invested primarily in low risk money market accounts and certificates of deposit until needed for operating and other activities. Current money market rates range from approximately 0.00% to 0.10%. The money market interest rates have declined from 1.32% over the last twelve months. A review of our money market accounts indicated that no impairment occurred during the year ended December 31, 2009 and no write-down in fair value is considered necessary.
Concurrent with the issuance of the Convertible Notes, we entered into a call spread option transaction with an affiliate of Merrill Lynch for the cost of $5.9 million. The call spread option transaction was intended to reduce the potential dilution of our common stock upon conversion of the Convertible Notes. The Convertible Notes are convertible at any time prior to maturity at a conversion rate of 108.3658 shares per $1,000 principal amount of Convertible Notes, which represents a conversion price of $9.23 per share, subject to adjustment. The call spread option transaction allows us to receive up to 934,118 shares of our common stock at $9.23 per share from the call spread option transaction holder, equal to the amount of our common stock related to the excess conversion value that we would deliver to the holders of the Convertible Notes upon conversion. The number of shares that we would receive pursuant to the call spread option transaction declines after the market price exceeds $11.15 per share to reflect the aggregate market value of $10.4 million of our common stock. The call spread option transaction will terminate upon the earlier of the maturity date of the Convertible Notes or the first day all of the Convertible Notes are no longer outstanding due to conversion or otherwise. Our ability to receive the maximum aggregate market value of shares of our common stock pursuant to the call spread option transaction is dependent upon the performance of our stock price and the desire of holders to convert the Convertible Notes into shares of our common stock. If holders fail to convert the Convertible Notes into shares of our common stock prior to the due date in 2013, the call spread option transaction will expire without the shares of our common stock being delivered to us.
Concurrent with the issuance of the Convertible Notes, we entered into a forward stock purchase transaction with Merrill Lynch at a cost of $15.0 million. Pursuant to the forward stock purchase transaction we are entitled to receive from Merrill Lynch 1.95 million shares of our common stock on or about the maturity date of the Convertible Notes to reduce the potential dilution to our common stock upon conversion of the Convertible Notes. If the stock price falls below $7.69 per share on or about the maturity date of the Convertible Notes, the aggregate value of our common stock received would be less than the amount paid for the forward stock purchase transaction.
Changes in interest rates also impact the amount of tax credit equity we may be able to raise for a project under development. In general, as interest rates rise, the tax equity investor’s hurdle rate for their investments increases. As the hurdle rate increases, the amount of tax credit equity that can be raised for a project decreases.
We are exposed to losses in the event of nonperformance by the counterparties on the instruments described above.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data.
Our audited Consolidated Financial Statements, including the notes thereto, appear beginning on page of this report.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
ITEM 9A.
ITEM 9A. Controls and Procedures.
Evaluation of disclosure controls and procedures
Our management, with the participation of our chief executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 as of the end of the period covered by this Annual Report on Form 10-K. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs. The design of any disclosure controls and procedures also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Based on that evaluation, our chief executive officer and principal financial officer concluded that, as of December 31, 2009, our disclosure controls and procedures were, subject to the limitations noted above, effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting.
We continued to formalize documentation and perform testing of our financial processes during the period covered by this Annual Report on Form 10-K. Our Chief Executive Officer resigned in August 2009. In addition, our Chief Financial Officer resigned in January 2010, prior to the filing of our 2009 Annual Report on Form 10-K. As a result of the management turnover, individual responsibilities for certain internal controls over financial reporting changed, including the individuals responsible for preparing and reviewing the Consolidated Statement of Cash Flows. Subsequent to these changes, a reclassification was identified affecting the unaudited interim Condensed Consolidated Statements of Cash Flows for the periods ended September 30, 2009, June 30, 2009 and March 31, 2009. Refer to Note 24. Selected Quarterly Financial Data (unaudited) for further discussion. The reclassifications did not have an impact on the Consolidated Statements of Cash Flows included in this Annual Report on Form 10-K. There were no other changes in our internal control over financial reporting during our fourth quarter of fiscal 2009 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s report on internal controls over financial reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13(a)-15(f) under the Securities and Exchange Act of 1934. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Internal control over financial reporting 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 company; 2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and 3) 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, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. 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. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2009. In making its assessment, management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Based on management’s assessment, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2009 based on the COSO criteria.
Our independent registered public accounting firm, Hein & Associates LLP, independently assessed the effectiveness of the Company’s internal controls over financial reporting. Hein & Associates LLP has issued an attestation report concurring with management’s assessment, which is included herein.
Report of independent registered public accounting firm
To the Board of Directors and Stockholders
Raser Technologies, Inc.
Provo, Utah
We have audited Raser Technologies, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). Raser Technologies, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (a) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (b) 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 (c) 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 the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Raser Technologies, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Raser Technologies, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009 and our report dated March 17, 2010 expressed an unqualified opinion thereon.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 17, 2010
ITEM 9B.
ITEM 9B. Other Information.
None.
PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance.
The information required by this item is included in our definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A of the Exchange Act in connection with our 2010 annual meeting of stockholders and is incorporated herein by reference. In addition, we refer you to Part I of this report.
ITEM 11.
ITEM 11. Executive Compensation.
The information required by this item is included in the proxy statement referred to above and is incorporated herein by reference.
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is included in the proxy statement referred to above and is incorporated herein by reference.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence.
The information required by this item is included in the proxy statement referred to above and is incorporated herein by reference.
ITEM 14.
ITEM 14. Principal Accounting Fees and Services.
The information required by this item is included in the proxy statement referred to above and is incorporated herein by reference.
ITEM 15.
ITEM 15. Exhibits, Financial Statement Schedules.
# Management contracts or compensation plans or arrangements in which directors or executive officers are eligible to participate.
 Confidential treatment has been requested for portions of this exhibit.
* To be filed herewith.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Nicholas Goodman and Richard D. Clayton, and each or any one of them, as his true and lawful attorney-in-fact and agent, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capabilities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his substitute or substituted, may lawfully do or cause to be done by virtue hereof.
Pursuant to the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:
RASER TECHNOLOGIES, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Raser Technologies, Inc.
Provo, Utah
We have audited the accompanying consolidated balance sheets of Raser Technologies, Inc. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Raser Technologies, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their consolidated operations and their consolidated cash flows for each of the three years in the period ended December 31, 2009 in conformity with United States generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has suffered recurring losses, has used significant cash for operating activities since inception, has significant purchase commitments in 2010 and has a lack of sufficient working capital. This raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
As described in Note 17 to the financial statements, effective January 1, 2009, the Company adopted a new accounting policy related to its accounting for warrants that have contingent exercise prices in certain circumstances. The accounting change resulted in the fair value of these warrants being classified from equity to a liability.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Raser Technologies, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 17, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 17, 2010
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
See accompanying notes to consolidated financial statements.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
See accompanying notes to consolidated financial statements.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Consolidated Statement of Stockholders’ Equity
(a) Under the Line of Credit, each lender received warrants (each a “Warrant”) to purchase our common stock for each advance of funds made under the Line of Credit. The number of shares underlying each Warrant is equal to 50% of the total amounts funded by the applicable lender divided by the closing price of our common stock on the date of the advance. The Warrants have an exercise price of $6.00 per share.
See accompanying notes to consolidated financial statements.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
See accompanying notes to consolidated financial statements.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1. Nature of Business and Basis of Presentation
Nature of Business
We are an environmental energy technology company focused on geothermal power development and technology licensing. We operate two business segments: Power Systems and Transportation & Industrial. Our Power Systems segment develops geothermal electric power plants and anticipates also developing bottom-cycling operations in the future. Our Transportation & Industrial segment focuses on using our Symetron™ family of technologies to improve the efficiency of electric motors, generators and power electronic drives used in electric and hybrid electric vehicle propulsion systems. Through these two business segments, we are employing a business strategy to produce a positive impact on the environment and economically beneficial results for our stockholders. By executing our business strategy, we aim to become a producer geothermal electric power as well as a provider of electric and hybrid-electric vehicle technologies and products.
Power Systems Segment
Our power systems segment focuses on the development of geothermal power plants. Our geothermal resources portfolio consists of over 275,000 acres in the United States and a concession of over 100,000 acres in Indonesia. These geothermal interests are important to our ability to develop geothermal power plants.
We have initiated the development of eight geothermal power plant projects in our Power Systems segment to date. We have placed one power plant in service to date, which we refer to as our Thermo No. 1 plant, and we are currently selling electricity generated by the Thermo No. 1 plant. The Thermo No. 1 plant is currently generating approximately 7 MW of electrical power (gross). After deducting the electricity required to power the plant, also known as parasitic load, the net power produced by the Thermo No. 1 plant is approximately 6 MW. In addition we also purchase power for remote pumps in our well field, which are required to ensure adequate flow of hot water. Both the gross output and the net output of the plant are below the amounts the plant was designed to produce, primarily due to issues related to the temperature of the resource from the well field. We are working to improve the electrical output of the plant and the temperature of the resource.
Our Thermo No. 1 plant was the first geothermal power plant to be constructed utilizing PureCycle 280 generation units (“PureCycle units”) manufactured by PWPS. The PureCycle units are small, modular units producing approximately 280 kilowatts (“kW”) of gross electrical output each. We installed fifty PureCycle units at the Thermo No. 1 plant.
Our ability to develop our geothermal power projects is dependent on our ability to obtain adequate financing to fund those projects. These alternatives could include government funding from grants, loan guarantees or private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, pre-paid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. We cannot be certain that funding from any of these sources will be available. If we are unable to secure adequate funds on a timely basis on terms acceptable to us, we may need to modify our current plans for plant construction, well field development and other development activities, extend the time frame over which these activities will take place, or cease operations.
We originally financed the construction of the Thermo No. 1 plant through project financing and tax equity financing arrangements. Subsequent to the adoption of the Recovery Act, we amended these financing arrangements to be consistent with the Recovery Act and take advantage of the grants available under the Recovery Act. We obtained a grant of approximately $33.0 million, which we received in February 2010.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Approximately $3.8 million of the grant funds were released to us, as owner of the project. The remainder of the grant funds will be held in escrow until June 30, 2010, and the amounts to be released to the other parties that provided the debt and equity financing for the project will be determined based on the electrical output of the plant at that time. Up to $4.3 million of any amounts not released to these parties will be paid to Pratt Whitney Power Systems (“PWPS”) as final payment for the turbines installed at the Thermo No. 1 plant. Any remaining amount, after the payment to PWPS, will be released to us.
Transportation & Industrial Segment
Our Transportation & Industrial segment focuses on commercializing our electric motor, generator and drive technologies, such as our series plug-in hybrid vehicle (“PHEV”) with range extender technologies, into applications. In 2008, we began work to integrate a Symetron™ traction motor, generator and controller drive in a Hummer H3 demonstration vehicle (“Hummer Demonstration Vehicle”). The Hummer Demonstration Vehicle was built under a collaborative arrangement with General Motors, Inc. (“General Motors”) and our integration partner FEV, Inc. The Hummer Demonstration Vehicle was designed to achieve 100 mpg equivalent to demonstrate the benefits of our plug-in electric drive system in Sports Utility Vehicles (“SUVs”) and light truck applications. Our plug-in electric drive system is designed to allow light trucks and SUVs to achieve the equivalent of over 100 mpg in typical local daily driving with near zero emissions, by using electricity instead of petroleum as the primary fuel. Recently, General Motors decided to discontinue the Hummer brand. We believe, however, that our technology is capable of being used in other types of SUVS and light truck applications.
We completed the initial phase of developing our Hummer Demonstration Vehicle and unveiled the prototype at the 2009 SAE International World Congress, in Detroit Michigan. We are currently in the process of further testing the Hummer Demonstration Vehicle and seeking a manufacturing partner for small scale manufacturing of additional prototype vehicles. We also expect to begin to realize modest revenues from the sale of enhanced motors and generators through our business cooperation agreement with HHI, although the exact amount and timing of these revenues will be dependent on HHI’s ability to implement these enhanced designs into its manufacturing and distribution system which we anticipate to occur during 2010.
We are also currently evaluating the advantages and disadvantages of a possible business separation transaction involving the Transportation and Industrial segment, which may include spinning off the Transportation and Industrial business to our stockholders as a separate independent company. However, we may ultimately determine that a business separation transaction involving the Transportation and Industrial segment is not feasible for financial, legal or other reasons. For a discussion of the revenues, profit/loss and total assets of the Transportation and Industrial segment for the years ended December 31, 2009, 2008 and 2007, please see Note 20. “Business Segments” in our audited consolidated financial statements.
Basis of Presentation
The consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. In 2008 and 2007, our financial statements were presented as a development stage company. However, in April 2009, we began selling electricity generated by our Thermo No. 1 plant to the City of Anaheim. Accordingly, we believe that we transitioned from a development stage company to an operating stage company during the second quarter of 2009.
As reflected in the accompanying consolidated financial statements, as of December 31, 2009, we had cash and cash equivalents on hand of $41,800 and accounts payable and accrued liabilities of $16.7 million. Cash used in operations totaled approximately $23.5 million for the year ended December 31, 2009 and the accumulated
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
deficit totaled $109.7 million. We have incurred substantial losses since inception and we are not operating at cash breakeven.
Our continuation as a going concern is dependent on efforts to secure additional funding, increase revenues, reduce expenses, and ultimately achieve profitable operations. The current economic environment will make it challenging for us to access the funds that we need, on terms acceptable to us, to successfully pursue our developmental plans and operations. The cost of raising capital in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. If we are unable to raise sufficient, additional capital on reasonable terms, we may be unable to satisfy our existing obligations, or to execute our plans. In such a case, we would be required to curtail or cease operations, liquidate or sell assets, modify our current plans for plant construction, well field development or other development activities, or pursue other actions that would adversely affect future operations.
Although we raised substantial proceeds during the year ended December 31, 2009, we have used or committed a substantial portion of these proceeds to fund our operations and development efforts. Further, we are not currently generating enough revenues to cover our operating costs, and our cash and cash equivalents will continue to be depleted by our ongoing development efforts. Until we are in a position to generate significant revenues, we will need to continue to raise additional funds to continue operating as a going concern. We may seek this additional funding through the issuance of debt, preferred stock, equity or a combination of these instruments. We may also acquire financing through government funding from grants, loan guarantees and private activity bonds, joint ventures, the sale of one or more of our projects or interests therein, entry into prepaid power purchase agreements with utilities or municipalities, or a merger and/or other transaction, a consequence of which could include the sale or issuance of stock to third parties. The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets or the amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.
New Accounting Pronouncements (adopted in 2009)
In October 2009, the FASB issued new accounting guidance relating to multiple-deliverable revenue arrangements. The new accounting guidance changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable to be based on the relative selling price. The selling price used for each deliverable should be based on vendor-specific objective evidence if available, third-party evidence if vendor specific evidence is not available, or the estimated selling price. Although the effective date of this new pronouncement is January 1, 2011, early adoption is permitted. We elected to adopt this new guidance effective January 1, 2010 which had no material impact on our financial condition, results of operations or cash flows in prior years.
In September 2009, the FASB issued new accounting guidance to provide implementation guidance for uncertainty in income taxes for “pass through entities.” The amendments clarify that management’s determination of the taxable status of the entity is a tax position subject to the standards required for accounting for uncertainty in income taxes. This new guidance became effective on July 1, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
In August 2009, the FASB issued new accounting guidance to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. This new guidance became effective on July 1, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
In June 2009, the FASB issued new accounting guidance relating to codification of accounting principles and authoritative hierarchy. On the effective date of this Statement, the Codification superseded all existing non-SEC accounting and reporting standards. All other non-grandfathered, non-SEC accounting literature not included in the Codification will become non-authoritative. The new accounting guidance was effective for financial statements issued for interim and annual periods ending after September 15, 2009. We implemented this guidance on July 1, 2009, and it had no material impact on our financial condition, results of operations, or cash flows.
In March 2008, the Financial Accounting Standards Board (the “FASB”) issued new accounting guidance relating to disclosures about derivative instruments and hedging activities. The new accounting guidance is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, results of operations and cash flows. The new standard also improves transparency about how and why a company uses derivative instruments and how derivative instruments and related hedged items are accounted for under the Accounting Standards Codification. It is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We adopted this new accounting guidance effective January 1, 2009 and addressed the relevant disclosures accordingly.
In December 2007, the FASB issued new accounting guidance relating to non-controlling interests in consolidated financial statements. In the new accounting guidance, the FASB established accounting and reporting standards that require non-controlling interests to be reported as a component of equity, changes in a parent’s ownership interest while the parent retains its controlling interest to be accounted for as equity transactions, and any retained non-controlling equity investment upon the deconsolidation of a subsidiary to be initially measured at fair value. This new accounting guidance was effective January 1, 2009 and retroactive application was prohibited. We adopted this new accounting guidance effective January 1, 2009 which primarily resulted in moving the presentation of non-controlling interest to the “Stockholders’ equity” section of our condensed consolidated balance sheets.
We also adopted the recent accounting revisions relating to the classification and measurement of redeemable securities. The accounting revisions require that securities with redemption features that are not solely within the control of the company should be classified outside of permanent equity as temporary equity. We adopted these revisions effective January 1, 2009. As a result of the adoption, we classified “non-controlling interest” as temporary equity outside of the permanent equity section.
In December 2007, the FASB issued new accounting guidance relating to collaborative arrangements. This new accounting guidance prescribes the accounting for parties of a collaborative arrangement to present the results of activities for the party acting as the principal on a gross basis and report any payments received from (made to) other collaborators based on other applicable GAAP or, in the absence of other applicable GAAP, based on analogy to authoritative accounting literature or a reasonable, rational, and consistently applied accounting policy election. Further, this new accounting guidance clarified the determination of whether transactions within a collaborative arrangement are part of a vendor-customer (or analogous) relationship, subject other accounting considerations. This new accounting guidance is effective for collaborative arrangements that exist on January 1, 2009 and application is retrospective. We adopted this new accounting guidance effective January 1, 2009 and the adoption had no material effect on our financial position or results of operations.
In June 2008, the FASB ratified new accounting guidance relating to determining whether an instrument (or embedded feature) is indexed to our own stock. The new accounting guidance provides that an entity should use a two-step approach to evaluate whether an equity-linked financial instrument (or embedded feature) is indexed
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
to its own stock, including evaluating the instrument’s contingent exercise and settlement provisions. It also clarifies the impact of foreign currency denominated strike prices and market-based employee stock option valuation instruments on the evaluation. This new accounting guidance was effective for fiscal years beginning January 1, 2009 which we adopted on January 1, 2009. The adoption of this new accounting guidance resulted in our warrants with anti-dilutive provisions being classified as derivatives. For further discussion of the adoption of this new accounting guidance, please refer to Note 17. “Warrants” and Note 19. “Fair Value Measurements” below.
New Accounting Pronouncements (effective in future years)
In January 2010, the FASB issued new accounting guidance relating to improving disclosures about fair value measurement. The new accounting guidance requires new disclosures and clarifies certain existing disclosure requirements about fair value measurements. A reporting entity is required to disclose significant transfers in and out of Level 1 and Level 2 fair value measurements, to describe the reasons for the transfers and to present separately information about purchases, sales, issuances and settlements for fair value measurements using significant unobservable inputs. This new accounting guidance is effective on January 1, 2010, except for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective on January 1, 2011 and early adoption is permitted. We do not expect that the adoption of will have a material impact on our financial position, results of operations or cash flows.
In October 2009, the FASB issued new accounting guidance relating to lending shares in contemplation of convertible debt issuances or other financings. The new accounting guidance amends the accounting and reporting guidance for debt (and certain preferred stock) with specific conversion features or other options. The effective date of this new guidance is January 1, 2010. Since we did not enter into a share lending arrangement upon the issuance of our convertible debt, implementation of this new guidance will not impact on our financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance to improve financial reporting by enterprises involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This new accounting guidance becomes effective as of the beginning of each reporting entity's first annual reporting period that begins after November 15, 2009. Based upon current assumptions, we believe that adoption of this new accounting guidance will not immediately change the designation of our Thermo Subsidiary from being a consolidated entity for financial statement purposes. However, we will continue to evaluate events under this new pronouncement that may result in the deconsolidation of the Thermo Subsidiary as they arise.
No other new accounting pronouncement that became effective during the current fiscal year had or is expected to have a material impact on our consolidated financial statements.
Concentration of Credit Risk
We maintain a portion of our available unrestricted cash in deposit accounts in two banks in Utah. At times, cash balances in these accounts may exceed federally insured limits. From time to time, we purchase investments in marketable debt securities as a means of temporarily investing the proceeds from financings until the funds are needed for operating purposes. Due to the nature of these investments, we consider it reasonable to expect that their fair market values will not be significantly impacted by a change in interest rates, and that they can be liquidated for cash on short notice. Our investments are intended to establish a high-quality portfolio that preserves principal, meets liquidity needs, avoids inappropriate concentrations and delivers an appropriate yield in relationship to our investment guidelines and market conditions. Concentration of credit risk is normally managed by diversifying investments among a variety of high credit-quality issuers.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
We invest a portion of our unrestricted cash in an AIM Funds money market account, which is not affiliated with the bank where we maintain our deposit accounts. The money market account earns interest based on a variable rate. At December 31, 2009, our balance in the money market account was $11,600 and the interest rate applicable to the money market account was 0.10 percent per annum. The average interest rate applicable to the money market account during the quarter ended and year ended December 31, 2009 was 0.12 percent and 0.24 percent per annum, respectively.
Cash from our checking account is swept nightly into an interest bearing account. At December 31, 2009, we had a balance of $18,700 in this sweep account and the interest rate applicable to the sweep account was 0.50 percent per annum. We also maintain cash in a non-interest bearing deposit account and an interest bearing money market account at a separate bank. At December 31, 2009, we had a balance of $10,800 in these account and the interest rate applicable to the money market account was 0.10 percent per annum.
Project financing proceeds received by our subsidiaries are subject to the terms and conditions of those arrangements. An independent administrative agent was appointed to administer all of the Thermo Subsidiary’s cash deposits and disbursements. The independent administrative agent deposited our restricted cash into a money market fund managed by the JP Morgan Fund, which earns interest at a variable rate. At December 31, 2009, we had a balance of $9.1 million invested in this money market fund and the interest rate applicable to the fund was 0.00 percent per annum. Due to the nature of the investments included in the money market accounts, we consider it reasonable to expect that the fair market values of these investments will not be significantly impacted by a change in interest rates, and that they can be liquidated for cash on short notice.
On December 4, 2009, we entered into a Redemption Agreement (“the Redemption Agreement”) with Merrill Lynch (the “Class A Member”). Pursuant to the Redemption Agreement, the Class A Member withdrew from the Thermo Subsidiary effective on December 11, 2009. Concurrently, we issued a promissory note payable to redeem the Class A Member for up to $24.5 million, subject to certain conditions relating to the timing and receipt of our 30% grant under Section 1603 of the American Recovery and Reinvestment Act of 2009 (the “Recovery Act”). On February 19, 2010, we received $33.0 million from the 30% grant under Section 1603 of the Recovery Act which resulted in the promissory note payable’s principal balance being adjusted to up to $20.0 million. Although the Class A Member had withdrawn from the Thermo Subsidiary, the Thermo Financing Agreements were not amended with respect to the establishment of an independent administrative agent primarily to maintain the rights and privileges previously granted to the current holder of the Thermo Subsidiary debt. Accordingly, the independent agent continues to administer all of the Thermo Subsidiary’s cash deposits and disbursements.
We reviewed the underlying investments included in the money market accounts described above and concluded that the money market accounts are properly classified as cash equivalents for financial statement purposes. Due to the nature of the investments included in these money market accounts, we consider it reasonable to expect that the fair market values of these investments will not be significantly impacted by a change in interest rates, and that they can be liquidated for cash on short notice. We have not experienced losses in our money market accounts, and we believe that we are not exposed to any significant credit risks relating to our money market accounts.
We have also invested $76,900 into a certificate of deposit for the sole purpose of covering the credit limit on our corporate credit card and minimize the credit risk to the bank. The certificate of deposit matured on March 1, 2010. We rolled the outstanding balance on March 1, 2010 of $77,100 into a new certificate of deposit which matures on September 1, 2010 and bears an interest rate of 0.25%. Since this certificate of deposit is guaranteed by the FDIC, we believe that we are not exposed to any significant credit risks relating to our certificate of deposit.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Concurrent with the issuance of our Convertible Notes, we entered into a Pledge and Escrow Agreement that required us to utilize approximately $8.7 million of the gross proceeds to purchase a portfolio of U.S. Treasury Strips that were placed in escrow to secure the payment of the first four interest payments on the Convertible Notes. As of December 31 2009, we had used proceeds from these U.S. Treasury Strips to pay the holders of the Convertible Notes three semi-annual interest payments. Accordingly, the remaining portfolio of U.S. Treasury Strips that were placed in escrow approximates $2.2 million. The effective interest rates applicable to these U.S. Treasury Strips range from 1.44% to 1.72 % per annum. Since these U.S. Treasury Strips are backed by the United States government, we believe that we are not exposed to any significant credit risk relating to these government securities.
During the year ended December 31, 2009, we sold electricity generated by our Thermo No. 1 plant to the City of Anaheim in accordance with our power purchase agreement. Pursuant to power purchase agreement, we invoice the City of Anaheim within 15 days after each month end for the previous month’s activity. The City of Anaheim is required to remit payment to us within 15 days after receiving the invoice. We do not believe that we are exposed to any significant credit risks relating to collecting payments in accordance with our power purchase agreement.
Note 2. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include our accounts and the accounts of our consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made in the prior year’s consolidated financial statements to conform to the current year presentation.
In August 2008, we entered into various financing arrangements in which we sold Class A membership in Thermo No. 1 BE-01, LLC (the “Thermo Subsidiary”) to Merrill Lynch (the “Class A member”) for $24.5 million representing 78.7% of the agreed-upon value of the Thermo Subsidiary which was $31.1 million. We, through our wholly owned subsidiary maintained the Class B membership representing 21.3% of the agreed-upon value.
Under the financing arrangements, the tax benefit and profit/loss allocations is 1% to the Class B member and 99% to the Class A Member until the Class A Member achieves a 15% internal rate of return (“IRR”) on the project. Upon achieving a 15% IRR, the equity ownership would have automatically flipped so that 95% of the tax benefits and profit/loss allocations flowed to us through the Class B Member and 5% to the Class A Member.
According to financing agreements between the Class A Member and us, we also contributed as equity to Thermo No. 1 the fair value of six leases (640 acres of current well field and 10,000 additional acres of surrounding leased property) totaling approximately $29,500 to serve as security collateral for the Class A Member’s financing. We also contributed as equity to Thermo No. 1 completed well field costs of approximately $26.8 million.
In 2008, we evaluated the Class A and Class B member voting rights, the minority holder’s substantive participative and protective rights, and conditions outlined in variable interest entity accounting guidance and determined that the financing arrangement should not be classified as a variable interest entity and that the subsidiary should continue to be consolidated for financial statement purposes.
On December 4, 2009, we entered into a series of agreements with the Class A Member that amended the provisions of the August 2008 financing arrangements noted above. These amendments were necessary to allow
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
the Thermo Subsidiary to apply for a grant under Section 1603 of the Recovery Act (the “Grant”). Pursuant to the amendments, we transferred the cost overruns, net of amortization, incurred as the EPC contractor on the Thermo No. 1 plant to the Thermo Subsidiary totaling approximately $25.9 million. On December 4, 2009, we also amended the LLC Agreement. Pursuant to the amended LLC Agreement, the Class A member withdrew from the Thermo Subsidiary and the tax benefit and profit/loss allocations changed to 0% to the Class A Member and 100% to the Class B Member, effective December 11, 2009. Concurrently, on December 4, 2009, we entered into a Redemption Agreement with the Class A Member. Pursuant to the Redemption Agreement, we issued a promissory note payable to redeem the Class A Member for up to $24.5 million, subject to certain conditions including the timing and receipt of the Grant. On February 19, 2010, we received $33.0 million in cash from the Grant which resulted in reducing the maximum principal balance of the promissory note payable to $20.0 million due to the timing and amount of the Grant, per the Redemption Agreement.
As of December 31, 2009, based upon this change in ownership in the Thermo Subsidiary, we evaluated the conditions outlined in the variable interest entity accounting guidance and determined that the Thermo Subsidiary should not be classified as variable interest entity under the new financing arrangement and that the Thermo Subsidiary should continue to be consolidated for financial statement purposes. In determining whether our subsidiaries should be classified as variable interest entities, we must make judgments about whether the subsidiary is a variable interest and other conditions outlined in variable interest entity accounting guidance. If these judgments prove to be incorrect, it could result in the deconsolidation of our subsidiary and have a material impact on our results of operations and financial position.
Use of Estimates
The preparation of consolidated financial statements in conformity with United States Generally Accepted Accounting Principles (“GAAP”) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ significantly from those estimates.
Fair Value of Financial Instruments
The carrying amounts reported in the accompanying consolidated financial statements for cash and cash equivalents, restricted cash, accounts receivable, notes receivable, interest receivable, accounts payable and accrued liabilities approximate fair values because of the immediate or short-term maturities of these financial instruments. See Note 19. “Fair Value Measurements” for additional discussion below.
The carrying value and estimated fair value of our debt instruments at December 31, 2009 were as follows:
* Represents the face value of the debt without consideration of the deferred financing costs of $33,399 as of December 31, 2009.
** Represents the face value of the debt without consideration of the imputed interest rate of 15% from December 11, 2009 to June 30, 2010 resulting in a discount of $1,232,846 as of December 31, 2009.
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Notes to Consolidated Financial Statements-(Continued)
*** Due to the original issue discount, cash proceeds of debt are less than the face value of the debt. Therefore, the effective interest rate of 9.5% is greater than the 7% stated rate. Represents face value of debt without consideration of the amortized original issue discounts as of December 31, 2009 and 2008 totaling $4,469,479 and $4,952,505, respectively.
The estimated value of our short-term 10.00% amended unsecured line of credit, long term 15.00% promissory note, and long-term 9.50% senior secured note was determined by management who based its judgment relating to fair value on discounted cash flow analysis that were developed with the assistance of a third-party valuation consultant. Our cash flow model utilized the projected cash outflows and a discount rate, which was derived from market and non-market inputs. Our estimate of the value of our short-term 10.00% amended unsecured line of credit, long term 15.00% promissory note, and long-term 9.50% senior secured note secured note depends on judgments relating to the projected cash flows and discount rate. If these judgments prove to be incorrect, it could have a material effect on our results of operations and financial position.
To estimate the fair value of our long-term 8.00% convertible senior note, we used a market pricing service that estimated the fair value based upon theoretical values based on assumptions that market participants would use to price the convertible notes.
Cash and Cash Equivalents
All highly liquid investments with an original maturity of three months or less are classified as cash equivalents.
Restricted Cash
Restricted cash at December 31, 2009 consisted of a $76,900 certificate of deposit held with a bank to secure a credit card purchasing arrangement utilized to facilitate employee travel and certain ordinary purchases for our business operations. The certificate of deposit earned 1.0% interest per annum until it matured on September 1, 2009. On September 1, 2009, we rolled over the amount from the previous certificate of deposit into new certificate of deposit that earned 0.50% interest per annum and matured on March 1, 2010. On March 1, 2010, we rolled over the amount from the previous certificate of deposit into a new certificate of deposit that earns 0.25% and matures on September 1, 2010.
On August 31, 2008, we and our subsidiary Thermo No. 1 BE-01, LLC (the “Thermo Subsidiary”) entered into a debt financing and tax equity capital arrangement with Merrill Lynch, the Class A Member, for the construction of our Thermo No. 1 plant. Under the arrangement, Merrill Lynch provided debt financing totaling $26.1 million, net of an original issue discount of $5.0 million and $24.5 million of tax equity capital. In addition, we contributed approximately $29.0 million, primarily of well field drilling costs that we had incurred to that date and agreed to make additional capital contributions as necessary to cover the costs to complete the well field. Pursuant to the arrangement, both parties agreed that the cash held at the Thermo Subsidiary would be restricted for use to complete the construction, service the debt and provide for continued operations of the Thermo No. 1 plant. The Thermo Subsidiary cash is located in separate cash accounts which are administered by Deutsche Bank.
On December 4, 2009, we entered into a series of agreements with the Class A Member that amended the provisions August 2008 financing arrangements noted above. On December 4, 2009, we amended the LLC Agreement in which the Class A member withdrew from the Thermo Subsidiary and the tax benefit and profit/loss allocations changed to 0% to the Class A Member and 100% to the Class B Member to be effective on
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Notes to Consolidated Financial Statements-(Continued)
December 11, 2009. Concurrently, on December 4, 2009, we entered into a Redemption Agreement with the Class A Member. Pursuant to the Redemption Agreement, we issued a promissory note payable to redeem the Class A Member for up to $24.5 million, subject to certain conditions relating to the timing and receipt of our 30% grant under Section 1603 of the Recovery Act. On February 19, 2010, we received $33.0 million from the 30% grant under Section 1603 of the Recovery Act which resulted in the promissory note payable’s principal balance being adjusted to up to $20.0 million. Although, the Class A Member had withdrawn from the Thermo Subsidiary, the Thermo Financing Agreements were not amended with respect to the establishment of an independent administrative agent primarily to maintain the rights and privileges previously granted to the current holder of the Thermo Subsidiary debt. Accordingly, the independent agent continues to administer all of the Thermo Subsidiary’s cash deposits and disbursements.
Since the Thermo Subsidiary cash is restricted for use, we record their cash accounts as restricted cash. As of December 31, 2009 and 2008, the Thermo Subsidiary maintained restricted cash balances of $9.1 million and $20.9 million, respectively. The Thermo Subsidiary cash is to be used to pay accounts payable relating to the construction of the plant, well field development, plant operations and to fund the distribution account and other reserve accounts.
Investments
We classify investment securities as either available-for-sale or held-to-maturity. Available-for-sale securities and are recorded at fair market value, based on quoted market prices, and unrealized gains and losses are recorded as a component of comprehensive income (loss). Realized gains and losses, which are calculated based on the specific-identification method, are recorded in operations as incurred. We did not have short-term investments classified as available-for-sale during the years ended December 31, 2009 and 2008, respectively. Accordingly, there was no unrealized gain or loss relating to available-for-sale short-term investments recorded for the years ended December 31, 2009 or 2008, respectively.
Held-to-maturity securities include U.S. Government Strips that have coupon dates and coupon amounts that correspond with the amount of interest payable for the April 2010 semi-annual interest payments to the holders of our Convertible Notes. The held-to-maturity securities are carried and amortized at cost.
Available-for-sale and held-to-maturity securities are assessed for impairment periodically. To determine if the impairment is other-than-temporary, we consider the duration and severity of the loss position, the strength of the underlying collateral, the term to maturity, and credit rating. For investments that are deemed other-than-temporarily impaired, losses are recorded and payments received on these investments are recorded using the cost recovery method. Since our investments are backed by the United States government, we believe that no impairment occurred during 2009. All of our current investments in securities consist of held-to-maturity securities backed by the United States Government. As a result, we do not believe there was any impairment of our investments in held-to-maturity securities during 2009 or 2008, respectively. In determining whether there was any impairment of available-for-sale and held-to-maturity securities, we must make judgments relating to the classification of our investments as either available-for-sale or held-to-maturity. If these judgments prove to be incorrect it could have an adverse effect on our results of operations and financial position.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable are carried at original invoice amount less an estimate made for doubtful receivables based on a review of all outstanding amounts on a periodic basis. Management estimates an allowance for doubtful accounts by identifying aged delinquent accounts determined by contractual terms and by using historical experience. Accounts receivable are written off when deemed uncollectible. Recoveries of accounts
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Notes to Consolidated Financial Statements-(Continued)
receivable previously written-off are recorded when received as a credit to the allowance. Based upon our review of the payment history and the current credit ratings of the City of Anaheim, management believes that no reserve is necessary for our outstanding accounts receivable at December 31, 2009. The accounts receivable balance relating to the City of Anaheim was collected in January 2010.
Accounting for Geothermal Energy Activities
Each geothermal power project we develop consists of three phases. During the first phase, the site is identified and evaluated. During the second phase, the power plant, transmission lines and pipelines are constructed and the production and reinjection wells are drilled. The third and final phase is the production phase, during which the power plant is operated over its useful life. We consider “development” to mean the time after initial exploration is complete but before the plant is placed into service. The order in which development activities are conducted may vary depending on the unique characteristics of each site.
Site Identification and Evaluation
The first step in the site identification and evaluation phase is the identification of potential project sites. As part of the identification process, we incur a variety of costs, which may include costs for topographical studies, geological and geophysical studies, rights to access and study properties, technical materials and maps. Regardless of whether we pursue a project at a particular site, all of the costs associated with the identification of a potential site are considered exploratory in nature and are expensed as incurred.
The next step in the site identification and evaluation phase is land acquisition, pursuant to which we acquire land, lease land, or otherwise obtain the appropriate property interests to develop a potential project. Lease acquisition costs, including lease bonuses, legal costs, permit costs, and the fair value of other forms of compensation to acquire leases are capitalized as power project leases when incurred. The power project leases are not amortized until the related power plant constructed on the leased property is placed in service. At that time, the related power project leases are capitalized as geothermal property plant and equipment and amortized over the estimated useful life of the geothermal power plant. From time to time, we also purchase land outright to develop. Any land we purchase outright is not amortized and is stated in our financial statements at historical cost.
Once we have acquired an interest in a geothermal property, we also incur costs to carry and maintain the undeveloped property until we are in a position to determine whether or not to pursue a project on the property. These costs can include delay rentals, certain taxes on the properties, legal costs for title defense, and the maintenance of land and lease records. All of these costs are expensed when incurred.
After, or occasionally prior to, the time we acquire an interest in a property, we conduct additional internal and external studies to determine whether to initiate the development of a project at the site. As part of this process, we may drill slim holes or conduct other activities to help identify the general location and characteristics of the potential geothermal resource. All of these costs, including slim holes, are considered exploratory in nature and are expensed as incurred
Well Drilling and Plant Construction
We only decide to pursue a project at a site if we determine, with a high degree of confidence, that; (i) the site contains an adequate renewable geothermal resource to support a power plant that will continually produce electricity without any substantial degradation of the heat resource; and (ii) we can effectively transmit and sell
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Notes to Consolidated Financial Statements-(Continued)
the electricity generated at a facility. Once we have made this determination for a site, the project begins the second development phase, which consists of drilling production and reinjection wells, as well as constructing the power plant, transmission lines and pipelines from the well field to the power generating units.
Before drilling and construction can begin, we must obtain the appropriate permits. Permitting costs are capitalized as part of the project costs. We capitalize permitting costs and record them as either well field development-in-progress or construction-in-progress.
After obtaining appropriate permits, we begin to develop the well field for the project by drilling large diameter production holes. In general, these holes are 20 to 22 inches in diameter at the surface and telescope down to between nine (9) and fourteen (14) inches, depending upon the depth of the well and other conditions. Each hole we drill will result in either a production well, a reinjection well, or an unsuccessful well. Production wells and reinjection wells will ultimately be used in the production of electricity at the geothermal power plant. Therefore, drilling costs for production wells and reinjection wells are capitalized. Drilling costs associated with unsuccessful wells are expensed in the period in which we determine they cannot be used in the production of electricity. Capitalized costs associated with well field development-in-progress are reclassified as geothermal property, plant and equipment once the plant is placed in service and amortized over the estimated useful life of the plant, or 35 years.
Construction of the geothermal power plant, the related transmission lines and the required substation normally occur either concurrent with or subsequent to the drilling of the production and reinjection wells. The costs associated with construction of the power plant and related transmission lines are accumulated and capitalized over the construction period. We begin to depreciate the construction related costs over the estimated useful life of the plant once the power plant is placed in service. The estimated useful life of our power plants is estimated to be 35 years.
As part of the financing for a project, we incur costs to obtain a report from an independent engineer verifying the production capacity of the well field. The costs associated with the engineer’s report are expensed as consulting costs and other financing-related costs, such as legal costs, broker fees, and accounting fees are capitalized when incurred.
Although we placed the Thermo No. 1 plant in service in the first quarter of 2009, we have experienced certain difficulties in ramping up the production of electricity at the Thermo No. 1 plant to full capacity. In light of these difficulties, we have drilled additional new wells and performed certain recompletion work to stimulate and improve the existing wells to increase the output of electrical production at the power plant since we placed the power plant into service. The costs associated with the additional drilling and recompletion work are also capitalized as betterments that increase production and the useful life of the wells as incurred. These costs are amortized over the estimated useful life of our power plants or 35 years. We have made significant judgments with respect to the capitalization of drilling costs. Our financial results could differ if we had made different judgments relating to the capitalization of drilling costs or if management’s judgments prove to be incorrect.
Certain tax incentives are available to us through these renewable energy projects. Some of these tax incentives, such as the Internal Revenue Code Section 45 production tax credit, have “placed in service” deadlines in order to qualify for such incentives. We have incurred and may incur in the future, significant additional costs during this phase in order to meet the placed in service deadline. In 2008, the deadline for use of the production tax credit relating to geothermal power plants was extended to December 31, 2013, subject to future extensions. Also refer to discussion of the U.S. Department of Treasury grant under Section 1603 of the Recovery Act below.
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Notes to Consolidated Financial Statements-(Continued)
Production Phase
The final phase of a project is the energy production phase. The energy production phase begins when the plant begins selling electricity to a third party in accordance with a power purchase agreement. Operating costs incurred during the energy production phase are expensed as incurred. Prepaid commissions, if any, pursuant to power purchase agreements relating to the project are amortized over the life of agreements. In April 2009, we began selling electricity produced at the Thermo No. 1 plant to the City of Anaheim. Accordingly, we also began amortizing prepaid commissions over the life of the power purchase agreements.
Capitalization of Costs
Our determination to move forward with the process to construct the power plant, transmission lines, production wells and pipelines for a geothermal power project is based on management’s determination, with a high degree of confidence, that a given site contains adequate renewable geothermal resources to support a plant that will continually produce electricity without any substantial degradation of the heat resource. This determination involves significant management judgment and is based on the information available at the time. Once this determination has been made, we begin to capitalize certain construction-related costs. Although management’s determination to proceed with construction activities and capitalize construction-related costs is based on a high degree of confidence that a sufficient geothermal resource exists, the information available and the uncertainties associated with potential geothermal resources could later prove our management’s judgments to be incorrect. If management’s judgments with respect to a project prove to be incorrect, we may have to write-off significant costs associated with that project that were previously capitalized, which could have a material adverse effect on our results of operations.
With respect to the power generating units at our Thermo No. 1 plant, we expect to incur maintenance costs each five years to maintain the optimal operating efficiency of the power plant. Under current accounting guidance, we may elect to either capitalize the planned major maintenance costs and amortize the costs over the five year period or expense the costs when incurred. We estimate that the actual planned major maintenance costs may range between $3.0 million and $4.0 million at each planned maintenance event. Since the PureCycle units are based upon a new technology, there is no historical basis to estimate what the actual costs will be. Therefore, we have elected to recognize the planned major maintenance costs when incurred which will have the effect of increasing the operating costs in those years that the planned major maintenance costs are incurred.
Interest costs associated with the development of our well fields and construction of our power plants are capitalized during the period for which the development and construction activities are in progress. Interest ceases to be capitalized when the power plant is placed in service. See Note 5. “Geothermal Property, Plant and Equipment”, Note 7. “Geothermal Well Field Development-in-Progress”, and Note 8. “Power Project Construction-in-Progress” for amounts of interest capitalized.
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Notes to Consolidated Financial Statements-(Continued)
Property, plant and equipment
Property, plant and equipment are stated at cost. Geothermal power plants and related transmission equipment, production and re-injection wells, and power project leases for properties on which the applicable geothermal power plant and related wells are located are capitalized at cost and depreciated or amortized over the estimated useful life of the geothermal power plant when it is placed in service. Equipment is recorded at cost and is depreciated over the estimated useful life of the related asset. Depreciation and amortization are computed using the straight-line method for financial reporting purposes. The estimated useful lives are as follows:
As of December 31, 2009, only the Thermo No. 1 plant had been placed in service.
Depreciation expense for the years ended December 31, 2009, 2008 and 2007 totaled $2,551,444, $277,300 and $245,800, respectively.
Expenditures for repairs and maintenance are charged to expense when incurred. Expenditures for major renewals and betterments that extend the useful lives of existing equipment are capitalized and depreciated. Leasehold improvements are depreciated over the remaining life of the lease. Upon retirement or disposition of equipment, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in the consolidated statements of operations.
With respect to the power generating units at our Thermo No. 1 plant, we expect to incur maintenance costs each five years to maintain the optimal operating efficiency of the power plant. We elected to expense our planned major maintenance the costs when incurred.
Intangible Assets
Costs of internally developing, maintaining or restoring patents and trademarks that are specifically identifiable and have determinate lives are capitalized. The costs of patents are amortized on a straight-line basis over the estimated useful life or 20 years from the date of the first filing. The costs of trademarks are capitalized but not amortized because their useful lives are indefinite.
We assess recoverability of our patents by determining whether the amortization of the balance over its remaining life can be recovered through undiscounted future operating cash flows. The amount of impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate which reflects our average cost of funds.
Costs incurred to acquire the global heat transfer technology license have been capitalized and amortized on a straight-line basis over the estimated useful life of the related patents underlying and accompanying the license, or 11.5 years.
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Notes to Consolidated Financial Statements-(Continued)
Costs incurred with obtaining water rights and easements are capitalized and not amortized due to the non-depreciable nature of the asset. Costs to extend or renew the water rights and easements are expensed accordingly. When management determines that the water rights and easements are no longer required, the previously capitalized costs are expensed accordingly.
We periodically review intangible assets for impairment. Abandoned or permanently impaired intangible assets are written off and expensed in the period when the impairment occurs.
Our power project leases are considered contract-based intangible assets and the costs to acquire the power project leases are capitalized accordingly. Costs incurred to extend the terms of the power project lease are considered to be delay rentals and are expensed when incurred. Impairment of the power project leases is evaluated in accordance with accounting guidance which consists of a comparison of the fair value with its carrying amount at the balance sheet date. In accordance accounting guidance, we evaluated our intangible assets as of December 31, 2009, for impairment and determined that none of our intangible assets were impaired.
Deferred Finance Costs
Deferred finance costs are recorded at cost and include costs relating to undertaking debt financing activities. Deferred finance costs are amortized over the life of the maturity of the respective debt based upon the interest method of accounting and recorded as interest expense. Original issue discounts are recorded as reductions to the related long-term debt for financial statement purposes and accreted up to the face value of the respective debt instrument over the life of the maturity of the respective debt and recorded as interest expense. Costs associated with equity financings are recorded as a reduction of additional paid in capital. If related financing is not successfully completed, these costs will be expensed in the period when the related financing is determined to be unsuccessful. At December 31, 2009, our deferred finance costs totaled $6.9 million. The acceleration of debt terms or extinguishment of debt related to those financing fees would result in accelerating the recognition of interest expense in the period in which the event occurred.
Impairment of Long-Lived Assets
We periodically review our long-lived assets, including our well field drilling costs, geothermal power plant and transmission line construction costs, equipment and certain intangible assets for impairment when events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. We evaluate, at each balance sheet date, whether events and circumstances have occurred that indicate possible impairment.
The carrying value of other long-lived assets such as the well field drilling costs, geothermal power plant, transmission line construction costs, equipment and certain intangible assets is considered impaired in accordance with applicable accounting guidance when the anticipated cumulative undiscounted cash flows of the related asset or group of assets is less than the carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the estimated fair value of the long-lived asset using a discount rate which reflects our average cost of funds. We also exercised significant judgments including the assumption that our geothermal power plant will produce electricity over 35 years, a power purchase agreement will be renewed after its expiration at or near the then current terms of our current power purchase agreement, the maintenance costs associated with keeping the power generating units in operating condition after expiration of our current maintenance agreement in 10 years will be adjusted downward to reflect our expected internal costs and escalated at the current contracted rates of the current maintenance agreement over the estimated useful life of the plant over 35 years.
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Notes to Consolidated Financial Statements-(Continued)
In accordance with accounting guidance, we evaluated our long-lived assets for impairment as of December 31, 2009 and determined that none of our long-lived assets analyzed in 2009 have been impaired. However, management has exercised significant judgments with respect to our assumptions included in our impairment analysis. If these judgments prove to be incorrect and result in an impairment of our long-lived assets, it could have a material negative impact on our results of operations and financial position.
For further discussion of the impairment of our well costs, refer to Note 5, “Geothermal Property, Plant and Equipment.” We also determined in the fourth quarter of 2009 that, none of our current wells at our Thermo No. 1 plant should be expensed as non-commercial wells at this time. We will continue to monitor the production levels of our well for future impairment.
Asset Retirement Obligations
We have incurred certain liabilities related to the retirement of assets in connection with drilling wells and constructing the Thermo No. 1 plant. These liabilities include our obligations to plug wells upon termination of our operating activities, dismantle geothermal power plants upon cessation of operations and perform 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 power project lease. Such liability is accreted to its future value each period, and the capitalized cost is amortized over the useful life of the related geothermal power plant or 35 years. As of December 31, 2009, the present value of our asset retirement obligations total $2.7 million. At retirement, we will either settle the obligation for its recorded amount or incur a gain or a loss with respect thereto, as applicable. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, estimated inflation rates, retirement costs and the estimated timing of settling asset retirement obligations.
Derivative Financial Instruments
During the normal course of business, from time to time, we issue warrants and options to vendors as consideration to perform services or settle outstanding debt. We may also issue warrants as part of a debt or equity placement offering. We do not enter into any derivative contracts for speculative purposes.
Warrants that contain round down or price reset features are subject to classification as liabilities for financial statement purposes. Beginning in 2009, as required by the Derivatives and Hedging Topic of the FASB Accounting Standards Codification, we began accounting for our warrants with exercise price reset features as liabilities. These liabilities are measured at fair value with the changes in fair value at the end of each period reflected as current period income or loss unless the derivatives qualify as hedges of future cash flows and are accounted for as such. For warrants that contain certain conditions resulting in the price reset feature becoming fixed upon a contingent event, the fair market value of the warrant liability on the date of the triggering event is reclassified to equity and the liability account is reduced accordingly. We utilize the Black-Scholes option pricing model or a Binomial pricing model to compute the fair value of the liabilities associated with the outstanding warrants, depending upon the complexity of their contractual terms. In computing the fair value of the warrants liabilities at the end of each period, we use significant judgments with respect to the risk free interest rate, the volatility of our stock prices, and estimated life of the warrants. The effects of these judgments, if proven incorrect, could have a significant negative impact to our financial statements. For further discussion, refer to Note 17. “Warrants” and Note 19. “Fair Value Measurements.”
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Notes to Consolidated Financial Statements-(Continued)
Income Taxes
We recognize deferred income tax assets or liabilities for the expected future tax consequences of events that have been recognized in the consolidated financial statements or income tax returns. Deferred income tax assets or liabilities are determined based upon the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates expected to apply when the differences are expected to be settled or realized. Deferred income tax assets are reviewed periodically for recoverability and valuation allowances are provided as necessary. We classify penalties and interest in general and administrative expenses.
Revenue Recognition
Revenue is recognized when earned in accordance with applicable accounting standards and guidance, including Staff Accounting Bulletin or SAB, No. 104, Revenue Recognition, as amended.
Revenue generated through our Power Systems segment is expected to be primarily through the sale of electricity in accordance with power purchase agreements we have executed or intend to execute with investor owned utilities and municipalities. In April 2009, we began generating and selling electricity from our Thermo No. 1 plant to the City of Anaheim. Pursuant to our power purchase agreement with the City of Anaheim, we are required to deliver electricity and the related renewable energy credits produced by our Thermo No. 1 plant. While the electricity is delivered daily, the renewable energy credits are due monthly. Revenue related to the sale of electricity and delivery of the renewable energy credits are recorded based upon electricity output delivered at rates specified under relevant contract terms in accordance with our power purchase agreement. In the State of California, the renewable energy credits cannot be sold separately from the electricity and must be sold under an executed power purchase agreement. In addition, the City of Anaheim has no right of return under the power purchase agreement. Accordingly, the renewable energy credits are not considered to be a separate unit of accounting from the electricity. Therefore, we recognize revenue upon delivery of the electricity.
Prior to April 2009, we began generating and transmitting nominal quantities of “test” electricity at our Thermo No. 1 plant, however we recognized no revenue from the production of this “test” electricity. The power purchase agreement with the City of Anaheim is exempt from derivative treatment due to the normal sales contract exception. Management has made judgments with respect to the classification of the power purchase agreement with the City of Anaheim as a normal sales contract. The effect of these judgments, if incorrect, could have a negative impact on the revenue recognized in our financial statements.
However, since the Thermo Subsidiary is a consolidated entity, these intercompany revenues and fees are eliminated in consolidation.
Revenue from our Transportation & Industrial segment is generated, or expected to be generated from (1) the sale of prototypes of our motors or PHEV demonstration vehicles to private companies for testing and simulation and (2) from fees and royalties generated by the sales of products and solutions of our licensed manufacturing partners. Revenue from subcontracted engineering services is recognized under the percentage of completion method. Costs incurred to achieve the performance criteria are deferred and recognized concurrent with the recognition of revenue unless they are determined to be unrecoverable. For contracts in which the fee is estimated to equal 100% of the cost to complete the contract, we recognize revenue as the cost is incurred to complete the project using zero as our estimate of profit under the percentage-of-completion method. If estimated costs exceed projected revenues for a reporting period, we recognize a loss on the contract. Under the percentage of completion method, changes in the estimated time and cost to complete the contract may affect the time period over which the unrecognized revenues and related costs are recognized.
The revenue from the sale of prototypes is recognized when the prototype is delivered to the customer. We accepted an initial deposit of $200,000 for production of two extended range PHEVs. The initial deposit was
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Notes to Consolidated Financial Statements-(Continued)
recorded as unearned revenue until the vehicle is delivered. Revenue will be recognized pursuant to the percentage of completion method described above. If we accept deposits for vehicles and we are ultimately unable to deliver, the deposit is returned.
Cost of Revenue
Cost of revenue includes direct costs attributable to our operating geothermal power plant including operation and maintenance expenses such as depreciation and amortization, salaries and related employee benefits, equipment expenses, costs of parts and chemicals, costs related to third-party services, lease expenses, royalties, startup and auxiliary electricity purchases, property taxes, insurance and certain transmission charges. Payments made to government agencies and private entities on account of site leases where plants are located are also included in cost of revenue. Royalty payments, included in cost of revenue, are made as compensation for the right to use certain geothermal resources and are paid as a percentage of the revenue derived from the associated geothermal rights.
Equity Based Compensation
From time to time, we issue stock and option awards to employees as compensation for their employment. We record equity based compensation for employees at the fair value of the stock or option award on the grant date. The fair value is recognized over the requisite service period of the employee. Compensation expense is adjusted for equity awards that do not vest due to the fact that service or performance conditions are not satisfied. However, compensation expense already recognized is not adjusted if market conditions are not met, such as when stock options expire “out-of-the-money,” or when options expire unexercised.
For performance-based equity compensation, management assesses the likelihood that the event will successfully occur and computes the fair value of the instrument at each quarterly balance sheet date. When the performance is assessed as “probable,” expense is recognized on a pro rata basis over the estimated service period. When the performance is assessed as less than “probable,” no expense is recognized.
From time to time, we issue shares of common stock, stock options to purchase shares of common stock, and warrants containing underlying shares of our common stock as payment for services or purchase of assets to certain service providers, contractors and other non-employees. We record equity compensation for stock, stock options or warrants issued for services based upon the fair value of the instruments on the earlier of the date of a performance commitment agreement or the date when performance is completed. Expense is recognized over the requisite service period of the stock award.
Stock issued for the purchase of assets or settlement of debt is also valued based on the fair value of the stock on the date the stock is issued or required to be issued per the purchase agreement, or the fair value of the assets acquired, whichever is more readily determinable. The assets purchased or the amount of debt settled are recorded based on the more readily determinable fair value of the stock issued or price of the assets acquired or amount of the debt settled.
See Note 16. “Common Stock” for more information regarding our stock compensation plans.
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Notes to Consolidated Financial Statements-(Continued)
Options and warrants granted to employees and contractors are valued by applying the fair value based method to stock-based compensation in each period utilizing the Black-Scholes option pricing model, a generally accepted valuation model for determining the fair value of options. The maximum term of each option is ten years. With respect to stock options granted and warrants issued during the years ended December 31, 2009, 2008 and 2007, we computed the fair value using the Black-Scholes option-pricing model computations were as follows:
The risk-free interest rate is based on a yield curve of interest rates at the time of the grant based on the contractual life of the option. Expected dividend yield is based on our dividend history and anticipated dividend policy. Expected volatility is based on historical volatility for our common stock. Expected exercise life is based on management estimates of future attrition and early exercise rates, giving consideration to employee exercise behavior since filing of our initial S-8 registration statement for our Amended and Restated 2004 Long Term Incentive Plan on March 3, 2005.
Research and Development
Research and development costs are charged to expense when incurred.
Loss per Share of Common Stock
The computation of basic (loss) earnings per common share is based on the weighted average number of shares outstanding in accordance the Earnings per Share Topic of the FASB Accounting Standards Codification.
Stock warrants, stock options and unvested share awards are not included in the calculation of dilutive loss per common share because we have experienced operating losses in all periods presented and, therefore, the effect would be anti-dilutive.
Unvested stock grants totaling 130,000 shares and 30,084 shares were outstanding on December 31, 2009 and 2008, respectively. Since these unvested stock grants were granted to employees and Board of Directors, and would participate in dividends, if declared, as defined in the share grant agreements, they were included in the net loss per share computation. Our common stock underlying the call spread option transaction and forward stock purchase transaction would be recorded as treasury stock when delivered and; therefore, would be excluded from the calculation of diluted net loss per share because their effect is anti-dilutive. Also see Note 18, “Net Loss per Common Share” of Common Stock for potentially dilutive shares.
Noncontrolling Interest in Consolidated Entities
The accompanying consolidated financial statements include all assets, liabilities, revenues, and expenses in our Thermo Subsidiary that we control, but own less than 100%. Accordingly, we recorded noncontrolling interests in the earnings and equity of that subsidiary. We record adjustments to noncontrolling interest for allocable portions of income and loss to which the noncontrolling interest holders are entitled plus an allocable liquidated book value based upon contractual liquidation preference arrangements.
The Thermo Financing Agreements contain certain complex liquidation preference provisions which required certain distributions to each of the members of the Thermo Subsidiary in the event that a liquidation
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Notes to Consolidated Financial Statements-(Continued)
would occur. According to the Thermo Financing Agreements, upon liquidation of the Thermo Subsidiary and, after payment of all outstanding debt, any remaining funds would be distributions distributed in the following manner: (i) first, to both the Class A Member and the Class B Member in the amount of the agreed upon initial capital contributions for tax purposes, (ii) second, to the Class A Member so that any shortfall in achieving its target internal rate of return of 15% would have been achieved, and (iii) third, to both the Class A Member and the Class B Member with an allocation of 5% to the Class A Member and 95% to the Class B Member. To determine the non-controlling interest, we utilized a hypothetical liquidation at book value methodology at each balance sheet date. For the period ending March 31, 2009, we modified our hypothetical liquidation at book value methodology to include the recast-financial-statements approach. Under the hypothetical liquidation methodology, we utilized the recast-financial-statements approach which captured the initial relevant fair values of the assets and liabilities and follows generally accepted accounting principles for any additional transactions. We believe that the recast-financial-statements approach closely reflected the Class A Member’s claim on the Thermo Subsidiary’s book value at each balance sheet date because the tax equity financing documents with the Class A Member contained a liquidation preference. According to the recast-financial-statements approach, upon the initial sale of the membership interests, the assets and liabilities are hypothetically liquidated at the recast book value at the end of each period and the portions of the Class A Member’s claim relating to liquidation preferences are recorded as gains or losses. Because we have modified our hypothetical liquidation at book value methodology for the period ending March 31, 2009, certain differences resulted in the “Non-controlling interest” balance at March 31, 2009 as compared to the balance at December 31, 2008 and September 30, 2008. We treated these differences as a correction of an error, and such differences resulting from the modification to our methodology resulted in immaterial differences to the prior and current year disclosure.
As noted above, on December 4, 2009, we entered into a series of agreements with the Class A Member that amended the provisions August 2008 Thermo financing arrangements. These amendments were necessary to allow the Thermo Subsidiary to apply for a grant under Section 1603 of the Recovery Act. Pursuant to the amendments, we transferred the cost overruns, net of amortization, incurred as the EPC contractor on the Thermo No. 1 plant to the Thermo Subsidiary totaling approximately $25.9 million. On December 4, 2009, we also amended the LLC Agreement in which the Class A member withdrew from the Thermo Subsidiary and the tax benefit and profit/loss allocations changed to 0% to the Class A Member and 100% to the Class B Member to be effective on December 11, 2009. Accordingly, we computed the final hypothetical liquidation at book value balance on December 11, 2009 and the noncontrolling interest was eliminated. The difference between the redemption amount for the Class A Member and the noncontrolling interest at December 11, 2009 was recorded as additional paid in capital. For further discussion of noncontrolling interest, see Note 14. “Noncontrolling Interest” below.
We exercised significant judgments in computing the hypothetical liquidation at book value financial recast method including the amortization of the basis difference required by the financial recast method over 20 years.
U. S. Department of Treasury Grant under Section 1603 of the Recovery Act
Pursuant to the Recovery Act, an owner of a qualified geothermal power plant may elect to receive a grant from the U.S. Treasury Department of up to 30% of certain qualifying construction and drilling costs in lieu of claiming either ITCs or the PTC. The amount of the grant for a qualified geothermal power plant is up to 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the later of the date of the application for the grant is deemed complete or the date the project is placed in service.
We qualified for a U.S. Treasury grant totaling $33.0 million. We elected to reduce the cost basis of our Thermo No. 1 plant by the amount of the grant we received from the U.S. Department of Treasury. Grants under
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Notes to Consolidated Financial Statements-(Continued)
Section 1603 of the Recovery Act on the date the Grant was deemed complete by the U.S. Department of Treasury. By electing to reduce the cost basis, the depreciation expense going forward will also be reduced by approximately $0.8 million per year. An alternative method would be to record the amount received from the grant as a deferred credit and amortize it over the useful life of the Thermo No. 1 plant on a straight-line basis. We elected to reduce the cost basis of our Thermo No. 1 plant because this approach more accurately reflects the reimbursement nature of the grant. Had we elected to amortize a deferred credit over the estimated life of the plant instead of reducing the cost basis of the Thermo No. 1 plant and decreasing the amount of the depreciation, the net effect to net income or loss would be zero. For further discussion of the Grant, please refer to Note 3. “Federal Grant Receivable” and Note 5 “Geothermal Property, Plant and Equipment” below.
Note 3. Federal Grant Receivable
As noted above, pursuant to the Recovery Act, an owner of a qualified geothermal power plant may elect to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or the PTC. For a geothermal project, the amount of the grant is 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the date the U.S. Treasury Department deems the application is properly submitted and complete. All or some of the grant is subject to recapture if the property eligible for the grant is sold or otherwise disposed, or ceases to be eligible property within, five years after being placed in service. None of the grant should be included in federal taxable income, but may be included in applicable state taxable income.
On December 8, 2009, we submitted our application for a U.S. Department of Treasury grant under Section 1603 of the Recovery Act (the “Grant”) totaling approximately $33.0 million. On February 19, 2010, we received the Grant totaling $33.0 million. Although the actual Grant was not received until February 19, 2010, the Grant was deemed completed by the U.S. Department of Treasury on December 22, 2009. Accordingly we recorded the federal grant receivable on December 22, 2009.
We elected to reduce the cost basis of our Thermo No. 1 plant by the amount of the capital expenditures included in our Geothermal property, plant and equipment account that qualified for reimbursement under the Grant. Accordingly, we reduced the cost basis of our Thermo No. 1 plant by $29.2 million.
In addition, certain of the capital expenditures that qualified for tax purposes had previously been expensed for book purposes. Accordingly, for those capital expenditures that had been previously expensed for book purposes, we recorded a “Gain on Federal Grant” totaling $3.0 million. For further discussion of the Grant, please refer to Note 5. “Geothermal Property, Plant and Equipment” below.
The following table sets forth the total capital expenditures that qualified for the Grant:
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Notes to Consolidated Financial Statements-(Continued)
Note 4. Restricted Short-Term and Long-Term Marketable Securities
On March 26, 2008, we sold $50.0 million aggregate principal amount of our Convertible Notes pursuant to the terms of a purchase agreement, dated March 19, 2008 (the “Purchase Agreement”), between Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated (the “Initial Purchaser” or “Merrill Lynch”) and us. On April 1, 2008, we sold an additional $5.0 million aggregate principal amount of the Convertible Notes pursuant to the exercise of the Initial Purchaser’s overallotment option. The accrued interest payments on the Convertible Notes are due semi-annually on October 1 and April 1 of each year from October 1, 2008 until April 1, 2013.
On March 26, 2008, we used approximately $7.9 million of the proceeds from the Convertible Notes to purchase four discounted U.S. Treasury Strips that have coupon dates and coupon amounts that correspond with the amount of interest payable at each semi-annual payment date of the Convertible Notes. On April 1, 2008, we also purchased additional U.S. Treasury Strips totaling approximately $0.8 million to secure the first four interest payments on the additional $5.0 million of Convertible Notes. Under the Pledge and Escrow Agreement, we are required to hold these securities to maturity. Accordingly, the discounts are amortized over the period of the coupon and recognized as interest income. The short-term marketable securities at December 31, 2009 were as follows:
Interest payments on the Convertible Notes during the years ended December 31, 2009 and 2008, respectively totaled $4,400,000 and $2,261,556.
Note 5. Geothermal property, plant and equipment, net
The Thermo No. 1 plant was placed in service during the first quarter of 2009. Accordingly, we reclassified our related power project lease acquisition costs from the “Power project leases and prepaid delay rentals” account, well field drilling costs from the “Geothermal well field development-in-progress” account and power plant construction and transmission equipment costs from the “Power project construction-in-progress” account to the “Geothermal property, plant and equipment” account in accordance with our company policy. Accordingly, we began to amortize the capitalized costs related to the power plant over the estimated useful life of the Thermo No. 1 plant in the second quarter of 2009. The useful life of the Thermo No. 1 plant is estimated to be 35 years.
During the year ended December 31, 2009, we delivered 25,200 MW hours of electricity to the City of Anaheim. Thus far, we have been unable to operate the plant at full capacity due to insufficient heat and flow from the production wells that provide geothermal water to the plant. In the fall of 2009 we undertook a comprehensive review of the plant and well field operations at the Thermo No. 1 plant and, together with outside experts and our financing partners, developed a plan for increasing the output of the Thermo No. 1 plant. The key component of this plan was to re-work certain wells in order to eliminate down flow of a shallower, cooler zone of geothermal fluids which was mixing with the deeper, hotter zones. In general, this cooler zone contains
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Notes to Consolidated Financial Statements-(Continued)
geothermal fluids in the range of 200 F, while the deeper zone contains temperatures greater than 300 Fahrenheit. We believe that well field work and optimization of certain operations at the plant, have the potential to significantly increase the net power production from the plant during 2010. However, we have not completed all of the necessary well field or plant work and testing, and we cannot be certain the changes will allow us to significantly increase the power production at the Thermo No. 1 plant. Although our efforts to increase the temperature of the well field is taking longer than originally anticipated and additional work may be necessary to improve the output of the wells, we continue to believe that we can significantly increase power production at the Thermo No. 1 plant and eventually be able to operate the Thermo No. 1 plant at its full designed capacity of 11 MW.
Because we have experienced these difficulties, in order to improve our production levels, we have incurred significant construction, well field drilling and transmission equipment costs to improve the current levels of production through December 31, 2009. These costs have been capitalized directly into the “Geothermal property, plant and equipment” account in accordance with our company policy and depreciated accordingly.
As noted above, pursuant to the Recovery Act, an owner of a qualified geothermal power plant may elect to receive a grant from the U.S. Treasury Department in lieu of claiming either the ITC or the PTC. For a geothermal project, the amount of the grant is 30% of the cost of qualifying geothermal property placed in service in 2009 or 2010, or placed in service before 2014 if construction begins in 2009 or 2010. Grants are to be paid 60 days after the date the U.S. Treasury Department deems the application is properly submitted and complete. All or some of the grant is subject to recapture if the property eligible for the grant is sold or otherwise disposed, or ceases to be eligible property within, five years after being placed in service. None of the grant should be included in federal taxable income, but may be included in applicable state taxable income. Currently, the federal grant is not taxable in the State of Utah.
On December 8, 2009, we submitted our application for a U.S. Department of Treasury grant under Section 1603 of the Recovery Act (the “Grant”) totaling approximately $33.0 million. On February 19, 2010, we received the Grant totaling $33.0 million. Although the actual Grant was not received until February 19, 2010, the Grant was deemed completed by the U.S. Department of Treasury on December 22, 2009. Accordingly we recorded the receivable on December 22, 2009.
We elected to reduce the cost basis of our Thermo No. 1 plant by the amount of the capital expenditures included in our Geothermal property, plant and equipment account that qualified for reimbursement under the Grant. Accordingly, we reduced the cost basis of our Thermo No. 1 plant by $29.2 million. We will also decrease depreciation expense on a go forward basis and depreciate the net capitalized costs of the Thermo No. 1 plant as of December 22, 2009 over its remaining useful life on a straight-line basis. For further discussion of the federal grant, please refer to Note 3. “Federal Grant Receivable” above.
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Notes to Consolidated Financial Statements-(Continued)
The table below sets forth the capitalized costs relating to our geothermal property, plant and equipment after reducing the costs by the amount of the federal grant received as of December 31, 2009:
Thermo No. 1 Construction Costs
We purchased PWPS power generating units for the construction of our Thermo No. 1 plant. Fifty of these power generating units were installed at the Thermo No. 1 plant. In addition to the power generating units, construction costs include the construction of a cooling tower, pipelines from the well field to the power generating units, electronic monitoring equipment, buildings to house the equipment, office space, fences, and roadways to the Thermo No. 1 plant.
The Thermo No. 1 plant construction costs included costs to construct transmission lines, connecting substations and electrical lines from the substation to the well pumps. In order to connect a geothermal power plant to the existing power lines, we must construct transmission lines from the plant to the local utility interconnection point. We also must construct a substation at or near the facility that will increase the voltage from the generation facility to match local utility transmission voltages. We completed construction of approximately 6.5 miles of transmission lines for the Thermo No. 1 plant and the associated substation and other interconnection lines with the plant. We capitalized approximately $5.5 million of direct costs associated with the construction of these transmission lines and substation.
Thermo No. 1 Wells
At our Thermo No. 1 plant, as of December 31, 2008, we had completed the drilling of five wells that had been identified as production wells, two wells that had been identified as reinjection wells, one cold water well that is utilized for the cooling towers, and two wells that we have determined to be non-commercial wells. These two non-commercial wells were expensed in 2008.
During 2009, we drilled two additional wells that we expect to use as production wells, pending completion of testing. Although we had completed the initial drilling of both wells by December 31, 2009, based upon our limited capital resources, we have not been able to fully evaluate the commercial viability of both wells. Both wells initially demonstrated potential production level properties relating to heat and flow of the geothermal fluids. However, the initial heat levels in both wells are currently at levels which would only marginally increase the production of electricity. Additional time and work is required to fully assess the commercial viability of both of these wells. Accordingly, both of these wells have been classified as pending until we can fully evaluate the heat and flow characteristics. No additional wells were being drilled at December 31, 2009. Capitalized interest included in the costs of the Thermo No. 1 geothermal property, plant and equipment totaled $1,713,145.
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Notes to Consolidated Financial Statements-(Continued)
The following table is a roll forward of the capitalized well costs for pending wells at the Thermo No. 1 plant for the years ended December 31, 2009 and 2008, respectively:
In December 2008, we completed the testing of our PWPS power generating units and began generating and transmitting nominal quantities of “test” electricity. As a result of evaluating the combined production capacity of the geothermal power plant and the combined electricity producing capacity of the production wells, in accordance with our policy, we identified two completed production-sized wells at Thermo No. 1 that were unlikely to be used for the production of electricity at the Thermo No. 1 plant. Although one well initially exhibited production level heat, it was damaged and, after redrilling and marginally restoring the well, with the assistance of independent consultants, we determined that it should be expensed. In addition, the other well also initially demonstrated marginal production capabilities; however, we also determined that the well would not likely be used for the production of electricity. Accordingly, we expensed the wells at December 31, 2008 totaling $10.6 million.
Thermo No.1 Leases
After identifying the Thermo No. 1 prospect area, we began acquiring geothermal rights. Beginning in April 2007, we entered into several lease agreements with the State of Utah School and Institutional Trust Lands Administration (the “State”) for geothermal rights in the Thermo No. 1 area totaling approximately 5,500 acres in Beaver and Iron Counties, Utah. The initial term of the geothermal leases is 10 years, subject to extension for as long as we are actively pursuing or generating electricity from the geothermal resources from the leased lands. Annual delay rental payments on the State of Utah leases are $1.00 per acre and are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resources coverd by the leases, royalties are paid based on a percentage of electrical sales from the plant.
Additionally, in September, 2007, we entered into a lease agreement with a private landowner for geothermal rights on approximately 11,000 acres of land located in the Thermo area. Through this lease, we acquired a 75% undivided interest in the geothermal rights on the properties. In October 2008, we acquired the remaining 25% undivided interest via a lease with another private entity. The initial term of the lease with 75% undivided interests is ten years. The initial term of the lease with the 25% undivided interests is five years. Royalties are paid on the leased properties on which the Thermo No. 1 plant is located and are based on a percentage of electrical sales from the plant. The cumulative lease bonuses paid for both leases totaled $147,800. We also capitalized the present value of our asset retirement obligation totaling $2.5 million that we assumed to
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Notes to Consolidated Financial Statements-(Continued)
plug our wells and decommission our geothermal power plant at the end of its estimated useful life. This asset retirement obligation is included in the carrying cost of the leased properties and amortized when the geothermal power plant is placed in service over its estimated useful life of 35 years.
Collateralized Thermo No. 1 Leases
On May 16, 2008, we and our Thermo Subsidiary entered into a financing commitment letter (the “Thermo Commitment”) with Merrill Lynch relating to the project financing and tax equity funding for the Thermo No. 1 plant. On August 31, 2008, we finalized the project financing arrangements for the Thermo No. 1 plant and entered into the Thermo Financing Agreements that provide debt financing and tax equity capital for the Thermo No. 1 plant.
Pursuant to the Thermo Financing Agreements, we agreed to contribute, as Class B membership equity interests, seven geothermal leases held by certain of our wholly owned subsidiaries to the Thermo Subsidiary. One of the geothermal leases contains the property totaling 1,507 acres on which we had drilled wells that are being developed as either production wells or re-injection wells for the Thermo No. 1 plant. The other six geothermal leases represent parcels of land surrounding the Thermo No. 1 plant area totaling 8,892 acres (“Collateral Parcels”). The Thermo Subsidiary also granted to Deutsche Bank (the “Collateral Agent”) a security interest and continuing lien on all of our right, title and interest in the seven contributed geothermal leases to be held as collateral by the Collateral Agent to secure prompt and complete payment when any and all of the obligations become due.
Pursuant to the Thermo Financing Agreements, the Collateral Agent is instructed to release all liens and return the Collateral Parcels to us when construction of the geothermal power plant is deemed to be substantially complete. Additionally, the Collateral Agent is further instructed to remove all liens on approximately 867 acres of the remaining leased property upon receiving certification from an independent geothermal engineer, at any time after 18 months, that the geothermal resource is expected to remain viable long-term.
Note 6. Power Project Leases and Prepaid Delay Rentals
The first phase of our development and construction of our geothermal power projects is site identification and evaluation. The first step in the site identification and evaluation phase is the identification of potential project sites. As part of the identification process, we incur a variety of costs, which may include costs for topographical studies, geological and geophysical studies, rights to access and study properties, technical materials and maps. Regardless of whether we pursue a project at a particular site, all of the costs associated with the identification of a potential site are considered exploratory in nature and are expensed as incurred.
The next step in the site identification and evaluation phase is land acquisition, pursuant to which we acquire land, lease land, or otherwise obtain the appropriate property interests to develop a potential project. Lease acquisition costs, including lease bonuses, legal costs, permit costs, and the fair value of other forms of compensation to acquire leases are capitalized as power project leases when incurred. The power project leases are capitalized but not amortized until the related power plant is placed in service. At that time, the related power project leases are capitalized as geothermal property, plant and equipment and amortized over the estimated useful life of the geothermal power plant. From time to time, we also purchase land outright to develop. Any land we purchase outright is not amortized and is stated in our financial statements at historical cost.
Our power project leases are considered contract-based intangible assets and the costs to acquire the power project leases are capitalized accordingly. Impairment of the power project leases is evaluated based upon a
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Notes to Consolidated Financial Statements-(Continued)
comparison of the fair value with its carrying amount at the balance sheet date. We evaluated our power project leases as of December 31, 2009 for impairment and determined that none of our intangible assets were impaired.
Once we have acquired an interest in a geothermal property, we also incur costs to carry and maintain the undeveloped property until we are in a position to determine whether or not to pursue a project on the property. These costs can include delay rentals, certain taxes on the properties, legal costs for title defense, and the maintenance of land and lease records. All of these costs are expensed when incurred.
As part of our site identification and evaluation process, as of December 31, 2009, we had accumulated a large portfolio of geothermal interests in four western states in the United States that have the potential to provide sufficient geothermal energy to operate binary cycle geothermal power plants. In addition to our geothermal interests in the United States, in September 2008, we and Indonesia Power were selected as low bidders on a geothermal project in Indonesia. As a result, both companies were awarded a concession by the Indonesian government that includes approximately 100,000 acres of land that contains potential geothermal resources. Once we have obtained sufficient project financing, we intend to pursue the exploration and development of our geothermal concession Indonesia. We are currently in discussions with Indonesia Power to form a joint venture, subject to Board of Director approval.
The following represent capitalized power project lease and acquisition costs by geographical area and by general project area which include leases surrounding the target project development site at December 31, 2009 (normally, the well field and power plant are designed to be drilled and constructed on leased properties between 480 and 1,000 acres within the project site):
* The “Greater Thermo and other areas” as used in this table excludes the Thermo No. 1 plant and parcels which are in the closest proximity to the Thermo No. 1 plant. This acreage includes other parcels which we consider
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Notes to Consolidated Financial Statements-(Continued)
part of the greater Thermo area. Our holdings in the greater Thermo area total approximately 51,000 acres. The typical project will generally have a parcel of 480-1,000 acres dedicated to it. These larger acreage numbers represent the total acreage of the leases on which these projects are currently being proposed. However, prior to finalizing project financing for each of these, we anticipating segregating these leases so that only a small portion (480-1,000 acres as stated above) will be dedicated to a typical 10-20 MW project.
The following represent capitalized power project lease and acquisition costs by geographical area and by general project area which include leases surrounding the target project development site at December 31, 2008 (normally, the well field and power plant are designed to be drilled and constructed on leased properties between 480 and 1,000 acres within the project site):
** The “Thermo area” as used in this table includes the Thermo No. 1 plant and parcels which are in the closest proximity to the Thermo No. 1 plant. This acreage does not include other parcels which we consider part of the greater Thermo area. Our holdings in the immediate vicinity of the Thermo No. 1 plant and the greater Thermo area total approximately 51,000 acres. The typical project will generally have a parcel of 480-1,000 acres dedicated to it. These larger acreage numbers represent the total acreage of the leases on which these projects are currently being proposed. However, prior to finalizing project financing for each of these, we anticipating segregating these leases so that only a small portion (480-1,000 acres as stated above) will be dedicated to the typical 10-20 MW project.
Greater Thermo Area Leases (excluding Thermo No. 1 leases)
After identifying the Thermo prospect area, we began acquiring geothermal rights. Beginning in April 2007, we entered into several lease agreements with the State of Utah School and Institutional Trust Lands Administration (the “State”) for geothermal rights in the Greater Thermo area of approximately 5,500 acres in
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Notes to Consolidated Financial Statements-(Continued)
Beaver and Iron Counties, Utah. The initial term of the geothermal leases is 10 years, subject to extension for as long as we are actively pursuing or generating electricity from the geothermal resources from the leased lands. Annual delay rental payments on the State’s leases are $1.00 per acre and are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resource covered by the leases, royalties are paid based on a percentage of electrical sales from the plant. The leases provide rights to the geothermal resource and rights to utilize the surface as necessary for the development of the geothermal rights.
During 2008, we entered into three separate geothermal leases with private land owners in the Greater Thermo area for $41,200 covering approximately 10,800 acres. The initial terms of the leases are between five and ten years, subject to certain extensions. Annual delay rentals for the three leases total $33,300 and are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resource covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant.
During 2009, we entered into two separate geothermal leases with private land owners in the Greater Thermo area for $4,500 covering approximately 475 acres. The initial terms of the leases are ten years, subject to certain extensions. Annual delay rentals for the two leases total $950 and are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resource covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant. We continue to pursue the acquisition of geothermal leases on other State parcels and geothermal leases with other private landowners in the Thermo area.
Our general strategy in the Thermo area has been to lease as much property as possible that we consider to be located in the Greater Thermo resource. We anticipate that each typical 10- 20 MW project will have a smaller portion of property dedicated to it; typically 480-1,000 acres. We expect to segregate these smaller parcels out from the larger leased positions as we finalize the project financing for each individual project.
Lightning Dock Area Leases
In 2007, we entered into an agreement to acquire GeoLectric, LLC. This agreement was later superseded by our agreement to purchase a BLM lease and other miscellaneous assets totaling $4,260,000 from a subsidiary of GeoLectric, LLC (the “Purchase”). The expenses associated with the negotiation, document preparation, due diligence and other acquisition related activities were capitalized as part of the land acquisition. The Purchase was subject to the BLM’s approval of the assignment of the BLM Lease from the subsidiary of GeoLectric, LLC to us. On December 13, 2007, the BLM approved the assignment of the BLM Lease to us, which fulfilled the condition required to complete the Purchase pursuant to the terms of agreement. Under the assigned BLM Lease, we obtained rights to begin development of one or more geothermal power plants on the property located on approximately 2,500 acres in Hidalgo County, New Mexico. The initial lease term of the assigned BLM Lease began in January 1979 and has been extended based upon certain conditions in the lease until January 2024. Annual delay rental payments of $5,000 are required on each anniversary date until geothermal power production has begun. If a geothermal power plant is constructed which utilizes geothermal resource covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant. We have capitalized certain legal fees directly associated with completing the Purchase and obtaining the BLM lease. We also capitalized the present value of our asset retirement obligation totaling $85,600 that we assumed to plug certain wells associated with the BLM property. This asset retirement obligation is included in the carrying cost of the leased properties and amortized when the geothermal power plant is placed in service over its estimated useful life of 35 years.
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Notes to Consolidated Financial Statements-(Continued)
With respect to the same 2,500 acres in Hidalgo County, New Mexico, in January 2008, we also entered into a surface access and use lease agreement, or surface lease agreement, with a private property owner in New Mexico (the “New Mexico Property Owner”) and paid $320,000 to obtain surface right-of-way access and drilling rights. The term of the surface lease agreement continues until our geothermal rights respective to the BLM lease have expired. Pursuant to the surface lease agreement, we also obtained certain water rights at $0.50 per acre foot of water with a minimum annual fee of $1,000 during the term surface lease agreement, which is due on each anniversary date of the surface lease agreement.
In August 2008, we paid $1,200 as a lease bonus and entered into a ground lease agreement for 20 acres with the New Mexico Property Owner. The term of the ground lease agreement is indefinite, as long as the power plant, transmission and related facilities on the leased property are producing or capable of producing electricity from geothermal resources. No annual payments are required for the ground lease agreement. Under the ground lease agreement, we obtained the right to construct and operate a geothermal power plant and transmission facilities on the property.
Klamath Falls Area Leases
In January 2008, we paid $10,000 as a lease bonus and entered into a geothermal lease with private land owners for 984 acres approximately 13 miles south of Klamath Falls, Oregon. The leased property is a farm that contains a residential house, barns, hay storage sheds, greenhouses and a boi diesel plant. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease term is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rental payments of $1,000 are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant.
Truckee Area Leases
In December 2006, we paid $25,000 in cash, as a lease bonus, to cover the first year rental obligation, and issue to the owner 25,000 restricted shares of our common stock that had a fair value of $115,250 on the grant date to obtain the right to begin development and construction of geothermal power plants on three ranches in central Nevada consisting of approximately 11,600 acres. In August 2007, we also granted to the private property owner 35,000 options at a strike price of $15.10 representing the closing market price on the date of the grant as consideration to cancel previously awarded contingently vesting stock. The fair value of the 35,000 options was recorded as power project leases totaling $424,000. Annual delay rental payments total $34,800 on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resource covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant. The terms of the lease agreement are for 50 years subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Lease acquisition costs for the Truckee project total $755,900.
In June 2007, we paid $40,000 to the private land owner that held the geothermal rights and entered into a geothermal lease agreement for the same 11,600 acres described above. Under the terms of this lease agreement, there are no delay rental payments. Of the 11,600 acres of leased property, approximately 1,000 acres have been designated for the Truckee project. In September 2007, we participated in a United States Bureau of Land Management (“BLM”) auction to obtain the geothermal development rights for certain parcels of land in the Truckee project site. We successfully won the bid for one parcel of land and entered into a 10-year lease agreement with the BLM covering a total of approximately 5,000 acres. Our payment obligation under this lease
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Notes to Consolidated Financial Statements-(Continued)
was $55,000, which was paid in the third quarter of 2007. Pursuant to the terms of the BLM leases, annual delay rental payments total $15,000. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant.
Devil’s Canyon Area Leases
In February 2007, we entered into a lease agreement with a private property owner covering approximately 155 acres in Devil’s Canyon. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease terms of the lease agreement is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Concurrently, we were assigned the rights of the private property owner’s BLM lease covering 240 acres. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The remaining lease terms of the BLM lease agreement is 4 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. In June 2008, we leased an additional 600 acres of private land from another private landowner adjacent to our previously leased property. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease terms of the lease agreement is 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rental payments of $20,000 are due on each anniversary date until production begins. If a geothermal power plant is constructed which utilizes geothermal resource covered by the lease, royalties are owed to the landowner based on a percentage of electrical sales from the plant.
In December 2008, we purchased a cold water well containing certain water rights on property that we had leased for geothermal development. We expect to use this water in our operations of the Devil’s Canyon plant.
Trail Canyon Area Leases
In January 2007, we paid $5,000 and issued 5,000 restricted shares of our common stock to a private land owner and entered into a geothermal lease agreement on 635 acres of private land in the Trail Canyon project. The terms of the lease agreement are for 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rentals total $635 on each anniversary date of the lease until production of electricity begins. In addition, concurrent with entering into this lease agreement, the private land owner assigned to us a BLM lease in the Trail Canyon project for the same 635 acres. The BLM lease contains the rights to develop and construct a geothermal power plant. The term of the BLM lease is 10 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Annual delay rentals for the BLM lease total $635 due on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by these leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
In September 2007, we participated in a BLM auction to obtain the geothermal development rights for certain parcels of land in the Trail Canyon project site. We successfully won the bid for one parcels of land and entered into a 10-year lease agreement with the BLM covering a total of approximately 1,900 acres. Our payment obligation under this lease was $126,800, which was paid in the third quarter of 2007. Pursuant to the terms of the BLM leases, annual delay rental payments total $5,700. If a geothermal power plant is constructed which utilizes geothermal resources covered by the lease, royalties are owed to the BLM based on a percentage of electrical sales from the plant.
In August and November 2007, we paid a total of $5,000 and entered into seven separate lease agreements with seven private land owners of the same private property near the Truckee project drilling site consisting of 4,444 acres to obtain the right to develop and construct a geothermal power plant. The terms of the lease
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Notes to Consolidated Financial Statements-(Continued)
agreements are for 50 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. Pursuant to the terms of this lease agreement, annual delay rentals total $4,444 on each anniversary date until production of a geothermal power plant begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
In May 2008, we paid $15,000 as a lease bonus and entered into a geothermal lease with private land owners for 560 acres in the Trail Canyon project. Under the lease agreement, we obtained the right to begin development and construction of geothermal power plants. The initial lease term is 15 years, subject to extension for as long as we are actively pursuing or generating resources from the leased lands. The annual delay rental payments total $5,000 on each anniversary date until production of electricity begins. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are owed to the respective landowners based on a percentage of electrical sales from the plant.
Additional Power Project Leases
In addition to our power project leases described above, we have also acquired certain additional leases for properties that we are currently evaluating for future projects.
In January 2009, we entered into a10-year geothermal lease agreement with a private land owner to obtain geothermal development rights for approximately 37,000 acres in Harney County, Oregon. Our obligation under the lease was $50,000, which was paid in the first quarter of 2009. Pursuant to the geothermal lease agreement, annual delay rentals total $37,000 for the first three years, $148,000 for year four, $185,000 for year five, and $222,000 for year six and thereafter. Royalty payments are 3.5% of gross revenues for the first five years and 4% thereafter.
In September 2008, in conjunction with a bid jointly submitted with Indonesia Power, we were also granted a 100,000 acre geothermal concession in West Java, Indonesia. As we finalize our joint venture agreement with Indonesia Power, subject to approval from our Board of Directors, which is expected in 2010, we intend to enter into a long-term lease agreement with the government of Indonesia to develop these geothermal resources.
In September 2007, we participated in a BLM auction to obtain the geothermal development rights for certain parcels of land in the Big Smoke Valley of Nye County, Nevada. We successfully won the bid for one parcels of land for the Truckee project, one parcel of land for the Trail Canyon project and two parcels of land for a project that is yet to be determined. The terms of the BLM lease are 10 years. The acreage acquired that has not been assigned to a project totals approximately 8,400 acres. Our payment obligation under these leases was $437,900, which was paid in the third quarter of 2007. Pursuant to the terms of the BLM leases, annual delay rental payments total $25,200. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are owed to the BLM based on a percentage of electrical sales from the plant.
Since March 2007, we have entered into approximately 70 geothermal leases with the State throughout Utah totaling approximately 120,000 acres. These leases are located in areas that we are currently evaluating for future projects. The terms of these geothermal leases are 10 years with an annual delay rental payment on each anniversary date of $1.00 per acre until production of electricity begins. The lease acquisition costs for these State leases totaled approximately $130,000 as of December 31, 2008. If a geothermal power plant is constructed which utilizes geothermal resources covered by the leases, royalties are paid based on a percentage of electrical sales from the plant.
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Notes to Consolidated Financial Statements-(Continued)
As part of the overall consideration for three of our geothermal lease agreements in Nevada, we issued 25,000, 5,000, 2,500, and 1,000 restricted shares of our common stock, respectively. The fair values of these equity awards were $115,250, $27,350, $12,450 and $9,930 on the respective grant dates, respectively. We have also granted options to purchase 35,000 shares of our common stock at a strike price of $15.10 per share to a property owner in Nevada. The Black-Scholes fair value of the options on the grant date total $423,987. These costs have been capitalized as power project leases. Certain legal fees incurred in connection with acquiring the geothermal lease agreements were also capitalized as power project leases totaling $55,700. We also agreed to pay $50,000 as an advance against future delay rentals and/or royalties beginning in the second year of one of the lease agreements in Nevada. Power project leases are not amortized until a geothermal power plant constructed on the applicable leased property is placed in service. In addition, the prepaid delay rentals are not amortized.
Abandoned Leases and Lease Options
In December 2008, we participated in a BLM auction to obtain the geothermal development rights for certain parcels of land in Utah. We successfully won the bids for four parcels of land and entered into four separate 10-year renewable lease agreements with the BLM covering a total of approximately 60,300 acres. Our total payment obligation under these leases was $503,816, of which $199,190 was paid in the fourth quarter of 2008. However, our January 5, 2009 payment for the remaining $304,626 was rejected and returned to us due to our clerical error. We believe that the payment was valid and we filed an appeal to re-instate the leases. In December 2009, we were notified by the BLM that we had lost the appeal and the $199,190 was returned to us, less nominal administrative fees. Accordingly, we reduced the capitalized power project lease costs relating to this property by $199,190.
In January 2008, we paid $25,000 to obtain a binding option agreement with a land owner in Utah. Under the terms of the binding option agreement, 90 days from the execution of the agreement, we had the option to lease certain geothermal rights on the property totaling 108 acres. Based upon management’s further evaluation of the property, we decided not to exercise this option and terminated the binding option agreement. Accordingly, we expensed $25,000 of capitalized power project lease costs relating to this property.
During the first quarter of 2008, we paid $40,000 to enter into two separate binding option agreements with two private property owners in Utah. Under the terms of the binding option agreements, we had options to lease certain geothermal and water rights on the properties. Based upon management’s further evaluation of the properties, we decided not to exercise these options and terminated our binding option agreements. Accordingly, we expensed $40,000 of capitalized power project lease costs relating to this property.
Note 7. Geothermal Well Field Development-in-Progress
Once we have obtained sufficient third-party evaluation and analysis supporting the conclusion, with a high degree of confidence, that our leased geothermal property contains adequate renewable geothermal resources to continually produce electricity, we begin drilling production and reinjection wells for use at the geothermal power plant we intend to build. Depending on the depth of the well and conditions encountered, it typically takes approximately 25 to 90 days to drill a production or reinjection well. Once drilled, the determination of whether the well can be used in the production of electricity can take another six months or more and is normally based upon several factors such as; (1) the results of testing the heat and volume flow of the geothermal liquids, (2) the combined production capacity of the geothermal power plant, (3) the combined electricity producing capacity of the other production wells, and (4) the required total quantity of reinjection wells for the project. The costs of the wells for which the determination of the viability for use as a production or reinjection well is pending are capitalized with those wells that have already been determined for use as production or reinjection wells. The capitalized costs for pending wells and wells that have been determined to be used in the production of electricity
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Notes to Consolidated Financial Statements-(Continued)
are classified on the balance sheet as either well field development-in-progress or as geothermal property, plant and equipment if the plant is already placed in service. When management determines that it is probable that a well will not be used to in the production of electricity by the respective geothermal power plant, the previously capitalized costs of that well are expensed in the period in which the wells are determined to be unusable.
During the first quarter of 2009, we placed our Thermo No. 1 plant in service and reclassified the accumulated costs of Thermo No. 1 wells from well field development-in-progress to geothermal property, plant and equipment. For further discussion of the Thermo No. 1 wells see Note 5. “Geothermal Property, Plant and Equipment”.
Impairment of the Truckee Well
As of December 31, 2008, we had drilled one production-sized well at the Truckee project. After performing an impairment analysis of our long-lived assets at December 31, 2008 as required by the FASB Accounting Standards Codification, we determined that the Truckee well was impaired. Accordingly, we expensed the well at December 31, 2008 totaling $3.0 million.
The circumstances that led to the impairment of the Truckee well were primarily due the current world-wide economic conditions that have led to tightening credit markets. Because of the tightening credit markets, we determined that our access to capital may be constrained in the future. Accordingly, we prioritized our cash uses, concentrating our efforts on our largest known resources. As a result, the future undiscounted cash flows from the Truckee well have become uncertain because of the re-prioritization of our projects based upon the changing economic conditions. Therefore, we considered our ability to secure sufficient financing necessary to continue drilling at the Truckee project and determined it was uncertain if we would be able to finance continued drilling at the Truckee project in the near term in addition to our other projects of higher priority. Because of this uncertainty, we expensed $3.0 million in the Power Systems business segment in the fourth quarter of 2008 accordingly. However, management believes that this well could still be used in the production of electricity as either a production or reinjection well in the future should the appropriate financing be obtained.
No new wells have been drilled during 2009 except for the two Thermo No. 1 wells discussed in Note 5. “Geothermal Property, Plant and Equipment”.
The following table is a roll forward of the capitalized well costs for pending wells at the Truckee project for the year ending December 31, 2009:
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Notes to Consolidated Financial Statements-(Continued)
The costs to drill production and reinjection wells include tangible and intangible drilling costs. Tangible drilling costs include tangible materials that remain as part of the well after drilling is complete such as casing, pipes, wellheads, pumps, rings and drilling pads. Intangible drilling costs include tangible and intangible materials that do not remain as part of the well after the drilling is complete such as, permit preparation, drilling rig rental, salaries and expenses incurred by drilling personnel, lubricants, drilling mud, cement and other materials used in the drilling process, drill bits, freight to deliver the products, fishing costs, sample testing, rental equipment, survey costs, excavation cost, drainage cost, and other expenditures incurred analyzing the drilling process. Internal costs that are directly identified with development of a specific well field are also capitalized when incurred.
Once the related geothermal power plant is placed in service, the drilling costs are reclassified as “Geothermal property, plant and equipment” and depreciated over the estimated useful life of the related geothermal power plant or 35 years.
During 2009, we reclassified the well field drilling costs incurred by the Thermo No. 1 plant to “Geothermal property, plant and equipment”. We have either obtained or are in the process of obtaining permits to develop well fields at the Devil’s Canyon and Trail Canyon project sites in Nevada, the Thermo No. 2 and Thermo No. 3 project sites in Utah, the Lightning Dock project site in New Mexico and the Klamath Falls project site in Oregon.
The following table sets forth our capitalized permitting costs for projects to develop geothermal power plants that had not yet been placed in service by geographical area and by project as of December 31, 2009:
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Notes to Consolidated Financial Statements-(Continued)
The following table sets forth our capitalized drilling and permitting costs for projects to develop geothermal power plants that had not yet been placed in service by geographical area and by project as of December 31, 2008:
Intangible drilling costs are normally higher than tangible drilling cost because tangible costs are limited to tangible materials such as pipe and well casings that become part of the well when the well is completed. Capitalized interest costs included in well field development in progress totaled $1,215,800 and $652,900 for the year ended December 31, 2009 and 2008, respectively.
Note 8. Power Project Construction-in-Progress
The construction of the geothermal power plant, the related transmission lines, and the required substation takes place concurrently with the drilling of the production and re-injection wells. An independent engineering firm prepares the basic blue print design for each geothermal power plant project. The blueprints are customized for each plant prior to beginning construction. Depending on the contractual agreement with the entity financing the project, we either hire a third-party general contractor and several subcontractors to complete the construction of the power plant, installation of the power generating units, cooling towers and other electrical equipment or we act as the EPC contractor for the project. The construction of the power plant and related transmission lines are accumulated and capitalized over the construction period. Once the geothermal power plant is placed in service, the related construction costs will be reclassified as “Geothermal property, plant and equipment”.
In 2007, we began purchasing UTPC power generating units for the construction of our geothermal power plant at the Thermo No. 1 plant. As of December 31, 2008, pursuant to purchase agreements with a manufacturer, we had taken delivery of 163 generating units for use in the geothermal power plants we are developing. Fifty of these generating units were installed at the Thermo No. 1 plant. We had taken delivery of 48 power generating units that were stored at the Lightning Dock project pending installation at that project. These UTCP power generating units were capitalized as power project construction-in-progress. We had also taken delivery of 27
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Notes to Consolidated Financial Statements-(Continued)
power generating units that were stored on the Thermo No. 1 plant site that were not assigned to a specific project, and 38 power generating units were stored at independent storage facilities in New York and Pennsylvania that were not assigned to a specific project. These 65 power generating units that had not yet been assigned to a specific project were recorded as “Power project equipment” on our consolidated balance sheets totaling $19.7 million. Once the UTCP power generating units were assigned to a project for the purpose of beginning construction at the project site, the applicable costs of the UTCP power generating units will be reclassified from power project equipment to power project construction-in-progress.
On April 9, 2009, we entered into an agreement (the “PWPS Agreement”) with Trail Canyon Geothermal No. 1 SV-02, LLC (“Trail Canyon”), Raser Power Systems, LLC and PWPS pursuant to which we and PWPS agreed to terminate certain agreements that had been assigned to PWPS from UTCP relating to power generating units (collectively, the “Terminated Agreements”). Under the terms and conditions of the PWPS Agreement, we agreed to transfer title to PWPS of 113 power generating units previously delivered or held for delivery for us, free and clear of all liens and encumbrances. We and PWPS also agreed that, until the earlier of April 9, 2012 and the date on which we have installed 200 power generating units (in addition to the power generating units installed at our Thermo No. 1 plant), PWPS will be the exclusive provider of heat-to-electricity equipment used for any merchant power plant project developed by us or any of our affiliates so long as PWPS can meet the needs of the particular project. PWPS agreed that it would maintain 50 power generating units in inventory throughout 2009 that would be allocated to us and that we would receive preferential pricing until April 9, 2011. Pursuant to the Terminated Agreements, we had previously paid to UTCP non-refundable deposits totaling $8.9 million. As part of the PWPS Agreement, $1.5 million of these deposits was retained by PWPS as a restructuring charge. PWPS agreed to refund the remaining $7.4 million of deposits (the “Deposit Refund”), subject to the satisfaction of certain conditions. The purpose of the Deposit Refund is to help facilitate payment for certain work necessary for the completion of the Thermo No. 1 plant, including the payment of certain existing accounts payable. Accordingly, PWPS is only required to distribute portions of the Deposit Refund if we (1) provide reasonable documentation to PWPS evidencing the work performed at the Thermo No. 1 plant site by a third party vendor; (2) provide reasonable documentation to PWPS evidencing the payment of such third party vendor; and (3) represent that the amount of the Deposit Refund to be paid is related solely to the Thermo No. 1 plant site and is necessary to keep the project moving forward. The Deposit Refund was released to Raser in installments at times and in the amounts determined at the sole reasonable discretion of PWPS.
Notwithstanding the PWPS Agreement, our agreements with PWPS relating to the purchase of the power generating units for the Thermo No. 1 plant and the associated services agreement remain in full force and effect.
In April 2009, we began selling electricity generated by the Thermo No. 1 plant to the City of Anaheim pursuant to a power purchase agreement we previously entered into with the City of Anaheim. Since our Thermo No. 1 plant was placed into service in the first quarter of 2009, we reclassified these construction costs as “Geothermal property, plant and equipment” accordingly. For further discussion of Thermo No. 1 construction costs, refer to Note 5. “Geothermal Property, Plant and Equipment”.
We are currently obtaining the proper easements and right of way permits from the federal, state and private land owners to construct a 17 mile long transmission line from our Thermo No. 1 interconnect location to a Rocky Mountain Power system interconnect location. We have also purchased the appropriate transformers and some reclosers in anticipation of obtaining the necessary approvals to proceed with the construction of the proposed transmission lines totaling $1.9 million as of December 31, 2009. We anticipate the total cost to complete the 17 mile transmission line to range between $15.0 to $18.0 million.
As of December 31, 2009, pursuant to certain vendor purchase commitments, we had taken delivery at our Lightning Dock project site of equipment to construct our cooling towers, water pumps and pipes to transport geothermal water from the wellheads to the power generating units and other electronic equipment that will be
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Notes to Consolidated Financial Statements-(Continued)
used to operate the geothermal power plant at the Lightning Dock project site. This equipment is capitalized as “Power project construction-in-progress” on our consolidated balance sheets, as detailed below. Under the PWPS Agreement, we agreed to terminate certain agreements relating to the purchase of power generating units and related services, as discussed above in more detail. This equipment is capitalized as power project construction-in-progress at the Lightning Dock project below.
Power project construction-in-progress consisted of the following at December 31, 2009 (by project):
Capitalized interest included in construction in progress totaled $908,300 and $368,300 for the years ending December 31, 2009 and 2008, respectively. Amounts capitalized as power project construction-in-progress will not be depreciated until the applicable geothermal power plant is placed in service.
Note 9. Equipment, net
Equipment consisted of the following at December 31:
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Notes to Consolidated Financial Statements-(Continued)
Note 10. Intangible Assets, net
At December 31, 2009 and 2008, we had capitalized costs directly related to internally developing, maintaining or restoring patents and trademarks totaling $434,667 and $531,377, respectively. The accumulated amortization related to patents at December 31, 2009 and 2008 totaled $48,942 and $46,865, respectively. Since trademarks are considered to have indefinite lives, the costs of trademarks are not amortized.
Amortization expense relating to patents totaled $14,700, $14,900, and $15,800 for the years ended December 31, 2009, 2008, and 2007, respectively. Patent amortization expense for the succeeding five years is $12,995 per year or $64,975. At December 31, 2009, the weighted average amortization period for our patents is 15.75 years.
Abandoned or impaired patents and trademarks are written off in the period of abandonment or when the impairment occurred and a loss is recorded based upon the historical cost less accumulated amortization of the asset. For the years ended December 31, 2009, 2008, and 2007, losses relating to abandonment of patents and trademarks total $101,613, $11,554, and $111,460, respectively.
At December 31, 2009, our global license (excluding Australia, New Zealand, South Africa, and Canada) for certain key heat transfer technologies including geothermal, waste heat recovery and bottom-cycling applications totaled $88,955. The amortization expense related to our global license at December 31, 2009, 2008 and 2007 totaled $10,892, $10,892 and $10,892, respectively. Amortization expense relating to the global heat transfer technology license for the succeeding five years is $10,892 per year, or $54,460.
We have entered into various agreements to purchase the water rights from private owners of water rights in Utah, Nevada and New Mexico in order to provide the necessary water to operate the geothermal power plants that we intend to develop. The following table sets forth the quantity and costs of our water rights as of December 31, 2009 and 2008, respectively:
In May of 2009, we did not exercise the options to purchase 800 acre feet per year for our Lightning Dock project and expensed $24,000 accordingly. Since water rights normally increase in value over time, no amortization is recorded.
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Notes to Consolidated Financial Statements-(Continued)
Note 11. Deferred Acquisition and Financing Fees
Deferred financing fees consisted of the following at December 31, 2009 and 2008, respectively:
Refer to Note 12, “Short-term and Long-Term Debt Instruments” for further discussion of the 8.00% convertible senior notes deferred financing fees and discussion of the Thermo No. 1 financing and restructuring agreements. Also refer to Note 17, “Warrants” for further discussion of the fair value of the warrants that vested upon entering into the Thermo No. 1 plant financing arrangements.
Note 12. Short-Term and Long-Term Debt Instruments
Merrill Lynch Amended Promissory Note Payable
On December 4, 2009, we entered into a Redemption Agreement (“the Redemption Agreement”) with Merrill Lynch (the “Class A Member”). Pursuant to the Redemption Agreement, the Class A Member withdrew from the Thermo Subsidiary effective on December 11, 2009. Concurrently, we issued a promissory note payable to redeem the Class A Member for up to $24.5 million, subject to certain conditions including the timing and amount of proceeds from the 30% grant under Section 1603 of the Recovery Act and the amount of the convertible notes issued by us on March 18, 2008 (the “Convertible Notes”) held by the current holders of the Convertible Notes (as defined in the Redemption Agreement) on February 16, 2010.
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Notes to Consolidated Financial Statements-(Continued)
The promissory note payable bears no interest until February 16, 2010 and is due and payable on February 15, 2011. Principal amounts and unpaid interest shall bear interest at a rate of (i) fifteen percent (15%) per annum from February 15, 2010 through August 15, 2010, and eighteen percent (18%) per annum from August 16, 2010 through February 15, 2011 or until paid in full.
The December 4, 2009 promissory note was later amended on February 16, 2010 to change the effective date of the promissory note to June 30, 2010. Accordingly, the amended promissory note payable bears no interest until June 30, 2010 and is due and payable on June 30, 2011. Principal amounts and unpaid interest shall bear interest at a rate of (i) fifteen percent (15%) per annum from June 30, 2010 through December 30, 2010, and eighteen percent (18%) per annum from December 31, 2010 through June 30, 2011 or until paid in full. On February 19, 2010, we received the 30% grant under Section 1603 of the Recovery Act totaling $33.0 million. Since more than 50 percent of the Convertible Notes held on December 4, 2009 were still outstanding on February 16, 2010, the principal balance of the amended promissory note payable at December 31, 2009 totaled $20.0 million. We imputed interest at 15% per annum totaling $1.4 million which is has been accreted to reflect a discount against the note payable totaling $1.2 million at December 31, 2009.
Line of Credit
On January 27, 2009, we entered into the Line of Credit with the LOC Lenders party thereto. Pursuant to the Line of Credit, we could borrow up to $15.0 million, subject to the final approval of each advance by the LOC Lenders. Radion, one of the LOC Lenders, is controlled by the Chairman of our Board of Directors, Kraig Higginson. The commitment amounts under the Line of Credit from each of the LOC Lenders were as follows: $7.2 million from Radion; $5.3 million from Ocean Fund; $2.0 million from Primary Colors; and $500,000 from Mr. Bailey. Under the Line of Credit, advances are subject to the final approval of the LOC Lenders, and amounts borrowed under the Line of Credit accrue interest at the rate of 10% per annum. Under the Line of Credit, each LOC Lender receives warrants (the “LOC Warrants”) to purchase our common stock for each advance of funds made under the Line of Credit. The number of shares underlying each LOC Warrant is equal to 50% of the total amounts funded by the applicable LOC Lender divided by the closing price of our common stock on the date of the advance. The LOC Warrants have an exercise price of $6.00 per share. As of June 30, 2009, we had borrowed $13.4 million of the Line of Credit, and the LOC Lenders had received LOC Warrants to acquire approximately 1,755,048 shares of our common stock at a strike price of $6.00 per share as a result of the amount borrowed. On July 22, 2009, we amended the Line of Credit agreement with the LOC Lenders. Under the amendment, we paid $2.9 million of the loan principal and approximately $0.4 million of accrued interest. In connection with the amendment, the due date of the remaining principal balance was extended until July 31, 2010, without an early payment penalty. However, LOC Lenders have the right to demand early repayment of all or part of the outstanding balance at any time after November 15, 2009. The principal balance, and any accrued interest thereon, can be paid in the form of cash or equity securities at our sole discretion.
On October 19, 2009, we sold shares of our common stock and warrants to three of the LOC Lenders in consideration for $5.4 million in promissory notes (for further discussion of the registered offering see Note 17 “Warrants” and Note 16. “Common Stock” below). On October 23, 2009, we entered into agreements with the three LOC Lenders to cancel the $5.4 million promissory notes as an offset to settle the equivalent amount owed to the participating LOC Lenders for their respective portions of the outstanding Line of Credit balance on that date. Since this transaction, in substance, was an extinguishment of debt, we are required to compute the fair value of the warrants on the date sold and record a loss on extinguishment of debt. We computed the fair value of the warrants using the Black-Scholes option pricing model on the date sold and recorded a loss on extinguishment of debt totaling $2.2 million.
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Notes to Consolidated Financial Statements-(Continued)
In December 2009, we borrowed an additional $115,000 of the Line of Credit and the remaining LOC Lender received additional LOC Warrants to acquire 44,726 shares of our common stock at a strike price of $6.00 per share as a result of the amount borrowed. At December 31, 2009, the amount of principal and accrued interest outstanding on the Line of Credit totaled $5.6 million.
Long-term 7.00% Senior Secured Note (Non-recourse)
On August 31, 2008, we finalized the project financing arrangements for the Thermo No. 1 plant and entered into the Thermo Financing Agreements that provide debt financing and tax equity capital for the Thermo No. 1 plant. According to the Thermo Financing Agreements, the project financing arrangements for the Thermo No. 1 plant included approximately $31.1 million of permanent non-recourse debt financing for the Thermo No. 1 plant with a fixed annual interest rate of 7.00% over 18 years. Our Thermo Subsidiary received proceeds from the debt financing of approximately $26.1 million for construction of the Thermo No. 1 plant after an original issue discount of approximately $5.0 million. After the effect of the original issue discount, the effective interest rate on the $26.1 million of debt financing proceeds is 9.50%. Pursuant to the Thermo Financing Agreements, the debt financing for the Thermo No. 1 plant is held by our Thermo Subsidiary, which is responsible for debt service, all maintenance and operations expenses, and the payment of various fees and distributions to us and Merrill Lynch. Accordingly, if our Thermo Subsidiary defaulted on the loan, there would be no recourse to us to pay the unpaid balance. As of December 31, 2009, we have made principal and interest payments toward the $31.1 million 7.00% senior secured note totaling $724,380 and $2,138,443, respectively.
Long-term 8.00% Convertible Senior Notes
On March 26, 2008, we sold $50.0 million aggregate principal amount of our 8.00% Convertible Notes due 2013 pursuant to the terms of the Purchase Agreement between the Initial Purchaser and us. We granted the Initial Purchaser of the Convertible Notes a 30-day overallotment option to purchase up to an additional $5.0 million aggregate principal amount of the Convertible Notes. On April 1, 2008, we sold an additional $5.0 million aggregate principal amount of the Convertible Notes pursuant to the exercise of the Initial Purchaser’s overallotment option. The Convertible Notes were offered through the Initial Purchaser only to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933, as amended. Six qualified institutional buyers purchased the Convertible Notes. The net proceeds from the sale of the Convertible Notes, after deducting financing fees of $2.2 million, totaled $52.8 million. The Convertible Notes’ financing fees of $2.2 million has been capitalized as a deferred financing fee and will be amortized as additional interest expense over the five-year term of the Convertible Notes. As of October 1, 2009, we had paid the first three semi-annual interest payments to the current holders of the Convertible Notes totaling $6.7 million.
The Convertible Notes bear interest at a rate of 8.00% per annum, which is payable semi-annually. The Convertible Notes are convertible, at the holder’s option, at an initial conversion rate of 108.3658 shares of common stock per $1,000 principal amount of Convertible Notes, which represents a 20% conversion premium based on the last reported sale price of $7.69 per share of our common stock on March 19, 2008. Conversion of all Convertible Notes will result in the issuance of up to a maximum of 5,960,121 shares of our common stock. As of December 31, 2009, none of the Convertible Notes had been converted. The Convertible Notes are unsecured and rank on parity with all of our other existing and future unsecured indebtedness.
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Notes to Consolidated Financial Statements-(Continued)
The table set forth below represents outstanding payments for our long-term senior secured note (non-recourse), convertible senior notes and the Merrill Lynch amended promissory note payable and related scheduled payments as of December 31, 2009:
* Scheduled payments represent payments on the face value of the note without the recorded discount of $4,469,481.
** Scheduled payments represent payments on the face value of the note without the recorded discount of $1,232,846.
*** Scheduled payments represent payments on the face value of the note without the recorded discount of $33,399.
Concurrently, with the pricing of the Convertible Notes, we entered into a call spread option transaction and a confirmation of a forward stock purchase transaction with an affiliate of the Initial Purchaser of the Convertible Notes. We used approximately $15.0 million of the net proceeds from the offering to repurchase shares of our common stock pursuant to the forward stock purchase transaction and approximately $5.9 million of net proceeds to fund the call spread option transaction. We used the remaining net proceeds from the offering for general corporate purposes and to continue well field and other development activities for the geothermal power plants we are developing. For further discussion of the call spread option and forward purchase transaction, refer to Note 16. “Common Stock” below.
On February 15, 2008, we executed a promissory note, whereby we agreed to pay to Lightning Dock Geothermal, Inc. (“Lender”) $900,000 in principal plus $50,000 in interest on or before January 5, 2009. Accrued interest payable on this promissory note at December 31, 2008 totaled $45,833. On January 27, 2009, we settled the promissory note payable and issued to the Lender 263,108 shares of our common stock at a closing market price of $3.35 per share at a fair market value of $881,412.
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Notes to Consolidated Financial Statements-(Continued)
Note 13. Asset Retirement Obligation
The following table sets forth a reconciliation of beginning and ending aggregate carrying amount of asset retirement obligation for the years presented below:
Pursuant to the purchase of our BLM lease in New Mexico, we agreed to assume certain plug and abandon obligations for certain wells on the leased land. Management determined that the present value of the total estimated costs to plug and abandon the wells was $86,193. In February 2008, we plugged and abandoned 11 of the well sites at a cost of $26,453. No additional wells were required to be plugged and abandoned through the year ended December 31, 2009.
We completed the construction of the cooling towers, transmission lines and setting of the PWPS power generating units at our Thermo No. 1 plant in October 2008. In April 2009, we began selling electricity generated by the Thermo No. 1 plant to the City of Anaheim. In connection with the construction of the Thermo No. 1 plant, we have incurred a future obligation to dismantle the geothermal power plant, plug and abandoned our production-sized wells that we have drilled and restore the property to its original state at the end of the power plant’s useful life which is estimated at 35 years. Therefore, we have estimated the present value of the asset retirement liabilities for the Thermo No. 1 plant and for each of the respective wells of approximately $2.5 million. None of the Thermo No. 1 wells have been plugged and abandoned as of December 31, 2009.
Asset retirement liabilities for other projects were estimated at $0.1 million at December 31, 2009.
In connection with our asset retirement obligation, we have posted drilling bonds with the Nevada Department of Minerals totaling $50,000, the Utah Division of Water Rights totaling $50,000 and the Oregon Department of Geology & Mineral Industries totaling $25,000 to ensure that we comply with the local plug and abandonment requirements associated with drilling wells.
Note 14. Noncontrolling Interest
On August 31, 2008 and in conjunction with the Thermo No. 1 plant financing, our Thermo Subsidiary issued new member units to Merrill Lynch, the Class A Member, which contributed $24.5 million in exchange for an equity interest. We received $3.7 million of the total contribution on September 8, 2008 and the remaining balance of $20.8 million was received on October 20, 2008.
The Thermo Financing Agreements provided for the allocation of 99% of profits and losses to the Class A Member until the Class A Member earned a target internal rate of return of 15%. 100% of the intangible drilling costs were allocated directly to us. Upon reaching the target internal rate of return, the Class A Member’s allocation of profits and losses would have automatically been reduced to 5.00%.
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Notes to Consolidated Financial Statements-(Continued)
Because we maintained a 75% voting interest in the Thermo Subsidiary, we consolidated 100% of the assets and liabilities of the Thermo Subsidiary. The Class A Member’s interest in the Thermo Subsidiary was reflected as “Noncontrolling interest” in our consolidated balance sheet and statement of operations.
The Thermo Financing Agreements also contained certain complex liquidation preference provisions that require certain distributions to each of the members of the Thermo Subsidiary in the event of a liquidation. According to the Thermo Financing Agreements, upon liquidation of the Thermo Subsidiary and after payment of all outstanding debt, any remaining funds were to be distributed in the following manner: (i) first, to both the Class A Member and to us in the amount of the agreed upon initial capital contributions for tax purposes, (ii) second, to the Class A Member so that any shortfall in achieving its target internal rate of return of 15% would have been achieved, and (iii) third, to both the Class A Member and to us with an allocation of 5% to the Class A Member and 95% to us. To determine the non-controlling interest, we utilize a hypothetical liquidation at book value methodology at each balance sheet date. For the period ending March 31, 2009, we modified our hypothetical liquidation at book value methodology to include the recast-financial-statements approach. Under the hypothetical liquidation methodology, we utilized the recast-financial-statements approach which captures the initial relevant fair values of the assets and liabilities and follows generally accepted accounting principles for any additional transactions. We believe that the recast-financial-statements approach closely reflected the Class A Member’s claim on the Thermo Subsidiary’s book value at each balance sheet date because the tax equity financing documents with the Class A Member contained a liquidation preference. According to the recast-financial-statements approach, upon the initial sale of the membership interests, the assets and liabilities are hypothetically liquidated at the recast book value at the end of each period and the portions of the Class A Member’s claim relating to liquidation preferences were recorded as gains or losses. Because we had modified our hypothetical liquidation at book value methodology for the period ended March 31, 2009, certain differences resulted in the “Noncontrolling interest” balance at March 31, 2009 as compared to the balance at December 31, 2008 and September 30, 2008. We treated these differences as a correction of an error in the first quarter of 2009. Based on our results of operations for 2009, we do not believe that the correction of the error totaling $2.1 million from the first quarter of 2009 was material to our overall results for 2009. For further discussion of the correction of error, see Note 24. “Quarterly Financial Data” below.
As noted above, on December 4, 2009, we entered into a series of agreements with the Class A Member that amended the provisions August 2008 Thermo financing arrangements. These amendments were necessary to allow the Thermo Subsidiary to apply for a grant under Section 1603 of the Recovery Act. Pursuant to the amendments, we transferred the cost overruns, net of amortization, incurred by us as the EPC contractor on the Thermo No. 1 plant to the Thermo Subsidiary totaling approximately $25.9 million. On December 4, 2009, we also amended the LLC Agreement in which the Class A member withdrew from the Thermo Subsidiary and the tax benefit and profit/loss allocations changed to 0% to the Class A Member and 100% to the Class B Member to be effective on December 11, 2009. Accordingly, we computed the final hypothetical liquidation at book value balance on December 11, 2009 and the noncontrolling interest was eliminated. The difference between the redemption amount for the Class A Member and the noncontrolling interest at December 11, 2009 was recorded as additional paid in capital.
Effective January 1, 2009, we adopted a new accounting pronouncement whereby the FASB established accounting and reporting standards that require non-controlling interests to be reported as a component of equity. Changes in a parent’s ownership interest while the parent retains its controlling interest are to be accounted for as equity transactions. Operating gains or losses attributable to non-controlling interests are excluded from the net profit and loss calculation but included in the earnings and loss per share computations.
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Notes to Consolidated Financial Statements-(Continued)
Non-controlling interest totaled zero and $28.0 million at December 31, 2009 and December 31, 2008, respectively. Changes in non-controlling interest during the year ended December 31, 2009 are set forth below:
From time to time, we were required to pay operating expenses on behalf of the Thermo Subsidiary, which resulted in decreases to the non-controlling interest. We received a reimbursement of operating expenses paid on behalf of the Thermo Subsidiary totaling $750,000 in November 2009.
In accordance with accounting guidance relating to the classification and measurement of redeemable securities, we classified “noncontrolling interest” outside of permanent equity at December 31, 2008 because the Thermo Financing Agreements contained a conditional redemption provision that was based upon the occurrence of an event that was not solely within our control. However, at December 31, 2009, since Merrill Lynch had withdrawn as a tax equity partner effective December 31, 2009, there was no noncontrolling interest.
Note 15. Contingencies and Commitments
We have entered into non-cancelable operating leases for our corporate offices and a testing facility. We have commitments under these leases that extend through December 31, 2011.
Future minimum lease payments under non-cancelable operating leases under the Leases Topic of the FASB Accounting Standards Codification as of December 31, 2009 were as follows:
Total rent expense for the years ended December 31, 2009, 2008 and 2007, was approximately $447,000, $316,000 and $265,000, respectively.
On April 21, 2008, our wholly-owned subsidiary entered into a Road Construction and Maintenance Agreement with Beaver County, Utah to post an improvement bond, or mutually agreed upon equivalent, in the amount of $100,000. We are currently in the process of securing the improvement bond.
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Notes to Consolidated Financial Statements-(Continued)
During 2007 and 2008, we executed multiple purchase agreements with UTCP relating to the purchase of 250 power generating units for the geothermal power plants we intend to develop. Under the provisions of these agreements, we had paid down payments totaling approximately $3.8 million in 2007 and $7.3 million in 2008. On August 31, 2008, we finalized the project financing arrangements to provide for debt financing and tax equity capital for the Thermo No. 1 plant. Concurrent with the closing of the debt financing, our Thermo Subsidiary paid approximately $6.2 million toward the UTCP power generating units received in accordance with the first purchase agreement.
On December 23, 2008, the first purchase agreement with UTCP was terminated and the other purchase agreements with UTCP were amended into three separate purchase agreements (the “Amended Agreements”) to properly reflect the actual distribution of the generating units to the Thermo No. 1 plant site and establish greater flexibility for distribution of the generating units to future projects. Under the Amended Agreements, the deposits and payments already made under the previous purchase agreements were allocated to the new purchase agreements consistent with the actual and intended future distributions of the generating units. In 2009, the purchase agreement was assigned to PWPS. As of December 31, 2008, we were obligated to pay UTCP approximately $56.3 million to complete the agreements of which approximately $34.1 million is included in our accounts payables and accrued liabilities. At December 31, 2009, we were obligated to pay PWPS $5.0 million which is included in our accounts payables.
On April 9, 2009, we entered into an agreement (the “PWPS Agreement”) with Trail Canyon Geothermal No. 1 SV-02, LLC (“Trail Canyon”), Raser Power Systems, LLC and PWPS pursuant to which we and PWPS agreed to terminate certain agreements that had been assigned to PWPS from UTCP relating to power generating units (collectively, the “Terminated Agreements”). Under the terms and conditions of the PWPS Agreement, we agreed to transfer title to PWPS of 113 power generating units previously delivered or held for delivery for us, free and clear of all liens and encumbrances. We and PWPS also agreed that, until the earlier of April 9, 2012 and the date on which we have installed 200 power generating units (in addition to the power generating units installed at our Thermo No. 1 plant), PWPS will be the exclusive provider of heat-to-electricity equipment used for any merchant power plant project developed by us or any of our affiliates so long as PWPS can meet the needs of the particular project. PWPS agreed that it would maintain 50 power generating units in inventory throughout 2009 that would be allocated to us and that we would receive preferential pricing until April 9, 2011. Pursuant to the Terminated Agreements, we had previously paid to UTCP non-refundable deposits totaling $8.9 million. As part of the PWPS Agreement, $1.5 million of these deposits were retained by PWPS as a restructuring charge. PWPS agreed to refund the remaining $7.4 million of deposits (the “Deposit Refund”), subject to the satisfaction of certain conditions. The purpose of the Deposit Refund is to help facilitate payment for certain work necessary for the completion of the Thermo No. 1 plant, including the payment of certain existing accounts payable. Accordingly, PWPS is only required to distribute portions of the Deposit Refund if we (1) provide reasonable documentation to PWPS evidencing the work performed at the Thermo No. 1 plant site by a third party vendor; (2) provide reasonable documentation to PWPS evidencing the payment of such third party vendor; and (3) represent that the amount of the Deposit Refund to be paid is related solely to the Thermo No. 1 plant site and is necessary to keep the project moving forward. The Deposit Refund was released to Raser in installments at times and in the amounts determined at the sole reasonable discretion of PWPS.
Notwithstanding the PWPS Agreement, our agreements with PWPS relating to the purchase of the power generating units for the Thermo No. 1 plant and the associated services agreement remain in full force and effect.
We have also entered into certain purchase obligations including a series of purchase and service agreements whereby certain vendors have agreed to provide certain equipment and services to us. As of December 31, 2009, we were obligated to pay the vendors including PWPS approximately $12.4 million in 2010; $1.3 million in 2011; $1.4 million in 2012; $1.5 million in 2013; and $1.6 million in 2014. Of these obligations
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Notes to Consolidated Financial Statements-(Continued)
approximately $5.1 million of the obligations was included in our accounts payable at December 31, 2009. Since our geothermal lease agreements are not considered to be operating leases under the Leases topic of the FASB Accounting Codification, these purchase obligations include delay rental payments that we have agreed to make in order to maintain our granted rights to the leased properties.
Contingent Options, Warrants and Share Grants
From time to time, we issued contingent options, warrants and share grants as an incentive for performance based compensation or purchase of assets. Below are descriptions of contingent options, warrant and share grants that are outstanding as of December 31, 2009:
We currently maintain a 10-year geothermal lease agreement to obtain the exclusive right to drill for, extract, produce, remove, utilize, sell and dispose of all forms of thermal energy on the private lands in Nevada. This lease was necessary to more fully secure our interest in the property. As part of the consideration for the 10-year geothermal lease agreement we committed to grant 25,000 restricted shares of our common stock, contingent upon successfully placing a geothermal power plant in operation upon the leased lands. At the end of each quarter since the grant date, management assessed the likelihood of completing the contingent requirements and concluded that it remained “reasonably possible” as defined in the Liabilities Topic of the FASB Accounting Standards Codification. Accordingly, we did not recognize equity compensation during the years ended December 31, 2009, 2008 and 2007, respectively.
We granted options to purchase 50,000 shares of our common stock to a key executive in our power systems segment. Vesting of these options is contingent upon successfully placing each of our first three geothermal power plants in service. The options will vest with respect to one third of the shares each time one of the three geothermal power plants is successfully placed in service. The option exercise price is $7.20 per share, which was the closing market price on the grant date. Failure to successfully place any of the first three geothermal power plants in service will result in the forfeiture of one third of the unvested contingent options. During the second quarter of 2008, management assessed the likelihood of completing the contingent requirements and concluded that the completion of the first geothermal power plant was considered “probable” as defined in the FASB Accounting Standards Codification. Accordingly, we recognized equity compensation for the years ended December 31, 2009, 2008 and 2007 totaling $15,981, $80,844 and zero, respectively. For the other two specific projects, management assessed the likelihood of completing the contingent requirements and concluded that it remained “reasonably possible” as defined in the FASB Accounting Standards Codification. Accordingly, we did not recognize equity compensation for the other two specific projects during the years ended December 31, 2009, 2008 and 2007, respectively.
On December 5, 2008, the Board of Directors granted options to purchase 50,000 shares of our common stock to a service provider. The option price is $4.00 per share which exceeded the closing market price on the day of the grant of $3.55 per share. Vesting of these options is contingent upon the successful completion of a strategic transaction which nets to us cash proceeds in an amount greater than or equal to $50.0 million. At December 31, 2009, management assessed the likelihood of completing the contingent requirements as defined in the FASB Accounting Standards Codification. Based on this assessment, management concluded that it is “reasonably possible” that a strategic transaction which nets to us cash proceeds in an amount greater than or equal to $50.0 million will be successfully completed. Accordingly, we did not recognize equity compensation during the years ended December 31, 2009 and 2008.
On April 6, 2009, the Board of Directors granted contingent contractor warrants to purchase 50,000 shares of our common stock to a service provider at an exercise price of $4.00 per shares which exceed the closing market price on the day of the grant of $3.83 per share. Vesting of these the first 25,000 warrants is contingent
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Notes to Consolidated Financial Statements-(Continued)
upon successful execution of a joint venture agreement between Indonesia Power and us for a predefined project. Vesting of the second 25,000 warrants is contingent upon breaking ground for the geothermal power plant to be constructed at the predefined project site in Indonesia. At December 31, 2009, management assessed the likelihood of completing the contingent requirements as defined in the FASB Accounting Standards Codification. Based on this assessment, management concluded that it is “reasonably possible” that a joint venture agreement between Indonesia Power and us will be executed and that ground breaking for the geothermal power plant to be constructed at the predetermined project site in Indonesia. Accordingly, we did not recognize equity compensation during the year ending December 31, 2009.
We entered into a geothermal project alliance agreement whereby a service provider agreed to provide engineering advice to us relating to geothermal drilling and geothermal power plant construction. As part of the consideration for the agreement, we agreed to grant 5,000 shares of common stock upon issuance of a certificate of completion with respect to each of the first three specific projects. During the second quarter of 2008, management assessed the likelihood of completing the contingent requirements and concluded that the completion of the first geothermal power plant was considered “probable” as defined in the FASB Accounting Standards Codification. Accordingly, we recognized equity compensation for the years ended December 31, 2009, 2008 and 2007 totaling zero, $29,100 and zero respectively. For the other two specific projects, management assessed the likelihood of completing the contingent requirements and concluded that it remained “reasonably possible” as defined in the FASB Accounting Standards Codification. Accordingly, we did not recognize equity compensation for the other two specific projects during the years ended December 31, 2009, 2008 and 2007, respectively.
Guarantees
On August 31 2008, we finalized the project financing arrangements for the Thermo No. 1 plant and entered into various definitive agreements (the “Thermo Financing Agreements”). The Thermo Financing Agreements included an equity capital contribution agreement (the “ECCA”) between Thermo No. 1 BE-01, LLC (“Thermo Subsidiary”) and Merrill Lynch LP. Holdings, Inc., the minority member of the Thermo Subsidiary (the “Class A Member”). Pursuant to the ECCA, our Thermo Subsidiary agreed to fund any drilling costs in excess of the original drilling account escrow of $5.7 million established to complete the well field drilling of the Thermo No. 1 plant (the “Drilling Escrow Top Up”). Through December 31, 2009, we have contributed an additional $16.4 million to the drilling account escrow for completion of the well field. These drilling costs are accrued in the period in which they are incurred.
The Thermo Financing Agreements include a guaranty agreement dated August 31, 2008 among our Thermo Subsidiary, the Class A Member, and us (the “Guaranty Agreement”). Under the Guaranty Agreement, we guarantee the full payment of the Drilling Escrow Top Up. Our liability under the Guaranty Agreement will continue until the guaranteed obligation is satisfied in full. We have experienced certain difficulties in ramping up the production of electricity at the Thermo No. 1 plant to full capacity. In light of these difficulties, we may be required to perform certain recompletion work to stimulate the existing wells or drill additional wells to satisfy the production requirements relating to the Final Completion (as defined in the Thermo Financing Agreements) date of June 30, 2010. While we expect to complete our well drilling at the Thermo No. 1 plant during 2010, the maximum potential future payments may be unlimited if our wells cannot produce sufficient resource (both heat and flow) so that the Thermo No. 1 plant can achieve the designated level of electricity generation. These drilling costs are accrued in the period in which they are incurred.
The Thermo Financing Agreements also include an engineering, procurement and construction agreement (the “EPC Agreement”) with our Thermo Subsidiary. Pursuant to the EPC Agreement, we agreed to oversee the engineering, procurement and construction of the Thermo No. 1 plant. In addition, we guaranteed the completion
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
of the geothermal power plant construction and the payment of all services performed by the subcontractors. We expect to make the payments to the subcontractors, including cost overruns, if any, in the ordinary course of business. On December 4, 2009, we entered into a series of agreements with the Class A Member that amended the provisions August 2008 Thermo financing arrangements. These amendments were necessary to allow the Thermo Subsidiary to apply for a grant under Section 1603 of the Recovery Act. Pursuant to the amendments, we transferred the cost overruns, net of amortization, incurred as the EPC contractor during the construction of the Thermo No. 1 plant to the Thermo Subsidiary totaling approximately $25.9 million. Our liability under this agreement will continue until the guaranteed obligation is satisfied in full. We expect to complete our construction phase at the Thermo No. 1 plant prior to the Final Completion date which is currently June 30, 2010.
In connection with the Thermo Financing Agreements, we also entered into an amended and restated purchase contract (the “Amended and Restated Purchase Contract”) with UTC Power (“UTCP”) relating to the purchase of generating units for the Thermo No. 1 plant. The agreements relating to the purchase of the power generating units have since been assigned from UTCP to Pratt & Whitney Power Systems (“PWPS”). Under the terms of the Amended and Restated Purchase Contract, PWPS is required to allow us to retain a certain portion of the purchase price of the generating units pending the successful completion of the Thermo No. 1 plant. If the Thermo No. 1 plant is not successfully completed as a result of a problem with the generating units, then we will keep the retained portion of the purchase price as a liquidated damages payment. If the Thermo No. 1 plant is not successfully completed as a result of any other reason, we will reimburse PWPS for any liquidated damages paid by PWPS. To secure payment of our obligations to reimburse PWPS under the Amended and Restated Purchase Contract, we provided a security interest to PWPS in five patents relating to our Transportation & Industrial segment. We believe that the likelihood that we will be obligated to reimburse PWPS for liquidated damages under the Amended and Restated Purchase Contract is “remote.” Accordingly, we estimate the maximum potential obligation and the related fair value of the obligation under the Amended and Restated Purchase Contract to be immaterial at this time. Therefore, no liability was recorded at December 31, 2009.
The Thermo Financing Agreements also contain a conditional redemption provision whereby the Thermo No. 1 plant must achieve “Final Completion” as defined in the Thermo Financing Agreements, by June 15, 2009. The Final Completion Date has been since extended to June 30, 2010. Under the original Thermo Financing Agreements, if the Thermo No. 1 plant fails to achieve certain levels of production, either the Class A Member or the debt holder could exercise its rights to require us to make a buy-down payment. On December 4, 2009, we entered into a Redemption Agreement (“the Redemption Agreement”) with Class A Member. Pursuant to the Redemption Agreement, the Class A Member withdrew from the Thermo Subsidiary effective on December 11, 2009. Accordingly, the Class A Member is no longer entitled to the buy-down payment. Currently, the buy-down payment is based upon a calculation that effectively enables the current debt holder to achieve the same debt service coverage ratio and economic return anticipated in the original debt agreement. Any amounts payable under the buy-down provision to the debt holder will be disbursed from the $33.0 million grant proceeds we received on February 19, 2010 and were placed in an escrowed account maintained at our Thermo Subsidiary.
If the buy-down computation is greater than $30.0 million, we would have to make up the difference out of general corporate funds. In addition to the buy-down payment, “make whole” penalties are also incurred of approximately 20% of the amount of the buy-down payment. The “make whole” penalties, if any, cannot be estimated at this time and will be determined upon completion of the 10-day performance test prior to Final Completion by June 30, 2010.
After achieving Final Completion, we will compute the buy-down payment and penalties. The buy-down payment and penalties, if any, will be paid to the then current Thermo debt holder. After payment to the Thermo debt holder, based upon the Redemption Agreement, Merrill Lynch would receive up to $20.0 million of the amount remaining to settle the Redemption Note payable. Since Merrill Lynch is required to receive a
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
distribution of the federal grant proceeds of up to $20.0 million, the Redemption Note payable of up to $20.0 million (net of discount), at a minimum, should be classified as a short-term liability. After payments of the buy-down payment and related penalties, if any, and the Redemption Note payable of up to $20.0 million, any remaining funds will be paid to PWPS of up to $4.3 million which is included in our accounts payable balance in current liabilities.
As of December 31, 2009, we did not have any letters of credit or repurchase obligations.
Legal Proceedings
On August 17, 2009, Kay Mendenhall (“Mendenhall”), an individual, and Spindyne, Inc. (“Spindyne”), a Utah corporation, filed a complaint in Fourth Judicial District Court, Utah County, Utah against Jack H. Kerlin, an individual, Kraig Higginson, an individual, and Raser Technologies, Inc. Mendenhall and Spindyne allege that, around the time that Raser was formed, Kerlin, on behalf of Spindyne, assigned to Raser the rights to use certain proprietary technology that was owned by Spindyne. Mendenhall and Spindyne allege that they were not properly compensated for that technology. In general, the complaint alleges, among other claims, breach of contract, breach of implied covenant of good faith and fair dealing, and intentional interference with contract and prospective economic relations. The complaint seeks damages in an amount to be determined at trial for the value of the alleged technology. Neither Spindyne nor Mendenhall have any relationship with us or Mr. Higginson, our Chairman. The alleged technology at issue in the complaint is not currently in use and has never been used by us or, to the knowledge of the Company, by Mr. Higginson. We believe the complaint to be completely without merit and are vigorously defending it.
On May 26, 2009, Bakersfield Pipe and Supply, Inc. (“Bakersfield”) filed a complaint in Fifth Judicial District Court, Beaver County, Utah against Thermo No. 1 BE-01, LLC, Intermountain Renewable Power, LLC and Raser Technologies, Inc., alleging breach of contract. The court has entered a formal judgment against us, and Bakersfield has requested the court to grant a decree of foreclosure, which would authorize Bakersfield to sell all of our property at the Thermo project (including associated transmission easements) at a sheriff’s sale. The complaint sought monetary damages of approximately $1.4 million plus interest and fees. We have accrued for these amounts and hope to reach a settlement with Bakersfield prior to any foreclosure on the Thermo project. Our ability to avoid foreclosure, however, will depend upon our ability to satisfy amounts owed to Bakersfield pursuant to the judgment or any settlement we are able to negotiate with Bakersfield.
Raser is not subject of any other legal proceedings and we are unaware of any proceedings presently contemplated against Raser by any federal, state or local government agency.
Note 16. Common Stock
2009 Registered Direct Offerings
October 2009 Registered Direct Offering
On October 19, 2009, we sold 3,201,526 shares of our common stock and warrants to acquire up to 1,600,763 shares of our common stock to three of the LOC Lenders in consideration for $5.4 million in promissory notes. The common stock and warrants were sold as units (the “Units”), with each Unit consisting of one share of common stock and one warrant to acquire 0.50 shares of our common stock (each, a “Warrant” and collectively, the “Warrants”) at an exercise price of $1.61 per share. The October 2009 Warrants expire on October 19, 2019. Each Unit was sold at a negotiated price of $1.68 per unit. On October 23, 2009, we entered into agreements with the three participating LOC Lenders to cancel the $5.4 million promissory notes as an offset to settle the equivalent amount owed to the participating LOC Lenders for their respective portions of the outstanding Line of Credit balance on that date.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Pursuant to the registered offering, we sold 3,201,526 Units to three of the LOC Lenders, each of whom had advanced funds to us pursuant to the Line of Credit. We did not offer Units to the one lender under the Line of Credit that is controlled by our Chairman of the Board, Kraig Higginson, due to certain regulatory restrictions relating to the sale of Units to an officer. The proceeds from the sale of these units to the three participating LOC Lenders totaled $5.4 million, before deducting estimated offering expenses of approximately $75,000. We accepted promissory notes totaling $5.4 million from the three participating LOC Lenders for the 3,201,526 Units sold. On October 23, 2009, we entered into agreements with the three LOC Lenders to cancel the $5.4 million promissory notes as an offset to settle the equivalent amount owed to the participating LOC Lenders for their respective portions of the outstanding Line of Credit balance on that date.
In connection with the cancelation of the promissory notes, we computed the fair value Warrants issued at $2.1 million. Since these warrants were issued with the stock to extinguish the outstanding debt, we recorded a loss on extinguishment of debt totaling $2.1 million for the year ended December 31, 2009. In addition to the sale of the Units to the three participating LOC Lenders, we also offered an aggregate of 1,120,526 additional Units to certain stockholders and former stockholders of our Company (the “Participation Rights Holders”) pursuant to agreements dated June 30, 2009 between us and the Participation Rights Holders. Each of the Participation Rights Holders was entitled to purchase a number of Units equal to at least its pro rata portion of 35% of the Units offered on the same terms and conditions as the three participating LOC Lenders. None of the Participation Rights Holders elected to participate in this offering.
June 2009 Registered Direct Offering
On June 30, 2009, we entered into a Placement Agent Agreement (the “Placement Agent Agreement”) in which Calyon Securities (USA) Inc., RBC Capital Markets Corporation and JMP Securities LLC served as placement agents relating to a registered direct offering by us of up to an aggregate of 8,550,339 units (“Units”) primarily to institutional investors. Each Unit consists of one share of our common stock, and one warrant to purchase 0.50 share of the Common Stock pursuant to a Warrant to Purchase Common Stock. The sale of the Units was made pursuant to Subscription Agreements, dated June 30, 2009 (the “Subscription Agreements”), with each of the investors. The per share exercise price of the July 2009 Warrants is $4.62 (see Note D. Warrants for further discussion of the July 2009 Warrants).
The investors purchased the Units for a negotiated price of $2.98 per Unit, resulting in gross proceeds to us of approximately $25.5 million, before deducting placement agents’ fees and offering expenses totaling $1.7 million. We closed the registered direct offering on July 6, 2009 and received the net offering proceeds from the sale of the Units, after deducting the placement agents’ fees and other offering expenses totaling approximately $23.5 million.
In connection with the registered direct offering that we completed on July 6, 2009, we granted the investors the right, subject to certain exceptions, to participate in any future equity financing by us prior to December 30, 2010. The participation right allows the registered direct investors to purchase up to 35% of the securities offered at the same terms offered to other investors in future financings. Since these participation rights give the holders the right to purchase stock at market terms, we have concluded that the participation rights should not be separately treated as derivatives
2009 Line of Credit
On January 27, 2009, we entered into an Unsecured Line of Credit Agreement and Promissory Note (the “Line of Credit”), among Radion Energy, LLC (“Radion”), Ocean Fund, LLC (“Ocean Fund”), Primary Colors,
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
LLC (“Primary Colors”) and R. Thomas Bailey, an individual (collectively, the “LOC Lenders”). Pursuant to the Line of Credit, we may borrow up to $15.0 million, subject to the final approval of each advance by the LOC Lenders. Radion is controlled by the Chairman of our Board of Directors, Kraig Higginson. The commitment amounts under the Line of Credit from each of the LOC Lenders are as follows: $7.2 million from Radion; $5.3 million from Ocean Fund; $2.0 million from Primary Colors; and $500,000 from Mr. Bailey. We obtained the Line of Credit in order to provide working capital for general corporate purposes. We intend to repay the borrowings under the Line of Credit primarily with proceeds from other financing arrangements with shares of our common stock. Under the Line of Credit, advances are subject to the final approval of the LOC Lenders, and amounts borrowed under the Line of Credit accrue interest at the rate of 10% per annum. The Line of Credit matures mature and amounts borrowed must be repaid on demand. Under the Line of Credit, each LOC Lender receives warrants (the “LOC Warrants”) to purchase our common stock for each advance of funds made under the Line of Credit. The number of shares underlying each warrant is equal to 50% of the total amounts funded by the applicable LOC Lender divided by the closing price of our common stock on the date of the advance. The warrants have an exercise price of $6.00 per share. As of December 31, 2009, we had borrowed $13.5 million under the Line of Credit, of which $5.6 million remains outstanding. Accordingly, as of December 31, 2009, the LOC Lenders had received warrants to acquire approximately 1,799,774 shares of our common stock at a strike price of $6.00 per share as a result of the amount borrowed.
2008 Private Equity Placement
On November 14, 2008, we sold 2,000,000 shares of our common stock at a fixed price of $5.00 per share in a private equity transaction or $10.0 million. We also sold 2,360,417 shares of our common stock on December 12, 2008 for $4.23654 per share, which is a price per share equal to $10.0 million divided by 110% of the average of the daily volume-weighted average price on the NYSE Arca exchange for the common stock for the ten business days ending on and including December 11, 2008. The gross proceeds from the closing of the November 14, 2008 and December 12, 2008 private placement transactions were $20,000,000, before deducting fees and commissions. We paid commissions of $1,232,000 to a placement agent in connection with the closing of the private placement transactions. In connection with this private placement, we issued 7,458,532 warrants to purchase our shares of common stock (see Note 17. “Warrants” below).
2008 ATM Transaction
On June 17, 2008, we entered into an ATM (at-the-market) Equity Offering Sales Agreement (the “Sales Agreement”) with Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”), pursuant to which we were able to offer and sell through Merrill Lynch, as our sales agent, from time to time, shares of our common stock with an aggregate sales price of up to $25.0 million (the “ATM Program”). Sales of shares under the ATM Program were made by means of ordinary brokers’ transactions on the NYSE Arca exchange at market prices. Merrill Lynch received from us a commission of 2.00%, based on the gross sales price per share, for any shares sold through it as our agent under the Sales Agreement. We began selling shares pursuant to the ATM Program during the third quarter of 2008, and we sold 732,000 shares pursuant to the ATM Program for an aggregate of $7.2 million. After deducting commissions of $0.1 million, we received net proceeds of $7.1 million from the sale of these shares. On August 15, 2008, we entered into an amendment to the Sales Agreement pursuant to which we sold to Merrill Lynch 1,986,173 shares of our common stock in connection with a public offering of such shares at a public offering price per share of $8.95. Merrill Lynch acted as underwriter of the offering. The net proceeds from the sale of the 1,986,173 shares, after deducting Merrill Lynch’s underwriting discount of $695,161 and the offering expenses payable by us, were approximately $17.1 million. The 1,986,173 shares, together with the 732,000 shares previously sold pursuant to the Sales Agreement, constituted all $25.0 million of the shares of common stock contemplated to be sold pursuant to the Sales Agreement.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Stock-Based Compensation
In March 2004, our Board of Directors (the “Board”) adopted the Raser Technologies, Inc. Amended and Restated 2004 Long-Term Incentive Plan (the “Plan”), and in May 2004, our board recommended and the stockholders approved the Plan. The Plan was adopted to facilitate (1) grants of a wider range of stock incentive awards, including restricted stock, stock appreciation rights, performance shares and performance units, (2) an automatic annual increase to the number of shares of common stock reserved for issuance under the Plan beginning in 2005 equal to the lesser of 1,750,000 shares of common stock, 3% of the outstanding shares of common stock on the first day of each fiscal year, or an amount determined by the Board, and (3) optional automatic, nondiscretionary annual stock option grants for employees and non-employee directors. As of December 31, 2009, we were authorized to issue up to 9,693,173 shares of common stock pursuant to the Plan.
Our Board of Directors also participates in an additional compensation plan for our outside directors. The standard equity package under this plan consists of stock awards, each award having a nominal value of $95,000 as of the date of the Annual Meeting of Stockholders (with the actual share award rounded to the nearest round lot of 100 shares). In order to participate in this plan, the Directors were required to make an election which resulted in them retaining all options vested up to that point under previous compensation arrangements and forfeiting all unvested options. Prior to 2008, three of the eligible outside directors elected to adopt this plan. One May 28, 2008, the date of the 2008 Annual Meeting of the Stockholders, three eligible outside directors were granted 9,500 shares each to be delivered on May 28, 2009. On June 25, 2009, the remaining two eligible outside directors elected to adopt this plan. Accordingly, the two outside directors that elected this plan forfeited a cumulative total of 65,000 unvested options. On June 25, 2009, the date of the 2009 Annual Meeting of the Stockholders, all five outside directors were granted a total of 26,000 shares each to be delivered on June 25, 2010. If the director resigns prior to the delivery date, the shares will be forfeited and not delivered.
Employee and Director Share Grants and Option Grants
We granted common stock to our employees and directors totaling 186,593 shares during the year ended December 31, 2009. We also granted options to purchase an aggregate of 816,750 shares of common stock during the year ended December 31, 2009. During the years ended December 31, 2008 and 2007, we granted to our employees and directors 28,500 and 43,100 shares of common stock, respectively, and options to purchase an aggregate of 557,950 and 992,500 shares of common stock, respectively. During the years ended December 31, 2009, 2008 and 2007, vested options expired “out of the money” and were not exercised totaling 0, 78,050 and 2,000, respectively. In September 2008, our Compensation Committee modified the terms of our options to increase the period in which the holder of the vested options is eligible to exercise those options after termination of employment from 90 days to a predetermined formula based upon the number of years of employment. Employees that terminate employment prior to their third anniversary date would be eligible to exercise their vested options for two years after employment terminated. Employees that terminate employment after achieving their third anniversary date will be able to exercise their vested options after employment is terminated based upon the number of years employed.
During the years ended December 31, 2009, 2008 and 2007, employees forfeited 617,750, 92,325 and 10,500 of unvested options to purchase shares of common stock, respectively. The increase in forfeitures during 2009 is primarily due to reductions in corporate staffing levels and executive resignations.
During the years ended December 31, 2009, a former employee forfeited 500 unvested stock share grants. During the year ended December 31, 2008, no unvested share grants were forfeited. During the year ended December 31, 2007, a former employee forfeited 2,000 unvested stock grant shares.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
During the year ended December 31, 2009, no shares of our common stock were issued as a result of option exercises. However, we issued 445,901 shares of our common stock as the result of an anti-dilution provision contained in our 2008 private placement agreement with Fletcher International Limited (“Fletcher”). As a result of the issuance of 445,901 shares to Fletcher, the maximum number of shares of our common stock underlying the Fletcher warrant decreased by 445,901 shares. During the year ended December 31, 2008, we issued 43,125 shares of our common stock as a result of option exercises, and 5,990 shares of common stock as a result of warrant exercises. During the year ended December 31, 2007, we issued 199,500 shares of common stock as a result of option exercises, and 1,069,726 shares of common stock as a result of warrant exercises.
Third Party Share Grants
During the year ended December 31, 2009, in settlement of an outstanding promissory note and outstanding payables to various vendors, we issued 142,013 restricted shares and 3,321,518 unrestricted shares of our common stock to settle outstanding debt totaling $9,327,500. As a result, we incurred a gain on the extinguishment of debt totaling $68,588.
During the year ended December 31, 2008, in settlement of outstanding payables to various venders and to acquire a 10-year geothermal lease with a private land owner in Nevada, we issued 319,779 restricted shares of our common stock to settle outstanding debt and the lease bonus cost totaling $1,848,906. The fair value of the restricted shares on the respective grant dates equaled the amounts outstanding on the respective invoices and lease agreement. The lease costs were capitalized as power project leases and prepaid delay rentals.
During the first quarter of 2007, we issued to three separate owners of geothermal properties in Nevada a total of 7,500 shares of our common stock pursuant to two separate 50-year geothermal lease agreements. The common stock had a fair value totaling $39,800 on the respective grant date. These costs have been capitalized and classified as unproved property and prepaid delay rentals.
During the first quarter of 2007, we granted 200,000 shares of restricted common stock to a service provider to advise us on various matters. Pursuant to the terms of the agreement 150,000 shares were delivered in April 2007 and 50,000 shares were delivered in September 2007. Accordingly, the stock was valued on the grant date and was recognized in the first quarter of 2007 as a non-cash general and administrative expense totaling $990,000.
During the second quarter of 2007, we granted 15,000 shares of registered common stock to a service provider to advise us on engineering matters relating to geothermal drilling and power plant construction. The stock had a fair value on the grant date totaling $110,250 and was recognized as a non-cash power project development expense.
Convertible Preferred Stock
We did not issue convertible preferred stock during the years ended December 31, 2009 and 2008. For discussion of convertible preferred stock issued during 2010, see Note 23. “Subsequent Events”.
Third Party Option and Warrant Grants
Stock options granted to non-employees for services are accounted for in accordance with the Equity Topic of the FASB Accounting Standards Codification which requires expense recognition based on the fair value of the options. We calculate the fair value of options and warrants that have been granted by using the Black-Scholes pricing model.
During the year ended December 31, 2009, we did not grant options to purchase shares of our common stock to third parties.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
On December 5, 2008, we granted options to purchase 95,000 shares of our common stock to a service provider for consulting services to assist us with entering into a corporate alliance to finance the construction of future geothermal power plants. The options have an exercise price of $4.00 per share which exceeded the closing market price on the grant date of $3.55 per share. The options have a fair value of $175,351 which was recorded as power project development expense.
During the third quarter of 2007, we granted options to purchase 35,000 shares of our common stock to the owner of three ranches in Nevada as consideration to secure certain surface rights to the land. The options have an exercise price of $15.10 per share which was established as the closing market price on the grant date. The options had a fair value of $423,987 that was recorded as power project leases.
For discussion of contingently vesting warrants and non-contingently vesting warrants issued during 2009 and 2008 and utilization of a binomial lattice model to calculate their fair value in Note 17. “Warrants” below.
The activity for stock options and warrants during the years ending December 31, 2009, 2008 and 2007, respectively is summarized as follows:
* On August 25, 2009, we issued 445,901 shares of our common stock as a result of an anti-dilution provision contained in our 2008 private placement agreement with Fletcher. As a result of the issuance of 445,901 shares to Fletcher, the maximum number of shares of our common stock underlying the Fletcher warrant decreased by 445,901 shares.
The total intrinsic value of options and warrants exercised in the years ended December 31, 2009, 2008 and 2007 was approximately $1,123,671, $297,394, and $8,943,604 respectively. The cash received from exercises of options and warrants in the years ended December 31, 2009, 2008 and 2007 was approximately $0, $678,597, and $7,294,868, respectively.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The following tables summarize certain stock option and warrant information at December 31, 2009:
Outstanding Options and Warrants Fully Vested and/or Expected to Vest
Outstanding Options and Warrants Fully Vested and Exercisable
The following table summarizes the non-vested stock options at December 31, 2009:
Non-Vested Option Grants
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The following table summarizes the non-vested stock awards at December 31, 2009:
Non-Vested Share Awards
As of December 31, 2009, there was $4,198,807 (pre-tax) and $237,900 (pre-tax) of unrecognized compensation expense related to non-vested stock option and stock award grants, respectively. This expense is expected to be recognized over a weighted average period of 2.19 years. The following table summarizes the unrecognized compensation expense expected to be recognized in future periods at December 31, 2009.
Call Spread Option Transaction
Concurrent with the issuance of the Convertible Notes, we entered into a call spread option transaction with an affiliate of Merrill Lynch for the cost of $5.9 million. The call spread option transaction was intended to reduce the potential dilution of our common stock upon conversion of the Convertible Notes. The Convertible Notes are convertible at any time prior to maturity at a conversion rate of 108.3658 shares per $1,000 principal amount of Convertible Notes, which represents a conversion price of $9.23 per share, subject to adjustment for certain corporate fundamental transactions such as stock splits and stock dividends payments to all stockholders. The call spread option transaction allows us to receive up to 934,118 shares of our common stock at $9.23 per share from the call spread option transaction holder, equal to the amount of our common stock related to the
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
excess conversion value that we would deliver to the holders of the Convertible Notes upon conversion. The number of shares that we would receive pursuant to the call spread option transaction declines after the market price exceeds $11.15 per share to reflect the aggregate market value of $10.4 million of our common stock. The call spread option transaction will terminate upon the earlier of the maturity date of the related Convertible Notes or the first day all of the related Convertible Notes are no longer outstanding due to conversion or otherwise. Our ability to receive the maximum aggregate market value of shares of our common stock pursuant to the call spread option transaction is dependent upon the performance of our stock price and the desire of holders to convert the Convertible Notes into shares of our common stock. If holders fail to convert the Convertible Notes into shares of our common stock prior to the due date in 2013, the call spread option transaction will expire without the shares of our common stock being delivered to us.
In accordance with current accounting guidance, we recorded the $5,850,000 cost of the call spread option transaction as a net reduction in additional paid in capital on the Consolidated Balance Sheets for the year ended December 31, 2008 and will not recognize subsequent changes in fair value.
Forward Stock Purchase Transaction
Concurrent with the issuance of the Convertible Notes, we entered into a forward stock purchase transaction with Merrill Lynch under which we are entitled to receive from Merrill Lynch 1.95 million shares of our common stock on or about the maturity date of the Convertible Notes. The forward stock purchase transaction was also intended to reduce the potential dilution of our common stock that would result from the conversion of the Convertible Notes into shares of our common stock. The Convertible Notes are convertible at any time prior to maturity at a conversion rate of 108.3658 shares per $1,000 principal amount of Convertible Notes, which represents a conversion price of $9.23 per share, subject to adjustment.
In accordance with current accounting guidance, the $15.0 million cost of the forward stock purchase transaction was recorded as a reduction to additional paid in capital on the Consolidated Balance Sheets for the year ended December 31, 2008 and we will not recognize subsequent changes in fair value.
Contingent Options and Share Grants
Refer to discussion of contingent options, warrants and share grants in Note 15 “Commitment and Contingencies” above.
Note 17. Warrants
Derivative Liability Warrants
Effective January 1, 2009, we adopted the provisions of a new accounting pronouncement, which applies to any freestanding financial instruments or embedded features that have the characteristics of a derivative and to any freestanding financial instruments that are potentially settled in an entity’s own common stock. As a result, certain of our issued and outstanding warrants previously treated as equity pursuant to the derivative treatment exemption are no longer considered exempt. Accordingly, effective January 1, 2009, we reclassified the fair value of the warrants described below, which have exercise price reset features, from equity to liability status as if these warrants had been treated as a derivative liability since the date they were issued. The fair value of the derivative liability warrants on January 1, 2009 totaled $27.2 million. At December 31, 2009, the fair value of the derivative liability warrants totaled $11.7 million resulting in a gain on derivatives for the year ended December 31, 2009 totaling $15.0 million.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Fletcher Warrants
As part of a $20.0 million private placement to Fletcher in November of 2008, we issued to Fletcher warrants to acquire shares of our common stock in an aggregate value of up to $20.0 million (the “Fletcher Warrants”). The number of shares issued pursuant to the Fletcher Warrants may not exceed 7,458,532 shares of our common stock. The Fletcher Warrants had an original strike price per share equal to the lesser of (i) six dollars ($6.00) or (ii) a price equal to the weighted-average of the daily market prices of our common stock for the forty (40) business days ending on the third business day prior to the exercise of the Fletcher Warrants, less $0.60, subject to certain adjustments (see “Fletcher Warrants Price Reset Feature” below). In addition, our agreement with Fletcher requires us to issue additional shares to Fletcher if, prior to the first-year anniversary of the 2008 private placement transaction or any exercise of the Fletcher Warrants by Fletcher, we engage in a public disclosure of our intention or agreement to engage in a sale or issuance of any shares of, or securities convertible into, exercisable or exchangeable for, or whose value is derived in whole or in part from, any shares of any class of our capital stock. As a result of the issuance of the units in the July 2009 registered direct offering, we issued 445,901 additional shares of common stock to Fletcher which were delivered in August 2009. Accordingly, as of September 30, 2009, the number of shares that may be issued pursuant to the Fletcher Warrants was reduced by the amount of additional shares issued and may not exceed 7,012,631. Furthermore, as a result of the issuance of additional units in the October 2009 registered offering to the participating LOC Lenders, an additional 218,189 shares became issuable to Fletcher. Since these warrants are no longer subject to the price reset feature described above, the fair value warrants were reclassified from “warrant liabilities” to additional paid in capital on the consolidated balance sheets. As of December 31, 2009, we have not issued the 218,189 shares to Fletcher. As a result of the 218,189 shares becoming issuable to Fletcher, the maximum number of shares of our common stock underlying the Fletcher warrant decreased by 218,189 shares.
At December 31, 2009, based upon an exercise price equal to the weighted average of the daily market prices of our common stock for the forty (40) business days ending on the third business day prior to the exercise of the Fletcher Warrants, less $0.60 on that date, the Fletcher Warrants would have been exercisable for a total of 7,012,631 shares of our common stock. The Fletcher Warrants expire on November 14, 2018. The Fletcher Warrants would generate proceeds totaling $3.9 million, if all of the Fletcher Warrants are exercised unless Fletcher decides to exercise the Fletcher Warrants through a cashless exercise.
Fletcher Warrants Price Reset Feature
As described above, the Fletcher Warrants, issued in November of 2008, would have been exercisable for a total of 5,861,622 shares of our common stock at June 30, 2009. The Fletcher Warrants contain an exercise price reset feature that may be triggered upon certain events, such as the issuance of shares of common stock at a price below the maximum Fletcher Warrant exercise price. If triggered, the exercise price reset feature results in a downward adjustment to the original maximum Fletcher Warrant exercise price of $6.00 per share to an amount equal to the average of the then current maximum exercise price and the lowest price at which shares are issued on the date when the event occurred. On July 6, 2009, we closed a $25.5 million registered direct offering that triggered a price reset with respect to the Fletcher Warrants. Pursuant to the registered direct offering, we sold units of one share of our common stock and one warrant to acquire 0.50 share of our common stock (the “July 2009 Warrants”) for a negotiated price of $2.98 per unit. The per share exercise price of the July 2009 Warrants is $4.62. The issuance of the units in connection with the July 2009 registered direct offering triggered a price reset with respect to the Fletcher Warrants, resulting in a maximum exercise price of $3.99 for the Fletcher Warrants as of September 30, 2009.
On October 22, 2009, we closed a $5.4 million registered offering that triggered another price reset with respect to these warrants. Pursuant to the registered offering, we sold units that included one share of our common
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
stock and one warrant to acquire 0.50 share of our common stock (the “October 2009 Warrants”) for a negotiated price of $1.68 per unit. The per share exercise price of the October 2009 Warrants associated with the units is $1.61. The issuance of the units in connection with the October 2009 registered offering triggered a price reset with respect to the Fletcher Warrants, resulting in a current maximum exercise price of $2.80 for the Fletcher Warrants.
Contingent Warrants
On January 16, 2008, we granted to Merrill Lynch warrants to acquire up to 3,700,000 shares of our common stock, subject to vesting requirements associated with the financing of our geothermal power plants (the “Contingent Warrants”). The Contingent Warrants expire on January 16, 2015. On August 31, 2008, the Contingent Warrants to purchase 1,350,000 shares of our common stock vested in connection with the closing of the project financing arrangements for the Thermo No. 1 plant and became immediately exercisable. In accordance with the accounting pronouncements, the performance criteria related to the vesting of the warrants had been completed. Since the vesting of warrants was a result of closing the project financing, we allocated the fair value between the net proceeds of the debt and the amount of equity contribution in our Thermo Subsidiary. We used a binomial lattice option-pricing model to calculate the fair value of the vested warrants. Accordingly, the fair value of the vested warrants allocated to the issuance of debt totaled $3,999,334 and the fair value of the vested warrants allocated to the equity contribution in our Thermo Subsidiary totaled $3,749,728.
However, since the performance criteria related to the vesting of the remaining unvested warrants has not been completed, we did not recognized the fair value of the unvested Contingent Warrants as deferred financing costs.
On December 4, 2009, as part of the Thermo No. 1 subsidiary restructuring, the original Commitment Letter between Merrill Lynch and us was terminated by mutual agreement which resulted in the cancellation of the remaining unvested Contingent Warrants to acquire 2,350,000 shares of our common stock. As of December 31, 2009, none of the Contingent Warrants had been exercised.
Contingent Warrant Price Reset Feature
The vested Contingent Warrants contain certain anti-dilution provisions which were triggered by the issuance of the Convertible Notes, the issuance of common stock during the third and fourth quarters of 2008, the issuance of the LOC Warrants in connection with the Line of Credit during the second quarter of 2009, resulted in a reduction of the original strike price of the Contingent Warrants from $14.98 to $13.07. The issuance of units in connection with the July 2009 registered direct offering, as described above, and subsequent issuance of shares to Fletcher International also in connection with July 2009 registered direct offer, resulted in a further reduction of the strike price to $11.65. The issuance of units in connection with the October 2009 registered offering resulted in an additional reduction of the strike price to $11.09. The warrants expire on January 16, 2015 and would generate proceeds totaling $15.0 million if all of the warrants vest and are exercised.
The terms of the Contingent Warrants also provide for anti-dilution protection, which adjusts the exercise price of each Contingent Warrant, from time to time upon the occurrence of certain events, including stock splits, dividends, recapitalizations and similar events. Upon the occurrence of such events, the exercise price of the Contingent Warrants will be appropriately adjusted.
Contingent Warrants Call Provision
Any vested warrants may be called for cancellation by us if certain conditions have been met. In general, warrants may be called for cancellation if during any period of twenty (20) consecutive trading days concluding at any time after September of 2008 the closing price of the common stock exceeds a specified price ranging between $23.66 and $39.43 per share.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Series B Warrants
Holders of Series B Preferred Stock were granted 412,691 cash-only exercise warrants equal to 25% of the common stock available to them upon conversion at an exercise price of $8.55 per share. During the year ending December 31, 2009, and 2008, zero and 5,990 warrants were exercised by holders of Series B Preferred Stock, providing $0 and $27,850 in cash to us.
Series B Warrant Price Reset Feature
The Series B warrants also contained an exercise price reset feature based upon certain conditions and events that would cause the warrant exercise price for outstanding warrant holders to be adjusted downward to fair value of the common stock on the date when the event occurred. We had issued shares to a service provider, shares in connection with a private placement, shares in connection with the $20.0 million private placement to Fletcher, and shares issued in connection with the $25.5 million registered director offering with Calyon which triggered the warrant re-pricing feature from the original exercise price of $8.55 per share to a new exercise price of $4.24 per share. On October 5, 2009, 25,243 Series B warrants expired unexercised.
The above warrants that are classified as a derivative liability do not qualify for hedge accounting, and as such, all future changes in the fair value of these warrants will be recognized currently in earnings until such time as the warrants are exercised or expire. In addition, these warrants do not trade in an active securities market, and as such, we estimate the fair value of these warrants using either a Binomial Lattice valuation model or the Black-Scholes option pricing model, whenever appropriate. The fair values of the warrants treated as derivatives were computed using the following assumptions:
The risk-free interest rate is based on a yield curve of interest rates at the time of the grant based on the contractual life of the option. Expected dividend yield is based on our dividend history and anticipated dividend policy. Expected volatility is based on historical volatility for our common stock. We currently have no reason to believe future volatility over the expected remaining life of these warrants is likely to differ materially from historical volatility. The expected life is based on the remaining term of the warrants.
Detachable Warrants
Line of Credit Warrants
On January 27, 2009, we entered into the Line of Credit with the LOC Lenders. Pursuant to the Line of Credit, each of the LOC Lenders received warrants to acquire our common stock for each advance of funds made under the Line of Credit. The number of shares underlying each warrant is equal to 50% of the total amounts funded by the applicable LOC Lender divided by the closing price of our common stock on the date of the advance. The warrants have an exercise price of $6.00 per share. As of December 31, 2009, we had borrowed $13.5 million under the Line of Credit, of which $5.6 million remains outstanding. Accordingly, as of December 31, 2009, the LOC Lenders had received warrants to acquire approximately 1,799,774 shares of our common stock at a strike price of $6.00 per share as a result of the amount borrowed. Since these warrants were issued based upon the amount that we borrowed from our Line of Credit, we allocated the total proceeds from the Line of Credit to the debt and the warrants. The amount of proceeds allocated to the warrants was recorded as a
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
discount totaling approximately $4.2 million which was accreted up to the face value of the Line of Credit over the life of the loan. As of December 31, 2009, we had expensed approximately all of the $4.2 million relating to the discount. For further discussion of the Line of Credit refer to Note 12. “Short-Term and Long-Term Debt Instruments” above.
There is no anti-dilution or pricing reset feature associated with the Line of Credit warrants. As of December 31, 2009, none of the Line of Credit warrants had been exercised.
July 2009 Warrants
On July 6, 2009, we closed our $25.5 million registered direct offering in which we sold an aggregate of 8,550,339 units primarily to institutional investors. Each unit consisted of one share of our common stock, and one warrant to purchase 0.50 share of our common stock pursuant to a Warrant to Purchase Common Stock. Accordingly, we issued warrants to purchase 4,275,170 shares of our common stock to the participants in the July 6 registered direct offering. The July 2009 Warrants have an exercise price of $4.62 per share and expire on July 6, 2014.
There is no anti-dilution or pricing reset feature associated with the July 2009 Warrants. As of December 31, 2009, none of the July 2009 Warrants had been exercised.
October 2009 Warrants
On October 22, 2009, we completed our registered offering in which we sold an aggregate of 3,201,526 units to certain of the LOC Lenders in connection with the settlement of $5.4 million of the outstanding Unsecured Line of Credit. Each unit consisted of one share of our common stock, and one warrant to purchase 0.50 share of our common stock pursuant to a Warrant to Purchase Common Stock. Accordingly, we issued warrants to purchase 1,600,762 warrants to the participants in the October 22 registered offering. The October 2009 Warrants have an exercise price of $1.61 per share and expire on October 19, 2019.
There is no anti-dilution or pricing reset feature associated with the October 2009 Warrants. As of December 31, 2009, none of the October 2009 Warrants had been exercised.
Contractor Warrants
On October 25, 2007, we issued warrants to purchase 15,000 shares our shares of common stock to a service provider for advice, counsel and other investor relations services. The warrants carry an exercise price of $12.06 which is equal to the five day average closing price of our common stock prior to the contract signature date. The contract signature date is also the grant date. The warrants vest on October 25, 2008, and expire on October 25, 2011. The expense was properly recognized in 2007.
On March 11, 2009, we also issued warrants to purchase 122,603 shares to a service provider for construction services relating to the Thermo No. 1 transmission lines in order to partially settle outstanding payable balances totaling $250,000. The fair value of the warrant on the grant date approximated the amount of the debt settled totaling $250,000. The warrants carry an exercise price of $5.35 per share and expire on March 11, 2014. As of December 31, 2009, none of the Contractor Warrants had been exercised.
Contingent Contractor Warrants
Refer to discussion of contingent options, warrants and share grants in Note 15. “Commitment and Contingencies” above.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The following table summarizes the warrants outstanding and exercisable at December 31, 2009:
Contingent Warrants Registration Rights Agreement
In connection with the Commitment Letter and the issuance of warrants to purchase up to 3,700,000 shares of our common stock, we entered into a registration rights agreement that provides the holder of the warrants with certain rights to register the resale of the warrants and the shares of common stock issuable upon exercise of the warrants. Warrants to purchase up to 1,350,000 shares of our common stock vested upon the completion of the Thermo No. 1 financing. On December 4, 2009, both Merrill Lynch and we cancelled the Commitment Letter resulting in the forfeiture of warrants to purchase 2,350,000 of our common stock. Upon a series of warrants vesting, we are obligated to register the shares underlying the vested warrants for resale pursuant to the exercise of such warrants and cause the registration statement to remain continuously effective until all vested warrants are exercised or expired. Merrill Lynch agreed to permit us to defer our obligation to register the resale of the warrants to purchase 1,350,000 shares of our common stock until such registration is requested by Merrill Lynch. We do not believe the merger of Merrill Lynch’s parent with Bank of America Corporation will alter our obligations under the registration rights agreement with Merrill Lynch. Management currently believes that the likelihood we will fail to register the shares in accordance with the registration rights agreement or fail to cause the registration statement to remain continuously effective is “remote” as defined in accounting literature. Accordingly, no accrued liability is deemed necessary.
Fletcher Warrants Registration Rights Agreement
In connection with our $20.0 million private placement on November 14, 2008 described above, the purchasers of the common stock and related warrants also entered into a registration rights agreement that
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
required us to register the resale of the common stock purchased in the private placement and pursuant to the exercise of related warrants. We were obligated to file a registration statement with the United States Securities and Exchange Commission registering the sale of the shares of common stock and the shares of common stock underlying the Warrants no later than November 14, 2008, and to use our best efforts to cause the registration statement to be declared effective by December 29, 2008, for the first 2.0 million shares of our common stock purchased and by January 30, 2009, for the remaining 2.3 million shares purchased and the related 7.5 million warrants. We are also obligated to use our best efforts to keep the registration statement continuously effective. Liquidated damages for failure to become effective or maintain effectiveness of the registration statement on Form S-3 equals one percent of the $20.0 million received per month up to a maximum of $2.0 million in aggregate. Our registration statement on Form S-3 was not declared effective by the SEC due to unresolved comments from their SEC Comment Letters. Accordingly, we recorded a liability to accrue for the liquidated damages totaling $800,000. In connection with our February 2010 issuance of $5.0 million of convertible preferred stock, we received a waiver of all outstanding liquidated damages from Fletcher International. See Note 23. “Subsequent Events” for further discussion.
Note 18. Net Loss Per Common Share
Basic net loss per common share (“Basic EPS”) is computed by dividing the net loss applicable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted net loss per common share (“Diluted EPS”) is computed by dividing net loss applicable to common stockholders by the sum of the weighted average number of common shares outstanding and the weighted average dilutive common share equivalents then outstanding. The computation of Diluted EPS does not assume exercise or conversion of securities that would have an anti-dilutive effect. Common share equivalents consist of shares issuable upon the exercise of options and warrants to purchase common stock, the conversion of any convertible debentures and related accrued interest, and shares issuable upon conversion of any preferred stock.
The following table sets forth the number of shares that would be outstanding if outstanding securities convertible into common stock were converted into common stock, whether the convertible securities were “in the money” or “out of the money” based upon the closing market price on December 31, 2009:
The following table sets forth the number of shares that would be outstanding if outstanding securities convertible into common stock were converted into common stock, whether the convertible securities were “in the money” or “out of the money” based upon the closing market price on December 31, 2008:
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
These warrants and options were not included in the calculation of diluted net loss per share because their effect was anti-dilutive. Unvested stock grants totaling 130,000 and 30,084 were outstanding on December 31, 2009 and 2008, respectively. Since these shares were granted to employees and Board of Directors, and contain certain rights as defined by the share grant agreements, they were included in the net loss per share computation.
We also agreed to contingently grant 5,000 shares of common stock to a service provider upon issuance of a certificate of completion with respect to each of the first three specific geothermal power plant construction projects. During the second quarter of 2008, management assessed the likelihood of completing the contingent requirements and concluded that the completion of the first geothermal power plant was considered “probable” as defined in the FASB Accounting Standards Codification. As of December 31, 2009 management also assessed the likelihood of completing the contingent requirements as “reasonably possible” as defined in the FASB Accounting Standards Codification for the remaining 10,000 contingent share grants. Our common stock underlying the call spread option transaction and forward stock purchase transaction would be recorded as treasury stock when delivered and; therefore, would be excluded from the calculation of diluted net loss per share because their effect is anti-dilutive.
Note 19. Fair Value Measurement
Effective January 1, 2008, we adopted the new accounting guidance relating to fair value measurements as required by the Fair Value Measurement Topic of the FASB Accounting Standards Codification, for financial instruments measured at fair value on a recurring basis and effective January 1, 2009 on a non-recurring basis. The new accounting guidance defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States and expands disclosures about fair value measurements.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting Standards Codification Topic 820 establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring 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). These tiers include:
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Level 1, defined as observable inputs such as quoted prices for identical instruments in active markets;
•
Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable such as quoted prices for similar instruments in active markets or quoted prices for identical or similar instruments in markets that are not active; and
•
Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions, such as valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.
Warrants
Effective January 1, 2009, we adopted the new accounting guidance relating to determining whether a financial instrument is indexed to its own stock as required by the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. The adoption of the new accounting guidance can affect the accounting for warrants and many convertible instruments with provisions that protect holders from a decline in the stock price (“down round” provisions). For example, warrants with such provisions will no longer be recorded in equity. Down round provisions reduce the exercise price of a warrant or convertible instrument if a company either
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
issues equity shares for a price that is lower than the exercise price of those instruments or issues new warrants or convertible instruments that have a lower exercise price. We evaluated whether warrants to acquire shares of our common stock contain provisions that protect holders from declines in the stock price or otherwise could result in modification of the exercise price and/or shares to be issued under the respective warrant agreements based on a variable that is not an input to the fair value of a “fixed-for-fixed” option. Accordingly, we determined that the following warrants contained such provisions, thereby concluding they were not indexed to our common stock:
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Series B Warrants, exercisable for 25,243 shares of our common stock that expired unexercised on October 5, 2009
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Contingent Warrants issued to Merrill Lynch, exercisable for 1,350,000 shares of our common stock, that expire January 16, 2015
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Fletcher Warrants to acquire shares of our common stock in an aggregate value of up to $20.0 million that may not exceed 7,012,631 shares of our common stock, exercisable at December 31, 2009 for 7,012,631 shares of our common stock, that expire November 14, 2018.
For further discussion of these financial instruments, refer to Note 17. “Warrants” and Note 16. “Common Stock.”
Beginning January 1, 2009, we recognized these warrants as liabilities at their respective fair values on each reporting date. The cumulative effect of the change in accounting for these warrants of $7.2 million was recognized as an adjustment to the opening balance of accumulated deficit at January 1, 2009. The cumulative effect adjustment was the difference between the amounts recognized in the consolidated balance sheet before January 1, 2009 and the amounts recognized in the consolidated balance sheet after January 1, 2009. The amounts recognized in the consolidated balance sheet on January 1, 2009 were determined based on the amounts that would have been recognized if the change had been applied from the issuance date of the warrants. We measured the fair value of these warrants as of March 31, 2009, and recorded a $0.9 million loss on derivatives and recorded the liabilities associated with these warrants at their respective fair values as of March 31, 2009. For the quarter ended June 30, 2009, we measured the fair value of these warrants as of June 30, 2009, and recorded a $7.9 million gain on derivatives. We also recorded the liabilities associated with these warrants at their respective fair values as of June 30, 2009. We also measured the fair value of these warrants as of September 30, 2009, and recorded a $5.9 million gain on derivatives for the quarter ended September 30, 2009 and recorded the liabilities associated with these warrants at their respective fair values as of September 30, 2009. The Series B Warrants expired on October 5, 2009. Accordingly, we no longer computed the fair value of the Series B Warrant after their expiration. We also measured the fair value of the remaining warrants as of December 31, 2009, and recorded a $2.1 million gain on derivatives for the quarter ended December 31, 2009 and recorded the liabilities associated with these warrants at their respective fair values as of December 31, 2009. We determined the fair values of these securities using the Binomial Lattice and Black Scholes valuation models when appropriate.
Asset Retirement Obligations
We report the fair value of asset retirement obligations on a nonrecurring basis in our consolidated balance sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 19. “Asset Retirement Obligations” for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances which represent the entirety of our Level 3 fair value measurements.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The following table represents the fair value hierarchy for assets and liabilities measured at fair value at December 31, 2009:
See asset retirement obligations rollforward at Note 19. “Asset Retirement Obligation”.
Cash and cash equivalents and restricted cash measured using Level 1 inputs consist primarily of money market accounts that are traded on active exchange markets. Valuations are obtained from readily available pricing sources for market transactions involving identical instruments.
Restricted cash measured using Level 2 inputs consist of certificates of deposit. Valuations are generally obtained from third party pricing services for or comparable instruments (and validated through back testing to trade data or confirmation that the pricing service’s significant inputs are observable) or determined through use of valuation methodologies using observable market inputs such as market interest rates.
We determined the fair value of the Contingent Warrants and the Fletcher Warrants using a Binomial Lattice valuation model that considered their down round provisions that reduce the exercise price if we issues new warrants or equity at a lower price. The model considered the historical volatility of our stock price. See discussion of variable inputs to the valuations of these warrants in Note 17. “Warrants” above.
Recurring Level 3 Activity, Reconciliation and Basis for Valuation
The table below provides a reconciliation of the beginning and ending balances for the major classes of assets and liabilities measured at fair value using significant unobservable inputs (Level 3). The table reflects gains and losses for the quarter for all financial assets and liabilities categorized as Level 3 as of December 31, 2009.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3) (in thousands):
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The carrying amounts reported in the accompanying consolidated financial statements for cash and cash equivalents, accounts receivable, notes receivable, interest receivable, accounts payable and accrued liabilities approximate fair values because of the immediate or short-term maturities of these financial instruments.
Note 20. Business Segments
The basis for presenting segment information results generally is consistent with our overall operating practices. All consolidating items and corporate administrative costs are included in Corporate and Other.
We pursue opportunities to develop technologies in the Power Systems market to supplement the development of technologies targeted for the Transportation & Industrial markets. Accordingly, the presentation below comprises financial information relating to the years ended December 31, 2009, 2008 and 2007, respectively.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Included in total assets for the Power Systems segment is a note receivable from a potential merger candidate totaling $0, $0 and $506,273 at December 31, 2009, 2008 and 2007, respectively.
Note 21. Income Taxes
As required by the Income Taxes topic of the FASB Accounting Standards Codification, we are required to determine whether it is more likely than not that a tax position will be sustained upon examination based upon the technical merits of the position. If the more-likely-than-not threshold is met, a company must measure the tax position to determine the amount to recognize in the financial statements. The application of income tax law is inherently complex. Laws and regulation in this area are voluminous and are often ambiguous. As such, we are required to make many subjective assumptions and judgments regarding the income tax exposures. Interpretations of and guidance surrounding income tax laws and regulations change over time. As such, changes in the subjective assumptions and judgments can materially affect amounts recognized in the balance sheets and statements of income.
There has been no significant change in the unrecognized tax benefit during the years ended December 31, 2009 and 2008, respectively.
We classify interest and penalties arising from the underpayment of income taxes in the statement of income under general and administrative expenses. As of December 31, 2009, we had no accrued interest or penalties related to uncertain tax positions. The tax years 2006-2009 federal return remains open to examination. The Internal Revenue Service completed their examination of our 2005 federal tax return without significant adjustment to our financial statements. However, the Internal Revenue Service reserves the right to audit the original tax returns for any year in which a net operating loss originated and is utilized through the carryback provisions of the Internal Revenue Code. Since we have incurred a net operating loss for each year of operations since 2004, the portion of the 2004 and 2005 tax returns that relate to the computation of the net operating loss remains open to examination . In addition, tax years 2006-2008 also remain open to examination by other taxing jurisdictions to which we are subject.
At December 31, 2009, we had net operating loss carry-forwards available to offset future taxable income of approximately $107,178,000 which will begin to expire in 2021 for federal tax purposes and 2018 for state tax purposes. The utilization of the net operating loss carry-forwards is dependent upon the tax laws in effect at the time the net carry-forwards can be utilized. The Internal Revenue Code contains provisions that likely could reduce or limit the availability and utilization of these net operating loss carry-forwards. For example, limitations are imposed on the utilization of net operating loss carry-forwards if certain ownership changes have taken place. We will perform an analysis to determine whether any such limitations have occurred as the net operating losses are utilized.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The amount of, and ultimate realization of, the benefits from the net operating losses is dependent, in part, upon the tax laws in effect, our future earnings, and other future events, the effects of which cannot be determined.
At December 31, 2009, we had a research and development tax credit totaling $1.1 million. The research and development credit will begin to expire in 2019 for federal tax purposes. We have established a valuation allowance for all deferred income tax assets not offset by deferred income tax liabilities due to the uncertainty of their realization. At December 31, 2009 the valuation allowance totaled $51.3 million representing an increase of $14.9 million over the valuation allowance at December 31, 2009. Approximately $0.8 million related to the “true up” of the 2008 tax return filed in 2009. Accordingly, there is no benefit for income taxes in the accompanying consolidated statements of operations.
Deferred income taxes are determined based on the estimated future effects of differences between the financial statement and income tax reporting bases of assets and liabilities given the provisions of currently enacted tax laws and the tax rates expected to be in place. The deferred income tax assets (liabilities) are comprised of the following at December 31, 2009 and December 31, 2008:
Reconciliations between the benefit for income taxes at the federal statutory income tax rate and our benefit for income taxes for the years ended December 31, 2009 and December 31, 2008 is as follows:
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
Note 22. Supplemental Cash Flow Information
For the year ended December 31, 2009:
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We paid $6,979,552 for interest and $400 for income taxes.
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We recorded in accrued liabilities certain capitalized well field development expenditures that were not paid as of December 31, 2009. These accrued capitalized costs included both tangible and intangible drilling costs and were omitted from the statement of cash flows as non-cash items totaling $3,825,735.
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We recorded in accrued liabilities and accounts payable certain capitalized power systems equipment and contractor fees that were not paid as of December 31, 2009. These accrued expenses included equipment such as pumps, cooling towers, generating units and related construction costs for a geothermal power plant under construction. These accrued capitalized costs were omitted from the statement of cash flows as non-cash items totaling $5,959,042.
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We recorded five non-cash payments totaling $40,000 for 11,035 shares of our common stock issued to settle outstanding invoices from two service providers for consulting relating to our PHEV project. The non-cash payments were equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $2,000,000 non-cash payment for 574,713 shares of our common stock issued to settle an outstanding invoice from a service provider for construction of our Thermo No. 1 plant. The non-cash payment approximated the fair market value of the shares on the date the shares were granted.
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We recorded a $950,000 non-cash payment for 263,108 shares of our common stock issued to settle a promissory note with a former merger candidate that was settled on January 27, 2009. The non-cash payment resulted in a gain on extinguishment of debt totaling $68,588.
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We recorded five non-cash payments totaling $3,500,000 for 70,197 restricted shares of our common stock, 1,004,094 unrestricted shares of our common stock, and 122,603 warrants to acquire shares of our common stock issued to settle an outstanding invoice from a service provider for construction of our Thermo No. 1 plant. The non-cash payment approximated the fair market value of the shares on the date the shares were granted.
•
We recorded four non-cash payments totaling $216,290 for 20,000 restricted shares of our common stock and 88,810 unrestricted shares of our common stock issued to settle outstanding invoices from two service providers for consulting relating to our investor relations and expansion of our geothermal operations. The non-cash payment approximated the fair market value of the shares on the date the shares were granted.
•
We recorded nineteen non-cash payments totaling $2,939,800 for 1,431,574 shares of our common stock to settle outstanding invoices from the service providers for construction of our Thermo No. 1 plant. The non-cash payments approximated the fair market value of the shares on the date the shares were granted.
For the year ended December 31, 2008:
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$2,944,000 was paid for interest and $400 was paid for income taxes.
•
We recorded in accrued liabilities certain capitalized well field development expenditures that were not paid as of December 31, 2008. These accrued capitalized costs included both tangible and intangible drilling costs and were omitted from the statement of cash flows as non-cash items totaling $7,389.063.
•
We recorded in accrued liabilities and accounts payable certain capitalized power systems equipment and contractor fees that were not paid as of December 31, 2008. These accrued expenses included
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
equipment such as pumps, cooling towers, generating units and related construction costs for a geothermal power plant under construction. These accrued capitalized costs were omitted from the statement of cash flows as non-cash items totaling $32,885,311.
•
We recorded as an increase to power project leases and to asset retirement obligation for the present value cost to decommission our power plant and plug the related wells totaling $2,066,037.
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We recorded a $450,000 non-cash payment for 45,732 shares of our common stock issued to settle an outstanding invoice from a service provider for design and engineering services relating to construction of a geothermal power plant. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $419,000 non-cash payment for 100,000 shares of our common stock issued to settle a portion of an outstanding invoice from a service provider for design and engineering services relating to construction of a geothermal power plant. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $318,814 non-cash payment for 22,217 shares of our common stock issued to settle an outstanding invoice from a service provider for design and engineering services relating to construction of a geothermal power plant. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $51,158 non-cash payment for 3,565 shares of our common stock issued to settle an outstanding invoice for professional services related to obtaining the proper permits that enable us to drill for geothermal resources. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $9,930 non-cash payment for 1,000 shares of our restricted common stock issued to acquire geothermal mineral rights on properties in Nevada. The non-cash payment was equal to the fair market value of the shares on the date the 10-year geothermal leases were signed.
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We recorded a $450,000 non-cash payment for 112,782 shares of our common stock issued to settle a portion of an outstanding invoice from a service provider for design and engineering services relating to construction of a geothermal power plant. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
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We recorded a $150,000 non-cash payment for 34,483 shares of our common stock issued to settle a portion of an outstanding invoice from a service provider for construction services for our Thermo No. 1 plant. The non-cash payment was equal to the fair market value of the shares on the date the shares were granted.
For the year ended December 31, 2007:
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No cash was paid for interest and $300 was paid for income taxes.
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We recorded a $39,800 non-cash payment of 7,500 shares of our common stock issued to acquire the geothermal rights on properties in Nevada. The non-cash payment was equal to the fair market value of the shares on the date the 50-year geothermal leases were signed.
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We recorded a $990,000 non-cash payment of 200,000 shares of restricted common stock issued to a service provider for advisory services. The non-cash payment was equal to the fair market value of the shares on the date the advisory services payment was approved by our Board of Directors.
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We recorded an $110,250 non-cash payment of 15,000 shares of unrestricted common stock issued to a service provider for advisory services. The non-cash payment was equal to the fair market value of the shares on the date the advisory services agreement was signed.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
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We recorded a $423,987 non-cash payment of options to purchase 35,000 shares of common stock at an exercise price of $15.10 per share issued to acquire the geothermal surface rights on land in Nevada. The non-cash payment was equal to the fair market value of the shares on the date the issuance was approved by the Board of Directors.
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We recorded an $118,889 non-cash payment of warrants to purchase 15,000 shares of our common stock at an exercise price of $12.06 per share issued to a service provider for investor relations services. The non-cash payment was equal to the fair market value of the shares on the date the service provider agreement was signed.
Note 23. Subsequent Events
On February 3, 2010, we completed the sale of 5,000 shares of Series A-1 Cumulative Convertible Preferred Stock (the “Preferred Stock”), pursuant to which we raised $5.0 million, before deducting underwriters’ fees, legal fees and other expenses. Each share of the Preferred Stock will pay a quarterly dividend, payable in cash or shares of common stock equal to an annual rate of LIBOR plus eight percent (8%), but in no event higher than 14%, subject to adjustment. Each share of the Preferred Stock will be convertible into shares of our common stock at a price of $5.00 per share, such price being subject to adjustment for stock splits, recombinations, stock dividends and the like. The holders of the Preferred Stock will have the right to redeem the shares of the Preferred Stock purchased at the earlier of six months after the issue date or the date on which the price of our common stock equals or exceeds $2.00 per share, or the date of a public announcement of the intention or agreement to engage in a transaction or series of transactions that may result in a change of control of our Company. The redemption price for each share of the Preferred Stock into shares of our common stock will be at least $1.22 per share of our common stock, subject to adjustment under certain circumstances and (b) 120% of the Prevailing Market Price (as defined in the Certificate of Rights and Preferences of the Preferred Stock) at the first redemption date. We also issued warrants (the “Preferred Warrants”) to purchase up to an additional 14,000 shares of the Preferred Stock.
On December 8, 2009, we submitted our application for a U.S. Department of Treasury grant under Section 1603 of the Recovery Act (the “Grant”) totaling approximately $33.0 million. On February 19, 2010, we received the Grant totaling $33.0 million. Although the actual Grant was not received until February 19, 2010, the Grant was deemed completed by the U.S. Department of Treasury on December 22, 2009. Accordingly we recorded the federal grant receivable on December 22, 2009.
On February 19, 2010 we received the full grant amount of $33.0 million. Under the terms of the Restructuring Amendments, approximately $3.8 million was distributed to us. The remaining proceeds received from the Grant were placed into an escrow account and will be paid out in the following order on or about June 30, 2010: (i) first Prudential will potentially receive a pre-payment, together with a pre-payment penalty, of its outstanding debt, depending on the performance of the Thermo No. 1 plant at the time; (ii) project escrow accounts will be funded as required by the Thermo Financing Agreements; (iii) Merrill Lynch will receive its Redemption Amount (as described above); (iv) Pratt & Whitney Power Systems will receive any amounts left owing to it as the turbine supplier for the Thermo No. 1 plant; and (v) any remaining amounts will be placed in a revenue escrow account and will ultimately flow through as a distribution to us.
On December 4, 2009, the parties to the Thermo Financing Agreements entered into a series of amendments to the Thermo Financing Agreements (the “Amendments”) in order to extend the Final Completion Date of the Thermo No. 1 plant. On February 16, 2010, the parties to the Thermo Financing Agreements entered into additional definitional amendments in order to extend the date upon which the Thermo project is required to achieve Final Completion from February 16, 2010 to June 30, 2010.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
On January 25, 2010, Nicholas Goodman began employment as the Chief Executive Officer. In connection with Mr. Goodman’s employment, his annual base salary is $300,000. Mr. Goodman also received options to purchase 228,571 shares of our common stock at an exercise price of $1.05 per share. The stock options had a fair market value of $199,200 on the date of the grant and will vest quarterly over three years.
On January 15, 2010, Martin F. Petersen resigned as Chief Financial Officer. John T. Perry began employment on March 10, 2010. His duties as Chief Financial Officer will begin on March 22, 2010. In connection with Mr. Perry’s employment, his annual base salary is $250,000. Mr. Perry also received options to purchase 194,174 shares of our common stock at an exercise price of $1.03 per share. The stock options had a fair market value of $165,700 on the date of the grant and will vest quarterly over three years. Since Mr. Perry will not have assumed his duties as Chief Financial Officer when the December 31, 2009 Form 10-K is issued, Mr. Clayton will certify the December 31, 2009 Form 10-K as the Principal Financial Officer.
Note 24. Selected Quarterly Financial Data (unaudited)
Selected quarterly data (unaudited) for the years ending December 31, 2009 and 2008 are as follows:
Significant year end adjustments for 2008 include expensing the costs of two wells at the Thermo No. 1 plant and expensing the cost of one well at the Truckee project totaling $13.6 million. The result of this adjustment in 2008 is an increase in our loss per share in the fourth quarter of 2009 calculation of $(0.22) per share.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
As discussed in Note 14. “Noncontrolling Interest”, noncontrolling interest decreased during the first quarter of 2009 by $2.1 million due to a correction of an error from a prior period that resulted from modifying our hypothetical liquidation at book value computation to include a basis adjustment that arises under the recast-financial-statement approach. The noncontrolling interest calculation during the first quarter of 2009 was computed utilizing the modified methodology for the period covering August 31, 2008 to March 31, 2009. As a result of modifying our hypothetical liquidation at book value methodology, our loss per share for the first quarter of 2009 decreased by $0.03 per share. Since we did not record the correction of error in the prior year due to its immaterial effect to the December 31, 2008 financial statements, below represents the net effect during the current year of recording the correction of error in the December 31, 2009 financial statements.
We believe that this prior period adjustment listed above did not materially impact the 2009 consolidated financial statements for the year ended December 31, 2009 or for any interim period.
Reclassification of quarterly consolidated condensed statement of cash flows (unaudited)
In connection with preparing the December 31, 2009 consolidated financial statements, management determined that the unaudited condensed consolidated statements of cash flows for the quarters ended September 30, 2009, June 30, 2009, and March 31, 2009, included in our Quarterly Reports on Form 10-Q for those quarters, incorrectly classified certain quarterly amounts as cash used in operating activities that should have been classified as cash used in investing activities for such periods.
In connection with the preparation of the consolidated financial statements for the year ended December 31, 2009, we have reclassified certain amounts in our unaudited financial statements for the quarters ended September 30, 2009, June 30, 2009 and March 31, 2009 in order to be consistent with the presentation contained in the financial statements included in this Annual Report on Form 10-K.
RASER TECHNOLOGIES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements-(Continued)
The reclassifications identified in connection with the year-end closing result in a decrease in the cash used in operating activities which is offset by an increase in investing activities for each of the periods ended September 30, 2009, June 30, 2009, March 31, 2009, September 30, 2008, June 30, 2008 and March 31, 2008 as follows:
These adjustments correct the previously incorrect classification of certain transactions as changes in accounts payable and accrued liabilities which should have been classified as geothermal property, plant, and equipment purchases and geothermal deposits. These adjustments do not affect any of the assets, liabilities, or equity accounts of our unaudited condensed consolidated balance sheets and they do not affect any of the revenue and expense accounts of our unaudited condensed consolidated statements of operations, including our net loss per share, for the periods ended March 31, 2009, June 30, 2009 and September 30, 2009.