ITEM 1. DESCRIPTION OF BUSINESS
Information Regarding Forward Looking Statements
This document contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve a number of risks and uncertainties. We caution readers that any forward-looking statement is not a guarantee of future performance and that actual results could differ materially from those contained in the forward-looking statement. These statements are based on current expectations of future events. You can find many of these statements by looking for words like “believes,” “expects,” “anticipates,” “intend,” “estimates,” “may,” “should,” “will,” “could,” “plan,” “predict,” “potential,” or similar expressions in this document or in documents incorporated by reference in this document. Examples of these forward-looking statements include, but are not limited to:
our business and growth strategies;
our future results of operations;
anticipated trends in our business;
the capacity and utilization of our geothermal resources;
our ability to successfully and economically explore for and develop geothermal resources;
our exploration and development prospects, projects and programs, including construction of new projects and expansion of existing projects;
availability and costs of drilling rigs and field services;
our liquidity and ability to finance our exploration and development activities;
our working capital requirements and availability;
our illustrative plant economics;
market conditions in the geothermal energy industry; and
the impact of environmental and other governmental regulation.
These forward-looking statements are based on the current beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements:
the failure to obtain sufficient capital resources to fund our operations;
unsuccessful construction and expansion activities, including delays or cancellations;
incorrect estimates of required capital expenditures;
increases in the cost of drilling and completion, or other costs of production and operations;
the enforceability of the power purchase agreements for our projects;
impact of environmental and other governmental regulation, including delays in obtaining permits;
hazardous and risky operations relating to the development of geothermal energy;
our ability to successfully identify and integrate acquisitions;
our dependence on key personnel;
the potential for claims arising from geothermal plant operations;
general competitive conditions within the geothermal energy industry; and
financial market conditions.
All subsequent written or oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this document or to reflect the occurrence of unanticipated events, except as may be required under applicable U.S. securities law. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.
The U.S. dollar is the Company’s functional currency; however some transactions involved the Canadian dollar. All references to “dollars” or “$” are to United States dollars and all references to $ CDN are to Canadian dollars.
U.S. Geothermal Inc. (the “Company,” “HTM” or “we” or “us” or words of similar import) is in the renewable “green” energy business. Through its subsidiary, U.S. Geothermal Inc., an Idaho corporation (“Geo-Idaho,” although our references to the Company include and refer to our operations through Geo-Idaho), we are engaged in the acquisition, development and utilization of geothermal resources in the Western Region of the United States of America. Geothermal energy is the natural heat energy stored within the earth’s crust. In some areas of the earth, economic concentrations of heat energy result from a combination of geological conditions that allow water to penetrate into hot rocks at depth, become heated, and then circulate to a near surface environment. In these settings, commercially viable extraction of the geothermal energy and its conversion to electricity become possible and a “geothermal resource” is present.
Development of Business
History
Geo-Idaho was formed as an Idaho corporation in February 2002 to conduct geothermal resource development. On March 5, 2002, Geo-Idaho entered into a letter agreement with the previous owner, pursuant to which Geo-Idaho agreed to acquire all of the real property, personal property and permits that comprised the owner’s interest in the Raft River project located in southeastern Idaho.
The Company and Geo-Idaho entered into a merger agreement on February 28, 2002, which was amended and restated on November 30, 2003, and closed on December 19, 2003. In accordance with the merger agreement, the Company acquired Geo-Idaho through the merger of Geo-Idaho with a subsidiary, EverGreen Power Inc., an Idaho corporation formed for that purpose. Geo-Idaho is the surviving corporation and the subsidiary through which the Company conducts operations. As part of this acquisition, we changed our name to U.S. Geothermal Inc. Because the former Geo-Idaho shareholders became the majority holders of the Company, the transaction is treated as a “reverse takeover” for accounting purposes.
We currently operate two power plants that include, Raft River Unit I in Idaho (through our joint venture with Raft River I Holdings, LLC, a subsidiary of Goldman Sachs) and a plant located in the San Emidio Desert in Nevada. We also have several other properties under development or exploration. Raft River Unit I (“RREI”) commenced commercial operations on January 3, 2008. Raft River Unit I is currently selling an annual average of 8 megawatts (“MWs”) of power to Idaho Power Company under a net 13 MW power purchase agreement (“PPA”) which expires in 2032. Management is currently evaluating alternatives to bring the RREI plant operations to its nameplate capacity of 13 MW.
In May 2008, we acquired the geothermal assets, including a 3.6 net MW nameplate generating capacity power plant, from Empire Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada for approximately $16.6 million which includes the Granite Creek geothermal and certain ground water rights. The plant currently generates an approximate average net output of 2.5 MWs, which is sold to Sierra Pacific Power Corporation. With the recent downturn in the economy we have been focusing our efforts on maximizing the available leverage to our existing equity investments and pursuing a development plan with lower risks by avoidance of exploration drilling of production wells. As a result we are planning a 35 MW development in three phases with the first phase a “repower” facility at San Emidio which will use the existing geothermal fluid feeding the existing plant to feed a new plant. The plant size is estimated to be 8.6 net MWs and currently is under construction and expected to be on line in late 2011. The second phase is a planned 8.6 net MW module similar to the first phase unit and is expected to be online in the second quarter of 2013. The second phase unit requires additional drilling for production and injection wells to support the plant and that work is underway and supported by a $3.77 million cost sharing exploration grant from the DOE. The third phase is anticipated to add 17.2 MW of power supplied from new production wells to be drilled but requires a significant transmission line upgrade. The third phase is planned to be on line late 2013.
On September 5, 2006, the Company announced the acquisition of property for a geothermal project at Neal Hot Springs, Oregon located in eastern Oregon near the Idaho border. The property is 8.5 square miles of geothermal energy and surface rights. On May 5, 2008, the Company announced that drilling had begun on the first full size production well (“NHS-1”) which was completed on May 23, 2009. In February 2009, the Company submitted an application for the project to the U.S. Department of Energy’s (“DOE”) Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Solicitation loan guarantee program under Title XVII of the Energy Policy Act of 2005. On May 26, 2009, the Company announced that it had been selected by DOE to enter into due diligence review on a project loan. Construction on a drill pad was completed in August 2009. In September 2009, the Company began drilling production well number 5 (“NHS-5”), which was substantially completed on October 15, 2009. Also, in September 2009, the Company began a temperature gradient well program to expand the knowledge of the entire geothermal resource. On December 14, 2009, the Company announced that its wholly owned subsidiary USG Oregon LLC has signed a 25-year power purchase agreement with Idaho Power Company that provides for the sale of up to 25 MWs. The PPA was approved by the Idaho PUC in May of 2010. The financial closing for the DOE loan guarantee took place in February 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at the 22 year treasury rate plus approximately 37 basis points when each advance is drawn. With a $13 million equity investment made by Enbridge Inc. to acquire a 20% interest, the project is 100 percent financed.
Plan of Operations
Our management examines different factors when assessing potential acquisitions or projects at different stages of development, such as the internal rate of return of the investment, technical and geological matters and other relevant business considerations. We evaluate our operating projects based on revenues and expenses, and our projects under development, based on costs attributable to each project.
We have exploration and development properties located in:
Raft River, Idaho;
Neal Hot Springs, Oregon;
San Emidio, Nevada;
Gerlach, Nevada;
Granite Creak, Nevada; and,
Republic of Guatemala.
Our business strategy is to identify, evaluate, acquire, develop and operate geothermal assets and resources economically, safely and efficiently. We intend to execute this strategy in several steps outlined below:
Leverage Management Team Capabilities and Experience - Our strategy is focused on the identification and acquisition of resources that can be developed in a cost-effective manner to produce attractive returns. In particular, we seek to acquire projects that have already undergone geothermal resource discovery. In addition, we intend to operate and manage construction of the projects, while using internal personnel and third-party contractors to efficiently and cost-effectively develop those resources. We believe that we have the strategic personnel in place to determine which resources provide the greatest opportunity for efficient development and operation. We have developed relationships and employed personnel that will allow us to develop and utilize geothermal resources as efficiently as possible.
Develop Our Pipeline of Quality Projects - Our project pipeline currently consists of several projects that we believe are aligned with our growth strategy. These projects have consulting reports from various industry experts supporting our belief in those projects’ potential, and we have started PPA negotiations for power off-take with counterparties for some of these growth opportunities. If realized, our identified project pipeline will greatly expand our renewable power generation capacity.
Utilize Production Tax Credits, Investment Tax Credits and Other Incentives - Although geothermal power production can be cost competitive with fossil fuel power generating facilities without government subsidies in some cases, production tax credits (“PTC”) and Investment Tax Credits (“ITC”) available to geothermal power producers enhance the project economics and attract capital investment. For the Raft River Unit I project, we partnered with Goldman Sachs as a tax equity partner to fully utilize production tax credits available to the project. Our strategy going forward is to structure project ownership to be the primary beneficiary of project economics. Recent legislation enacted as part of the stimulus funding has provided an election to take 30% ITC in lieu of the PTC for certain qualified investments being initiated before the end of 2010 and being placed in service before the end of 2013. This ITC election may be available to us at our San Emidio and Neal Hot Springs projects.
Pursue Acquisition Strategy - The geothermal market, particularly in the United States, is fragmented and characterized by a few large players and a number of smaller ones. Geothermal exploration and development is costly, technically challenging and requires long lead times before a project will produce revenue. We believe that geothermal technical and managerial talent is limited in the industry and that access to capital to develop projects will not be equally available to all participants. As a result, we believe that there will be opportunities in the future to pursue acquisitions of geothermal projects and/or geothermal development companies with attractive project pipelines.
Evaluate Other Potential Revenue Streams from Geothermal Resources - In addition to electricity generation, we will evaluate additional applications for our geothermal resources including industrial, agriculture, and aquaculture purposes. These uses generally constitute lower temperature applications where, after driving a turbine generator, residual hot water can be cycled for secondary processes before being returned to the geothermal reservoir by injection wells, which can provide incremental revenue streams. We will evaluate the optimal use for each geothermal resource and determine whether selling heat for industrial purposes or generating and subsequently selling power to a grid will generate the highest return on the asset.
Cash Requirements
We believe our cash and liquid investments at March 31, 2011 are adequate to fund our general operating activities through March 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, the issuance of equity and/or through the sale of ownership interest in tax credits and benefits.
The current financial credit crisis is not anticipated to impact the ability of our customers, Idaho Power Company and Sierra Pacific Power, to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. Projections for 2011 indicate that both projects, Raft River and San Emidio, will generate positive cash flows to the Company. However, the current status of the credit and equity markets could delay our project development activities while the Company seeks to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels. We are also pursuing additional available DOE loans and guarantees in order to reduce interest costs for any debt instruments the Company may require.
On March 7, 2011, the Company closed a direct registered placement of 5,000,000 shares of Common Stock at a price of $1.00 per share for gross proceeds of $5 million. Each investor also received a Common Stock Purchase Warrant exercisable for 50% of number of shares of Common Stock purchased. Each Warrant will entitle the holder to purchase one additional share of Common Stock for $1.075 per share. The Warrants expire March 3, 2012. The issue included a placement agent fee of 112,000 Common Shares and 56,000 Warrants plus expenses of approximately $15,000. The securities were offered by the Company pursuant to a registration statement filed with the Securities and Exchange Commission (“SEC”), which became effective on December 31, 2010. A prospectus supplement relating to the offering was filed with the SEC on February 28, 2010. After deducting for fees and expenses, the net proceeds were approximately $4.95 million. The net proceeds of the offering will be used for general working capital, including exploration, development and expansion of its geothermal properties
On February 24, 2011, the Company completed the financial closing with the U.S. Department of Energy (“DOE”) of a $96.8 -million loan guarantee to construct its planned 23-megawatt-net power plant at Neal Hot Springs in Eastern Oregon. Neal Hot Springs is the first geothermal project to complete a loan guarantee under DOE’s Title XVII loan guarantee program, which was created by the Energy Policy Act of 2005 to support the deployment of innovative clean energy technologies. The DOE loan guarantee will guarantee a loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 -million Federal Financing Bank loan represents 75% of total project cost. When combined with the previously announced equity investment by Enbridge Inc., the loan provides 100 percent of the anticipated capital remaining to fully construct the project.
In September 2010, USG Oregon LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note. Upon conversion, the note shall be considered to be an equity contribution to the Company’s subsidiary. The conversion occurs automatically upon the closing of the Department of Energy (“DOE”) guaranteed project loan. The agreements also provide for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note, will earn Enbridge a 20% direct ownership in the subsidiary. In the event of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $5 million would be contributed by Enbridge that would increase their direct ownership by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments could increase Enbridge’s ownership to a maximum of 27.5%.
In August 2010, USG Nevada LLC (a wholly owned subsidiary) entered into agreements with Benham Companies, LLC (subsidiary of Science Applications International Corporation) for a project loan. The project loan is expected to provide substantially all of the funding needed to construct an 8.6 net megawatt power plant for Phase I of the San Emidio project in northwest Nevada. Construction costs are estimated to be approximately $32 million and expected to be completed in October 2011. The construction loan is planned to be repaid with long term financing from available sources such as the Section 1705 loan guarantee program from the U.S. Department of Energy.
On March 16, 2010, the Company closed a private placement of securities issued pursuant to a securities purchase agreement (the "Purchase Agreement") entered into with several institutional investors, pursuant to which the Company issued 8,209,519 shares of common stock at a price of $1.05 per share for gross proceeds of approximately $8.6 million (the "Private Placement"). Pursuant to the terms of the Private Placement, each investor was also issued a common share purchase warrant (a "Warrant") exercisable for 50% of the number of shares of common stock purchased by the investor. The Company paid commissions to agents in connection with the Private Placement in the amount of approximately $516,000 and issued warrants to purchase up to 246,285 shares of common stock. The net proceeds of the offering (approximately $8.0 million) will be used by the Company to further develop its Neal Hot Springs geothermal project and for general working capital purposes.
On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets.
On August 17, 2009, the Company completed a private placement of 8,100,000 Subscription Receipts (“Receipt”) at $1.35 CDN per Receipt for aggregate gross proceeds of CDN $10,935,000. Each Receipt was exchanged on December 17, 2009 for one share of common stock of the Company and one half of one common stock purchase warrant (a "Warrant"). Each Warrant entitles the holder thereof to acquire one additional share of common stock of the Company for $1.75 for 24 months from closing. The placement agents have been paid an aggregate cash fee of CDN $656,100, representing 6% of the aggregate gross proceeds of the offering, and have been issued compensation options, exercisable for 24 months, entitling the placement agents to purchase up to 243,000 shares of common stock of the Company at $1.22. The proceeds provided funds to drill production size wells at Neal Hot Springs to increase production capacity to 22 MW and allow a 30-day flow test to verify the well reservoir capacity. Completion of drilling is a condition precedent to the funding from the DOE loan program, if our application is approved.
Material Acquisitions/Development
Raft River, Idaho
Raft River Energy Unit I, located in southern Idaho, is a binary cycle geothermal power plant with 13 net megawatts of installed capacity. The power plant achieved commercial operation in January 2008.
Raft River Unit I operated at 98.4% availability and generated an average of 7.95 net megawatts during the fourth fiscal quarter. For the 2010 calendar year, the plant averaged 8.39 net megawatts of generation with 97.7% availability. The plant is operating at reduced output due to the continued loss of temperature from production well RRG-7 and the shutdown of production well RRG-2.
In early January 2009, production well RRG-7 underwent a temperature decline that has now reduced the inlet fluid temperature to the power plant by approximately 11.8 degrees Fahrenheit. Power generation has been reduced by an estimated 1.5 megawatts due to the lower fluid temperature entering the plant. It was determined that the cement in a lap joint (an overlap of well casing) had failed and washed out, thereby allowing lower temperature fluid to enter the wellbore. Production well RRG-2 was shut down on June 10, 2010 due to a reduction in flow and increased motor load which indicates an impending pump failure.
The project does not generate sufficient revenue to complete the repairs out of cash flow so the repairs must be completed by additional capital investment by the partners or some other infusion of capital. Until the repairs are completed, the plant output will continue at an estimated annual average of about 7.8 megawatts.
Subsequent to the end of the quarter, Raft River I Holdings consented to a repair plan for both RRG-2 and RRG-7. A Repair Services Agreement was executed between US Geothermal Services and Raft River Energy I LLC, whereby US Geothermal Services will provide up to $1.65 million in funding and manage the well repairs. The cost of the repairs will be repaid from project cash flow, and will be paid preferentially at a rate of 90% of increased cash created by the repairs. A fee of 12.75 percent of the actual repair cost incurred will be paid to USG Services. The outstanding balance of the repair cost will also earn USG Services interest income at the rate of 12.0 percent per-annum.
A pump rig was mobilized to the Raft River site on May 16 and began working on well RRG-2. If the repair program is completed successfully, the Company expects the annual average output of the plant to increase approximately 25% from a current level of approximately 8 megawatts annual average to approximately 10 megawatts. In addition to the well repairs, a flow stimulation technique called deflagration will be applied to wells RRG-2 and RRG-7 which may increase fluid flow from the known production zones. Deflagration has been used successfully in geothermal wells that contain productive zones that have been damaged by drilling mud or drill cuttings during drilling operations, with demonstrated increases in well permeability of up to 50 percent. If successful, additional power generation may be realized from the well stimulation program.
The $10.2 million DOE cost-shared thermal fracturing program continues on schedule. Eight solar powered seismic stations were installed in June and will be used to monitor potential impacts from the test. Construction is complete on the injection pipeline that extends from the Unit 1 power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was completed during the 3rd fiscal quarter of 2010. It is now expected that a drill rig will be mobilized to set casing down to the geologic formation targeted for the thermal fracture test, and the first phase of cold water injection will commence during the 2nd calendar quarter of 2011.
San Emidio, Nevada
The San Emidio geothermal power plant has been producing power since 1987 and sells electricity to Sierra Pacific Power Corporation under an existing power purchase agreement that extends through 2017. Deeper wells with higher temperatures were drilled in 1994 to supply the plant after output declined due to cooling of the original, shallow production wells. The current configuration of the plant consists of four 1.2 gross megawatt Ormat Energy Converters (“OEC”), five production wells (two wells in use), and four injection wells (three wells in use and one on standby). A cooling tower was added in 1998 to improve summer peak power generation. During the third fiscal quarter ended December 31, 2010, the San Emidio plant operated at 99.6% availability and generated an average of 2.63 net megawatts during the period.
The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be the expansion. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth calendar quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Subsequent to the end of the period, the Company received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification on this matter, however, we believe third-party financing will be available for Phases I and II even without the loan guarantee, although the interest rate on such financing may be higher without the loan guarantee. Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. The Phase I repower began construction in the third calendar quarter of 2010. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the second calendar quarter of 2013. The Company expects to utilize Investment Tax Credits in connection with both the repower and the Phase II expansion. Both Phases I and II will require an amendment to the Sierra Pacific Power Purchase Agreement. Phase III is expected to follow construction of Phase II and be online by the fourth quarter of 2013. Both Phase II and Phase III are subject to successful development of additional production wells through exploration and drilling activities.
Phase I will utilize the existing production and injection wells with the installation a new, more efficient power plant. The existing, historic power plant will be placed on operational standby when the Phase I plant comes on line. As shown in the Project Development table below, the Phase I repower is anticipated to cost approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We believe 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.
The Phase I power plant began construction in August of 2010, with final completion scheduled to occur at the end of October 2011. All major foundations have been placed, main brine line tie to the new plant site completed, transmission line from the new plant site to the existing line installed, and the fresh water line for the cooling tower installed. Subsequent to the end of the quarter, the chemical building has been constructed, the main transformer is installed, and the cooling tower is being erected. The bulk of the major components for the power plant are scheduled to start arriving in late June and early July.
Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the second calendar quarter of 2013. The Company expects that the project will be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.
On June 1, 2011, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The PPA is subject to signature by NV Energy and approval by the Public Utility Commission of Nevada.
The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction contract for the San Emidio Phase I power plant. SAIC’s design-build subsidiary, the Benham Companies LLC, will execute the construction of an 8.6 net megawatt power plant at San Emidio, Nevada. TAS Energy of Houston, Texas will supply a modular power plant to the project. The financing agreement calls for the contractor to provide a non-recourse project loan for the estimated $32 million dollar project. The construction loan is expected to be repaid with long term project loan.
Two System Feasibility Studies were initiated in July 2008 with Sierra Pacific Power Company to begin the FERC mandated transmission study process for the development of the San Emidio resource. The studies examined two levels of power generation; 15 megawatts and 45 megawatts, several transmission routes and the costs associated with each level of generation. The 15 megawatt study, which is directed toward the Phase I repower and Phase II, has completed the study process and resulted in an increase of available transmission to 16 megawatts. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010.
The 45 megawatt study, which is directed toward the full build out of San Emidio with the addition of the 17.2 megawatt Phase III project, completed the second phase System Impact Study in April. A draft Interconnection Facilities Study, the third and final study, was received on November 22, 2010. The remainder of the 45 megawatt study has been put on hold pending further exploration of the project.
On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of Phase II of its San Emidio geothermal power project using advanced geophysical exploration techniques and drilling. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture factures that represent high-productivity geothermal drilling targets.
Surface geologic mapping by the University of Nevada-Reno has been completed and structural analysis of the mapping is underway. State-of-the-art interpretation of satellite data that measures ground surface deformation has also been completed. Preliminary results show excellent correlation between surface deformation and known producing fractures, establishing this method as an effective tool for locating wells. Field work for a high-precision seismic refraction survey is complete. Data processing and interpretation is complete and has been integrated with the structural mapping.
The results of the DOE exploration program have been finalized and submitted to the DOE for review. Drill sites have been selected, and permitting is underway for a targeted 3rd quarter start on the drilling program.
Neal Hot Springs, Oregon
Neal Hot Springs, located in Malheur County, Oregon, has been established as a commercial geothermal resource.
On February 26, 2009 U.S. Geothermal submitted a loan application for the Neal Hot Springs project to the DOE’s Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Solicitation loan guarantee program under Title XVII of the Energy Policy Act of 2005. The financial closing for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at 37.5 basis points over the current average yield on outstanding marketable obligations of the United States of comparable maturity. With the $18.8 million equity investment made by Enbridge Inc., the estimated project cost is 100 percent financed.
Notice to proceed was issued to both the EPC contractor (Industrial Builders Inc.) and equipment supplier (TAS Energy) on February 24, 2011. Detailed design and construction of the supercritical cycle power plant utilizing significantly improved technology is currently in progress. The new plant, which will consist of three separate power modules, is designed to deliver approximately 23 megawatt of power net to the grid. The first module is scheduled to begin commercial operations in December 2011 and the full plant is scheduled to be completed during the 4th quarter 2013.
A long term reservoir test was initiated on November 16, 2010 with two production wells flowing brine at an average of 1,800 to 2,000 gallons per minute. Two injection wells were operated in tandem with the production to dispose of the fluid and to provide additional reservoir data. The flowing portion of the test ran until December 20, 2010 when the production wells were shut in and injection was halted. For a following 30 days, temperature and pressure instruments were maintained in the wells until January 24, 2011 when they were pulled and data downloaded.
Geologic information, flow, temperature and pressure data from the production and T/G drilling programs and the long term reservoir test is being incorporated into the ongoing development of a numerical reservoir model of the Neal Hot Springs geothermal system. The reservoir model was completed on March 24, 2011 and the DOE independent reservoir engineer issued a reservoir certificate on March 31, 2011. The final reservoir report and certificate confirmed that the reservoir was able to sustain the production necessary for the planned 23 megawatt project from the existing four production wells. An injection plan was developed as part of the plan, and drilling operations resumed in April, 2011 to complete the injection well field for the project. A large diameter injection well, NHS-12 is being drilled on the western boundary of the geothermal field to an anticipated depth of 5,000 feet.
As part of the injection well program, a temperature gradient (“TG”) well was started on the south end of the resource area to help determine the limit where heat flow from the active geothermal reservoir extended. This extension of heat flow would be used to site a deep injection well. Subsequent to the end of the quarter, the TG well was completed to 3,020 feet deep and indicated a positive temperature gradient.
On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C). Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.
The Company received the Conditional Use Permit from the Malheur County Planning Commission for construction of its proposed 23 net megawatt power plant at Neal Hot Springs in eastern Oregon. The Conditional Use Permit received unanimous approval at a September 24, 2009 Planning Commission meeting and was issued on October 28, 2009. All of the Federal Energy Regulatory Commission (“FERC”) mandated transmission studies have been completed by Idaho Power Company. An interconnection agreement was signed with the Idaho Power Company in February 2009. Private right-of-ways for the transmission line have been acquired, the line route is surveyed and the final engineering design is complete. Idaho Power Company is responsible for the construction of the transmission line with the cost paid for by the project. A notice to proceed was issued to Idaho Power Company to commence procurement and construction of the transmission line on April 8, 2011.
The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per megawatt-hour and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions.
Gerlach Joint Venture
The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was re-drilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at a total depth of 1,070 feet. Temperature surveys and a short clean out flow test were conducted on the well.
A 2,000 foot deep temperature gradient well is permitted for the BLM lease site and is designed to test the deep temperature potential of the central portion of the interpreted reservoir block. A production target has been identified from previous drilling data at a depth of 2,700 to 3,000 feet.
Granite Creek, Nevada
The Granite Creek assets are comprised of three BLM geothermal leases totaling approximately 5,414 acres (8.5 square miles) located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser. A first stage gravity geophysical program was completed in the third quarter of 2008 and will be used to evaluate the resource potential, and help determine where to drill temperature-gradient exploration wells.
Republic of Guatemala
A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April. The concession contains 24,710 acres (100 square kilometers) in the center of the Aqua and Pacaya twin volcano complex.
The concession contains the El Ceibillo geothermal project which has nine existing geothermal wells that were drilled in the l990s and have depths ranging from 560 to 2,000 feet (170 to 610 meters). Six of the wells have measured reservoir temperatures in the range of 365°F to 400°F and have high conductive gradients that indicate rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicate the existence of a high permeability reservoir below the existing well field.
An office and staff are located in Guatemala City and planning is underway to advance the project with initial work focused on negotiating necessary surface and access rights, a power sales agreement with the local utility company, strategic investors, and potential project lenders. Follow on work will include a detailed geophysical program, geologic mapping, sampling of hot springs, and to redrill one or two of the existing wells to test for deep, high temperature permeability. Discussions and planning are underway for the development of a power purchase agreement. Discussions are also taking place with several interested parties for the potential sale of a minority equity interest in the El Ciebillo project to a qualified local partner.
(1) Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently varies between 7.1 and 10.0 megawatts and output of the San Emidio plant is approximately 2.6 megawatts.
(2) As part of the financing package for Unit I of the Raft River project, we have contributed $16.5 million in cash and approximately $1.5 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project. Additional investment may be required for Unit I to operate at design capacity.
(3) The repower below includes repairs to operating power plants.
(1)
In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”) may provide up to $23.8 million in funds for the Neal Hot Springs geothermal project. After the planned debt conversion and additional contribution in April of 2011, Enbridge has contributed $18.8 million which they have received a 20% ownership interest in the project.
(2)
As part of the financing package for Unit I of the Raft River project, we have contributed $16.5 million in cash and approximately $1.5 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project. Additional investment may be required for Unit I to operate at design capacity.
(1)
A third party’s assessment of 94 megawatts was based on 6.0 square miles. The Company acquired additional acreage. The resource estimate of 127.0 megawatts was provided by Geothermex.
(2)
Actual production temperatures for existing wells.
(3)
Probable reservoir temperature as measured with a geothermometer.
(4)
A estimate by Black Mountain of 44.0 megawatts.
(5)
A third party resource estimate with respect to 23.0 megawatts, remainder is an internal estimate.
(6)
An estimate provided by Geothermex.
Employees
At March 31, 2011, the Company had 34 full-time and one part time employee (13 administrative and project development, and 24 field and plant operations). The Company continuously considers acquisition opportunities, and if the Company is successful in making acquisitions, additional management and administrative staff may be added.
The Company did not experience any labor disputes or labor stoppages during the current fiscal year.
Principal Products
The principal product is based upon activities related to the production of electrical power from the utilization of the Company’s geothermal resources. The primary product will be the direct sale of power generated by our interests in our geothermal power plants. Currently, our principal revenues consist of energy sales, energy credit sales, management fees and lease income. All power plants currently under exploration or development are sites located in the Western Region of the United States of America. The Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America in April of 2010. Development options are currently being explored to determine how to maximize this opportunity.
Sources and Availability of Raw Materials
Geothermal energy is natural heat energy stored within the Earth’s crust at economically accessible depth. In some areas of the Earth, economic concentrations of heat energy result from a combination of geological conditions that allow water to penetrate into hot rocks at depth, become heated, and then circulate to a near surface environment. In these settings, commercially viable extraction of the geothermal energy and its conversion to electricity become possible and a “geothermal resource” is present.
There are four major components (or factors) to a geothermal resource:
1. 	
Heat source and temperature - The economic viability of a geothermal resource is related to the amount of heat generated. The higher the temperature, the more valuable the geothermal resource.
2. 	
Fluid - A geothermal resource is commercially viable only when the system contains water and/or steam as a medium to transfer the heat energy to the surface.
3. 	
Permeability - The fluid present underground must be able to move. In general, significant porosity and permeability within the rock formation are needed to create a viable reservoir.
4. 	
Depth - The cost of development increases with depth, as do resource temperatures. The proximity of the reservoir to the surface is therefore a key factor in the economic valuation of a geothermal resource.
Electrical power is directly produced through the utilization of geothermal resources; however, these resources are not a direct component of the final product.
The reservoir located in Raft River, Idaho is a proven geothermal resource, and has a 13 net MW capacity geothermal power plant in operation (Raft River Energy I LLC). San Emidio, Nevada is a proven geothermal resource, and has a 3.6 net MW capacity geothermal plant in operation. Based upon the tests of the completed wells and other studies, the reservoir in Neal Hot Springs Oregon has been established as a commercial geothermal resource. Unless major geological changes occur that impact the geothermal reservoirs, the condition of the existing resources is expected to remain consistent over time.
Significant Patents, Licenses, Permits, Etc.
Raft River. Five significant permits are in place for the Raft River project and are necessary for continued operations:
1. 	
Geothermal well permits for production and injection wells issued by the Idaho Department of Water Resources.
2. 	
A Conditional Use Permit for the first two power plants was issued by the Cassia County Planning and Zoning Commission on April 21, 2005.
3. 	
The Idaho Department of Environmental Quality issued the Air Quality Permit to Construct on May 26, 2006.
4. 	
A Wastewater Reuse Permit issued by the Idaho Department of Environmental Quality on February 23, 2007.
San Emidio. The San Emidio project has five significant permits in place necessary for continued operations:
1.
Geothermal well permits for production and injection wells issued by the Nevada Division of Minerals.
2.
A Special Use Permit issued by the Washoe County Board of Commissioners on July 1, 1987.
3.
An Air Quality Permit to Operate from Washoe County renewed on January 1, 2008.
4.
A Surface Discharge Permit from Nevada Division of Environmental Protection issued on June 11, 2001.
5.
An Underground Injection Permit from Nevada Division of Environmental Protection issued on August 18, 2000.
Neal Hot Springs. The Neal Hot Springs project has received all necessary permits for construction and operation of a 22 MW power plant.
Seasonality of Business
The Company and its major subsidiary (RREI) have been producing energy revenues under the terms of two PPAs. These contracts specify favorable rate periods and levels of production. The San Emidio Nevada plant’s contractual terms provide for premium rates in the months from September to April. The RREI contract pays favorable rates in the months of July/August and November/December. Energy production can be influenced by the seasonal temperatures. Generally, the Company’s binary geothermal plants can operate more efficiently in cooler temperatures. Cooler temperatures facilitate the cooling process of the secondary fluid that is used to power the turbines. Drilling and other construction activities could be negatively impacted by inclement weather that can occur, primarily, during the winter months.
Industry Practices/Needs for Working Capital
The Company is heavily involved in development operations; therefore high levels of working capital are committed, either directly or indirectly to the construction efforts. After a plant becomes commercially operational, the needs of working capital are expected to be low. The Company is expecting to be significantly involved in development activities for the next 5 to 10 years.
Dependence on Few a Customers
Ultimately, the market for electrical power is vast; however, the numbers of entities that can physically, logistically and economically purchase the commodity in large quantities in our area of operations are limited. The Company’s primary revenues originate from energy sales and the sale of energy credits. Currently, the Company generates energy revenues from two sources and energy credits from two separate sources. Energy sales are collected from the Idaho Power Company (through the Company’s major subsidiary Raft River Energy Unit I) and Sierra Pacific Power Company. The Company expects to sell power to Idaho Power Company for energy produced at the Neal Hot Springs, Oregon plant. Energy credits are currently being sold to Holy Cross Energy and Barrick Goldstrike Mines Inc. Even at planned levels of operation, it is expected that the Company and its interests will have a small number of direct customers that may amount to less than 8 or 9 within the next 5 to 10 years.
Competitive Conditions
Although the market for different forms of energy is large and dominated by very powerful players, we perceive our industrial competition to be independent power producers and in particular those producers who provide “green” renewable power. Our definition of green power is electricity derived from a source that does not pollute the air, water or earth. Sources of green power, in addition to geothermal, include wind, solar, biomass and run-of-the river hydroelectric. A number of states have instituted renewable portfolio standards (“RPS”) that require utilities to purchase a minimum percentage of their power from renewable sources. For example, RPS statutes in California and Nevada require 20% renewable. On November 17, 2008, the Governor of California signed executive order which mandated a RPS of 33% by 2020 which sits in addition to the 20% order. According to the Department of Energy’s Energy Efficiency and Renewable Energy department, utilities in 34 states nationwide are providing their customers with the opportunity to purchase green, renewable power through premium pricing programs. As a result, we believe green power is an important sub-market in the broader electric market, in which many power purchasers are increasing or committing to increase their investments. Accordingly, the conventional energy producers do not provide direct competition.
In the Pacific Northwest there is currently only one geothermal facility (Raft River Energy Unit I). There are a number of wind farms, as well as biomass and run-of-the river hydroelectric facilities. However, the Company believes that the combination of greater reliability and baseload generation from geothermal, access to infrastructure for deliverability, and a low "full life" cost will allow it to successfully compete for long term power purchase agreements.
Factors that can influence the overall market for our product include some of the following:
number of market participants buying and selling electricity;
availability and cost of transmission;
amount of electricity normally available in the market;
fluctuations in electricity supply due to planned and unplanned outages of competitors’ generators;
fluctuations in electricity demand due to weather and other factors;
cost of fuel used by generators, which could be impacted by efficiency of generation technology and fluctuations in fuel supply;
environmental regulations that impact us and our competitors;
availability of production tax credits and other benefits allowed by tax law;
relative ease or difficulty of developing and constructing new facilities; and
credit worthiness and risk associated with buyers.
Environmental Compliance
The Raft River project is in compliance with all environmental permits and water quality monitoring requirements. The most significant investment in environmental compliance in terms of time and cost was associated with water quality monitoring which had been required on a weekly basis. The Company’s second petition to the Idaho Department of Water Resources (IDWR) to reduce the monitoring obligations was accepted. IDWR has concurred that there is no impact from the Company’s operations on adjacent aquifers.
Since operations have been initiated, key environmental reports include:
1) 	
Monthly production and injection reports which are filed with the IDWR;
2) 	
Quarterly ground water monitoring reports which are filed with IDWR;
3) 	
Annual land application and blowdown water quality reports filed with the Idaho Department of Environmental Quality.
4) 	
Annual Tier II reporting filed with the Idaho Bureau of Homeland Security, Local Emergency Planning Committee, and the local fire department.
The Raft River project is ideally suited in a rural agricultural area. The nearest full time resident is located over one mile south of the plant. The nearest part time resident is located approximately one half mile north of the plant. Additionally, there are no unique plant or animal communities in the area and no unique cultural or environmental constraints.
Financial Information about Geographic Areas
As described in detail in the Property section, the Company’s interest in the Raft River Unit I power plant, located in the southeastern part of the State of Idaho, became operational on January 3, 2008. Similar plants are in the planning stages at the same location as well as locations in Nevada and Oregon. The Company acquired a 3.6 MW geothermal plant and geothermal rights in San Emidio, Nevada. Land acquisitions and rights have been obtained to explore the development and construction of power plants in the southeastern part of the State of Oregon. Substantial drilling and testing activities have occurred during the last fiscal year. In April of 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. Significant project strategies have just begun.
The Company’s revenues for the three most recent fiscal years ended March 31, 2011, 2010 and 2009 were $3,253,545, $2,579,152, and $2,336,202; respectively. All of these revenues were attributable to customers in the Northwest of the United States.
Available Information
We make available, free of charge through our Internet website at http://www.usgeothermal.com, our annual report 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 Securities Exchange Act of 1934, as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Information on our website is not incorporated into this report and is not a part of this report.
Governmental Approvals and Regulation
U.S. Geothermal Inc. is subject to federal and state regulation in respect of the production, sale and distribution of electricity. Federal legislation includes the Energy Policy Act of 2005, the Federal Power Act, and the Energy Policy Act of 1992. HTM is defined as an independent power producer under the rules and regulations of the Federal Energy Regulatory Commission (“FERC”). As an independent power producer, HTM’s operations are supported by the Public Utility Regulatory Policies Act (“PURPA”) which encourages alternative energy sources such as geothermal, wind, biomass, solar and cogeneration. The State of Idaho also regulates electricity through the Idaho Public Utility Commission (“IPUC”). Regulated utilities have the exclusive right to distribute and sell electricity within their service area. They may purchase electricity in the wholesale market from independent producers like HTM. The IPUC, has the authority to establish rules and regulations governing the sale of electricity generated from alternative energy sources. Regulated utilities are required to purchase electricity on an avoided cost basis from renewable energy facilities, or they may acquire purchased power through bids or negotiated procedures.
On May 8, 2006, HTM submitted proposals to Idaho Power in response to their “Request for Proposal for Geothermal Power.” HTM was the preferred respondent and entered into power purchase contract negotiations with Idaho Power. The Raft River Unit I Geothermal Power Plant started up under a contract based on avoided costs which limited the output of the plant to 10 average MWs per month. Through subsequent contract negotiations, HTM reduced the long-term price of power to Idaho Power, and is now allowed to deliver as much power in any month as the plant is capable of producing, up to a maximum hourly output of approximately 16 MWs. The annual average output capacity is on the order of 13 MWs.
Because carbon regulation is anticipated to increase the cost of power sourced from coal and because there are limited opportunities to purchase baseload geothermal power, HTM has found that utilities across the Western United States are eager to discuss PPAs with HTM.
On February 28, 2008, U.S. Geothermal Inc. and Eugene Water and Electric Board (“EWEB”), from Eugene, Oregon signed a power purchase agreement (“PPA”) for the planned Unit II power plant at Raft River. The PPA allows for variable electrical output up to a maximum of 16 MW with a term of 25 years. The PPA is subject to successful drilling and resource development at Raft River. The power will be delivered to the Bonneville Power Agency (“BPA”) customer load in Idaho.
The combined sales from the Idaho Power Raft River Unit I contract and the EWEB Unit II contract is anticipated to be 26 MW from two plants. Before the burgeoning interest in geothermal power, the Company had originally planned 30 MWs from three plants. The construction of only two larger plants will result in substantial capital and operating cost savings through improved economy of scale.
In addition to the EWEB agreement, the strong regional interest in geothermal power has resulted in numerous utilities inquiring with HTM to purchase the electrical power output of Unit III at Raft River, for the output of the Neal Hot Springs power plants, and for any expanded output at the company’s San Emidio, NV project. We anticipate that future plants will be developed under PPAs that do not restrict the output of the project.
The most recent such contract was a 25 MW (maximum) contract signed with Idaho Power on December 11, 2009 for the full output of the Neal Hot Springs development in Oregon. The contract has received approval from the Idaho PUC. The levelized cost of power for the project is $117.55/MWh for 25 years after the plant startup.
HTM will be required to obtain various federal, state and county approvals for construction of future geothermal facilities. These approvals are issued by entities such as the U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency, State (NV, OR, ID) Departments of Environmental Quality, Water Resources, State Historic Preservation Offices, the applicable land management agency, and County Commissioners.
For project development in Idaho and Oregon, David Evans & Associates of Boise, Idaho has provided consulting and engineering services for transmission and interconnection issues. Centra Consulting, Inc. of Boise, Idaho has been retained to assist with State of Idaho air quality and cooling water reuse permitting, and we have retained various environmental engineering firms and regulatory consultants to advise and assist HTM with regard to siting, design and regulatory compliance.
For project development in Nevada, U.S. Geothermal is retaining similar consulting firms to supplement in-house staff.
On June 1, 2011, the Company announced the signing of a 25 year power purchase agreement between its wholly owned subsidiary (USG Nevada LLC) and NV Energy for the purchase of an annual average of up to 19.9 net megawatts of energy produced from the San Emidio Geothermal Project located in Washoe County, Nevada. This agreement is still subject to approval by the PUC.
Environmental Credits
In the past several years, there has been increased demand for energy generated from geothermal resources in the United States as production costs for electricity generated from geothermal resources have become competitive relative to fossil fuel generation. This is partly due to newly enacted legislative and regulatory incentives, such as production tax credits and state renewable portfolio standards. State renewable portfolio standards laws require that an increasing percentage of the electricity supplied by electric utility companies operating in states with such standards will be derived from renewable energy resources until certain pre-established goals are met. We expect increasing demand for energy generated from geothermal and other renewable resources in the United States as additional states adopt or extend renewable portfolio standards.
As a “green” power producer, environmental-related credits, such as renewable energy credits or carbon credits, are also available for sale to power companies (to allow them to meet their “green” power requirements) or to businesses which produce carbon based pollution. In all of U.S. Geothermal Inc.’s project, these credits have been sold separately, or bundled with the electricity to provide an additional source of revenue.
We expect the following key incentives to influence our results of operation:
Production Tax Credits and Investment Tax Credits. Production tax credits provide project owners with a federal tax credit for the first ten years of plant operation. The PTC enhances the annual revenues of the projects by about 25 percent per year for the first 10 years. At present, unless extended, facilities constructed after December 31, 2014 will not be eligible to use this production tax credit. The federal production tax credit available for geothermal energy in 2009 was 2.1 cents per kilowatt-hour. For projects under construction before the end of 2010 and online before the end of 2013, a project can elect to take a 30% investment tax credit in lieu of the PTC. The ITC may be converted into a cash grant within the first 60 days of operation of the plant.
Renewable Energy Credits. Renewable Energy Certificates, or RECs, are tradable environmental commodities that represent proof that 1 MW-hour of electricity was generated from an eligible renewable energy resource. A renewable energy provider is credited with one REC for every 1,000 kilowatt-hours or 1 MW-hour of electricity it produces. The electrical energy is fed into the electrical grid and the accompanying REC can either be delivered to the purchaser of the power (“bundled”) or can be sold on the open market providing the renewable energy producer with an additional source of income.
On July 29, 2006, U.S. Geothermal, Inc. signed a $4.6 million renewable energy credits purchase and sales agreement with Holy Cross Energy, a Colorado cooperative electric association. The agreement is capped at 87,600 RECs (10 MWs average over the year). Holy Cross Energy began purchasing the renewable energy credits associated with the Raft River Unit I power production on October 2007, and is expected to continue purchasing through 2017. Under the revised RRU1 agreement, Idaho Power keeps all RECs above 87,600 RECs per year. In addition, we retain 49% of the renewable energy credits associated with power production from Raft River Unit I after 2017 and Idaho Power retains the other 51%. We expect to receive a majority of the annual revenue from the ten-year renewable energy credits sales arrangement with Holy Cross Energy.
The power purchase agreements for the existing San Emidio power plant, the planned Raft River Unit II facility, and the planned Neal Hot Springs facility are all for bundled power and RECs. Therefore, under these contracts all RECs are delivered with the net power delivered to the utility.
ITEM 1A.
ITEM 1A. Risk Factors
General Business Risks
Our future performance depends on our ability to establish that the geothermal resource is economically sustainable. Geothermal resource exploration and development involves a high degree of risk. The recovery of the amounts shown for geothermal properties and related deferred costs on our financial statements, as well as the execution of our business plan generally, is dependent upon the existence of economically recoverable and sustainable reserves. Expansion of the production of power from our interests is not certain and depends on successful drilling and discovery of additional geothermal hydrothermal resources in quantities and containing sufficient heat necessary to economically fuel future plants.
We have a need for substantial additional financing and will have to significantly delay, curtail or cease operations if we are unable to secure such financing. The Company requires substantial additional financing to fund the cost of continued development of the Raft River (Idaho), San Emidio, Gerlach, Guatemala and Granite Creek Ranch (Nevada) projects. Also, the Company requires funds for other operating activities, and to finance the growth of our business, including the construction and commissioning of power generation facilities. We may not be able to obtain the needed funds on terms acceptable to us or at all. Further, if additional funds are raised by issuing equity securities, significant dilution to our current shareholders may occur and new investors may get rights that are preferential to current shareholders. Alternatively, we may have to bring in joint venture partners to fund further development work, which would result in reducing our interests in the projects.
We may be unable to obtain the financing we need to pursue our growth strategy in the geothermal power production segment, which may adversely affect our ability to expand our operations. When we identify a geothermal property that we may seek to acquire or to develop, a substantial capital investment will be required. Our continued access to capital, through project financing or through a partnership or other arrangements with acceptable terms is necessary for the success of our growth strategy. Our attempts to secure the necessary capital may not be successful on favorable terms, or at all.
Market conditions and other factors may not permit future project and acquisition financings on terms favorable to us. Our ability to arrange for financing on favorable terms, and the costs of such financing, are dependent on numerous factors, including general economic and capital market conditions, investor confidence, the continued success of current 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 laws which are conducive to raising capital. If we are unable to secure capital through partnership or other arrangements, we may have to finance the projects using equity financing which will have a dilutive effect on our common stock. Also, in the absence of favorable financing or other capital options, we may decide not to build new plants or acquire facilities from third parties. Any of these alternatives could have a material adverse effect on our growth prospects and financial condition.
It is very costly to place geothermal resources into commercial production. Before the sale of any power can occur, it will be necessary to construct a gathering and disposal system, a power plant, and a transmission line, and considerable administrative costs would be incurred, together with the drilling of additional wells. For Raft River Energy Unit I, capital contributions of approximately $52 million were needed. Future expansion of power production at Raft River, Idaho and San Emidio, Nevada and development of new power production capability at Neal Hot Springs may result in significantly increased capital costs related to increased production and injection well drilling and higher costs for labor and materials. To fund expenditures of this magnitude, we may have to find a joint venture participant with substantial financial resources. There can be no assurance that a participant can be found and, if found, it would result in us having to substantially reduce our interest in the project.
We may be unable to realize our strategy of utilizing the tax and other incentives available for developing geothermal power projects to attract strategic alliance partners, which may adversely affect our ability to complete these projects. 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.
Our participation in the joint venture is subject to risks relating to working with a co-venturer. Raft River Energy I LLC is the Unit I project joint venture company with Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group Inc. Raft River I Holdings, LLC has contributed a total of $34.2 million in cash and we have contributed over $16.4 million in cash and approximately $1.5 million in production and injection wells and geothermal leases to Raft River Energy I LLC. We are subject to risks in working with a co-venturer that could adversely impact Unit I of the Raft River project as well as anticipated development of Raft River Unit II. It’s possible that the Raft River Unit II power plant may utilize the geothermal resource within the Raft River Unit I joint venture boundaries. Further, our contribution to the joint venture may exceed returns from the joint venture, if any.
We are a holding company and our revenues depend substantially on the performance of our subsidiaries and the projects they operate. We are a holding company whose primary assets are our ownership of the equity interests in our subsidiaries. We conduct no other business and, as a result, we depend entirely upon our subsidiaries’ earnings and cash flow. Our subsidiaries and projects may be restricted in their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the satisfaction of other obligations, including the payment of operating expenses or debt service.
We may not be able to manage our growth due to the continuation of operations of the Raft River and San Emidio power plants and construction activities in Neal Hot Springs and San Emidio which could negatively impact our operations and financial condition. Significant growth in our operations will place demands on our operational, administrative and financial resources, and the increased scope of our operations will present challenges to us due to increased management time and resources required and our existing limited staff. Our future performance and profitability will depend in part on our ability to successfully integrate the operational, financial and administrative functions of Raft River and San Emidio and other acquired properties into our operations, to hire additional personnel and to implement necessary enhancements to our management systems to respond to changes in our business. There can be no assurance that we will be successful in these efforts. Our inability to manage the increased scope of operations, to integrate acquired properties, to hire additional personnel or to enhance our management systems could have a material adverse effect on our results of operations.
If we incur material debt to fund our business, we could face significant risks associated with such debt levels. We will need to procure significant additional financing to construct, commission and operate our power plants in order to generate and sell electricity. If this financing includes the issuance of material amounts of debt, this would expose the Company to risks including, among others, the following:
a portion of our cash flow from operations would be used for the payment of principal and interest on such indebtedness and would not be available for financing capital expenditures or other purposes;
a significant level of indebtedness and the covenants governing such indebtedness could limit our flexibility in planning for, or reacting to, changes in our business because certain activities or financing options may be limited or prohibited under the terms of agreements relating to such indebtedness;
a significant level of indebtedness may make us more vulnerable to defaults by the purchasers of electricity or in the event of a downturn in our business because of fixed debt service obligations; and
the terms of agreements may require us to make interest and principal payments and to remain in compliance with stated financial covenants and ratios. If the requirements of such agreements were not satisfied, the lenders could be entitled to accelerate the payment of all outstanding indebtedness and foreclose on the collateral securing payment of that indebtedness, which would likely include our interest in the project.
In such event, we cannot assure you that we would have sufficient funds available or could obtain the financing required to meet our obligations, including the repayment of outstanding principal and interest on such indebtedness.
We may not be able to successfully integrate companies that we may acquire in the future, which could materially and adversely affect our business, financial condition, future results and cash flow. Our strategy is to continue to expand in the future, including through acquisitions. Integrating acquisitions is often costly, and we may not be able to successfully integrate our acquired companies with our existing operations without substantial costs, delays or other adverse operational or financial consequences. Integrating our acquired companies involves a number of risks that could materially and adversely affect our business, including:
failure of the acquired companies to achieve the results we expect;
inability to retain key personnel of the acquired companies;
risks associated with unanticipated events or liabilities; and
the difficulty of establishing and maintaining uniform standards, controls, procedures and policies, including accounting controls and procedures.
If any of our acquired companies suffers performance problems, the same could adversely affect the reputation of our group of companies and could materially and adversely affect our business, financial condition, future results and cash flow.
The success of our business relies on retaining our key personnel. We are dependent upon the services of our President and Chief Executive Officer, Daniel J. Kunz, our Chief Financial Officer, Kerry D. Hawkley, our Vice President of Finance, Jonathan Zurkoff, our Chief Operating Officer, Douglas J. Glaspey, and Kevin R. Kitz, our Vice President - Project Development. The loss of any of their services could have a material adverse effect upon us. As of the date of this report, the Company has executed employment agreements with these persons, but does not have key-man insurance on any of them.
Our development activities are inherently very risky. The high risks involved in the development of a geothermal resource cannot be over-stated. The development of geothermal resources at our Raft River, Idaho; San Emidio, Nevada and Neal Hot Springs, Oregon projects are such that there cannot be any assurance of success. Exploration costs are high and are not fixed. The geothermal resource cannot be relied upon until substantial development, including drilling, has taken place. The costs of development drilling are subject to numerous variables such as unforeseen geologic conditions underground which could result in substantial cost overruns. Drilling for geothermal resource at Raft River is relatively deep with the average depth of wells some 6,000 feet. Drilling at Neal Hot Springs, Raft River and San Emidio may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, compliance with governmental requirements and shortages or delays of equipment and services. If our drilling activities are not successful, we could experience a material adverse effect on our future results of operations and financial condition.
In addition to the substantial risk that wells drilled will not be productive, or may decline in productivity after commencement of production, hazards such as unusual or unexpected geologic formations, pressures, downhole conditions, mechanical failures, blowouts, cratering, explosions, uncontrollable flows of well fluids, pollution and other physical and environmental risks are inherent in geothermal exploration and production. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations.
The impact of governmental regulation could adversely affect our business by increasing costs for financing or development of power plants. Our business is subject to certain federal, state and local laws and regulations, including laws and regulations on taxation, the exploration for and development, production and distribution of electricity, and environmental and safety matters. On a Federal level, the most important tax rule that affects our business is the PTC, which was extended to December 31, 2014. Recent legislation enacted as part of the stimulus funding has also provided an election to take 30% ITC in lieu of the PTC and convertible into a cash grant for certain qualified investments being initiated before the end of 2010 and being placed in service before the end of 2013. The loss of the PTC or ITC is a risk that could result in making future expansions at Raft River, San Emidio and at Neal Hot Springs uneconomic. New rules recently adopted by the Bureau of Land Management, as directed by the Energy Policy Act of 2005, require competitive auction of all geothermal leases on Federal lands. Competitive leasing is significantly increasing the cost of obtaining leases on Federal land, is adding to the capital costs needed to develop geothermal projects, is increasing the total electrical power prices needed to make a geothermal project viable and is making it more difficult to acquire additional adjacent lands for reservoir protection and exploration.
If Federal lands or any Federal involvement are included in any geothermal development, requirements of the National Environmental Policy Act ("NEPA") will be triggered. Most of the geothermal resources in the United States are located in the western states, where the Federal Government often is the largest landowner. If a NEPA action is triggered, such as an Environmental Impact Statement or Environmental Assessment, a project delay of one to two years and a cost of $1,000,000 to $2,000,000 or more may be incurred while the environmental permitting process is completed. NEPA not only can impact the property where the geothermal resource is located, but includes the siting and construction of transmission lines. Environmental legislation is evolving in a manner that means stricter standards, and enforcement, fines and penalties for non-compliance are more stringent. Environmental assessments of proposed projects carry a heightened degree of responsibility for companies and directors, officers and employees. The cost of compliance with changes in governmental regulations has a potential to reduce the profitability of operations.
In the states of Idaho, Nevada and Oregon, drilling for geothermal resources is governed by specific rules. In Nevada drilling operations are governed by the Division of Minerals (Nevada Administrative Code Chapter 534A); in Idaho by the Idaho Department of Water Resources (IDAPA 37 Title 03 Chapter 04); and in Oregon by the Division of Oil, Gas and Mineral Industries (Division 20 Geothermal Regulation). These rules require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters, and, may not allow or may restrict drilling activity, or may require that a geothermal resource be unitized (shared) with adjoining land owners. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our geothermal wells, the power plant and other facilities. State environmental requirements and permits, such as the Idaho Department of Environmental Quality, Air Quality Permit to Construct, include public disclosure and comment. It is possible that a legal protest could be triggered through one of the permitting processes that would delay construction and increase cost for one of our projects. The state of Oregon has an Energy Facility Siting Council that must issue a site certificate for any geothermal energy facilities of 35 MWs or higher which could affect the Neal Hot Spring project by adding additional cost and delay construction.
Because of these state and federal regulations, we could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil or water, including responsibility for remediation costs. We could potentially discharge such materials into the environment:
from a well or drilling equipment at a drill site;
leakage of fluids or airborne pollutants from gathering systems, pipelines, power plant and storage tanks;
damage to geothermal wells resulting from accidents during normal operations; and
blowouts, cratering and explosions.
Because the requirements imposed by such laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business by increasing cost and the time required to explore and develop geothermal projects. In addition, because the Vulcan Property at Raft River was previously operated by others, we may be liable for environmental damage caused by such former operators.
Industry competition may impede our growth and ability to enter into power purchase agreements on terms favorable to us, or at all, which would negatively impact our revenue. The electrical power generation industry, of which geothermal power is a sub-component, is highly competitive and we may not be able to compete successfully or grow our business. We compete in areas of pricing, grid access and markets. The industry in the Western United States, in which the Raft River and San Emidio projects are located, is complex as it is composed of public utility districts, cooperatives and investor-owned power companies. Many of the participants produce and distribute electricity. Their willingness to purchase electricity from an independent producer may be based on a number of factors and not solely on pricing and surety of supply. If we cannot enter into power purchase agreements on terms favorable to us, or at all, it would negatively impact our revenue and our decisions regarding development of additional properties.
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 steam 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 of the Raft River, Idaho, San Emidio, Nevada and Neal Hot Springs, Oregon binary cycle power plant projects 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.
Actual costs of construction or operation of a power plant may exceed estimates used in negotiation of power purchase and power financing agreements. The Company’s initial power purchase contract is under rates established by the Idaho Public Utility Commission, using an “avoided-cost” model for cost of construction and operating costs of power plants. If the actual costs of construction or operations exceed the model costs, the Company may not be able to build the contemplated power plants, or if constructed, may not be able to operate profitably. The Company’s financing agreements provide for a priority payback to our partner. If the actual costs of construction or operations exceed the model costs, we may not be able to operate profitably or receive the planned share of cash flow and proceeds from the project. The actual costs of operating the Raft River power project are higher than the original estimate due to several factors including the need to filter the ground water for cooling to remove harmful and unanticipated chloride levels in the water, the need to purchase production pump power from a third party to provide maximum plant output, and increased general costs related to labor and management.
Payments under our Raft River Unit I power purchase agreement may be reduced if we are unable to forecast our production adequately. Under the terms of our power purchase agreement for Raft River Unit I, and starting with the third year of operation (2011), if we do not deliver electricity output within 90% to 110% of our forecasted amount, which requires us to submit a forecast every three months, payments for the amount delivered will be reduced, possibly significantly. For example if the plant produces more than 110% of the power as forecasted then we would not receive any revenue for the amount over the forecast figure. If the plant produces less than 90% of the forecast amount for unexcused reasons, such as normal plant breakdowns and maintenance, then we may be subject to a reduced power price, depending on the prevailing power market conditions. The agreement moves the power price to the market price instead of contracted price. We currently expect to forecast 9 MWs of delivery on a 10-MW plant and the damages would then result if the actual delivery was only 8.1 MWs or less. All 8.1 MWs would be subject to a reduced price that is not possible to predict at this time. The total average revenue per MW hour is approximately $62.40 and the reduction in revenue could be perhaps 30 percent of that amount. As a risk mitigation element, we are not subject to this adjustment until year three of the contract and then we are able to submit a new forecast every three months thereby limiting this exposure.
There are some risks for which we do not or cannot carry insurance. Because our current operations are limited in scope, the Company carries property, public liability insurance and directors’ and officers’ liability coverage, but does not currently insure against any other risks. As its operations progress, the Company will acquire additional coverage consistent with its operational needs, but the Company may become subject to liability for pollution or other hazards against which it cannot insure or cannot insure at sufficient levels or against which it may elect not to insure because of high premium costs or other reasons. In particular, coverage is not available for environmental liability or earthquake damage.
Our officers and directors may have conflicts of interests arising out of their relationships with other companies. Several of our directors and officers serve (or may agree to serve) as directors or officers of other companies or have significant shareholdings in other companies. To the extent that such other companies may participate in ventures in which the Company may participate, the directors may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. From time to time several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment.
Failure to comply with regulatory requirements may adversely affect our stock price and business. As a public company, we are subject to numerous governmental and stock exchange requirements, with which we believe we are in compliance. The Sarbanes-Oxley Act of 2002 and the Securities and Exchange Commission (SEC) have requirements that we may fail to meet by the required deadlines or we may fall out of compliance with, such as the internal controls assessment, reporting and auditor attestation required under Section 404 of the Sarbanes-Oxley Act of 2002. The Company has documented and tested its internal control procedures in order to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”). SOX requires an annual assessment by management of the effectiveness of the Company’s internal control over financial reporting and an attestation report by the Company’s independent auditors on internal controls over financial reporting. We may incur additional costs in order to comply with Section 404. In addition, if we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act of 2002. Moreover, effective internal controls are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could drop significantly. Our failure to meet regulatory requirements and exchange listing standards may result in actions such as the delisting of our stock impacting our stock’s liquidity; SEC enforcement actions; and securities claims and litigation.
Risks Relating To the Market for Our Securities
A significant number of shares of our common stock are eligible for public resale. If a significant number of shares are resold on the public market, the share price could be reduced and could adversely affect our ability to raise needed capital. The market price for our common stock could decrease significantly and our ability to raise capital through the issuance of additional equity could be adversely affected by the availability and resale of such a large number of shares in a short period of time. If we cannot raise additional capital on terms favorable to us, or at all, it may delay our exploration or development of existing properties or limit our ability to acquire new properties, which would be detrimental to our business.
Because the public market for shares of our common stock is limited, investors may be unable to resell their shares of common stock. There is currently only a limited public market for our common stock on the Toronto Stock Exchange in Canada and on the NYSE Amex in the United States, and investors may be unable to resell their shares of common stock. The development of an active public trading market depends upon the existence of willing buyers and sellers that are able to sell their shares and market makers that are willing to make a market in the shares. Under these circumstances, the market bid and ask prices for the shares may be significantly influenced by the decisions of the market makers to buy or sell the shares for their own account, which may be critical for the establishment and maintenance of a liquid public market in our common stock. We cannot give you any assurance that an active public trading market for the shares will develop or be sustained.
The price of our common stock is volatile, which may cause investment losses for our shareholders. The market for our common stock is highly volatile, having ranged in the last fiscal year ended March 31, 2011, from a low of $0.74 CDN to a high of $1.38 CDN on the TSX Exchanges and from a low of $0.70 to a high of $1.36 on the NYSE Amex. The trading price of our common stock on the TSX Exchange and on the NYSE Amex is subject to wide fluctuations in response to, among other things, quarterly variations in operating and financial results, and general economic and market conditions. In addition, statements or changes in opinions, ratings, or earnings estimates made by brokerage firms or industry analysts relating to our market or relating to our company could result in an immediate and adverse effect on the market price of our common stock. The highly volatile nature of our stock price may cause investment losses for our shareholders.
We do not intend to pay any cash dividends in the foreseeable future. We intend to reinvest any earnings in the development of our projects. Payments of future dividends, if any, will be at the discretion of our board of directors after taking into account various factors, including our business, operating results and financial condition, current and anticipated cash needs, plans for expansion and any legal or contractual limitations on our ability to pay dividends.
Provisions in our bylaws and under Delaware law could discourage a takeover that stockholders may consider favorable. Our bylaws contain provisions that could depress the trading price of our common stock by acting to discourage, delay or prevent a change of control of our company or changes in our management that the stockholders of our company may deem advantageous. These provisions prohibit stockholders from calling special meetings, which may deter a takeover attempt. Additionally, we are subject to Section 203 of the Delaware General Corporation Law, which generally prohibits a Delaware corporation from engaging in any of a broad range of business combinations with any holder of 15% or more of our capital stock for a period of three years following the date on which the stockholder acquired such ownership percentage, unless, among other things, our Board of Directors has approved the transaction. This statute likewise may discourage, delay or prevent a change of control.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Description of Property
The Company has interests in three areas in the Western United States. These interests include the Raft River area located in southeastern Idaho, the Neal Hot Springs area located in eastern Oregon (near the Idaho/Oregon boarder), and our interests located in northwestern Nevada. The properties in northwestern Nevada include San Emidio, Gerlach and Granite Creek. The Company currently has two commercially operational power plants. Unit I at Raft River became commercially operational on January 3, 2008. The San Emidio plant was acquired in the Empire Acquisition in May 2008.
REGIONAL LOCATION MAP
Raft River, Idaho
The Raft River project, where the Company’s geothermal operations are located, is in southeastern Idaho, approximately 55 miles southeast of Burley, the county seat of Cassia County. Burley, population 8,300, is the local agricultural and manufacturing center for the area, providing a full range of light to heavy industrial services.
A commercial airport is located 90 miles to the northeast in Pocatello, Idaho. Pocatello, population 53,000, is a regional center for agriculture, heavy industry (mining, phosphate refining), technology and education with Idaho State University. Malta, a town with a population of approximately 180, is 12 miles north of the project site where basic services, fuel, and groceries are available. Year-round access to the project from Burley is via Interstate Highway 84 south to State Highway 81 south, then east on the Narrows Canyon Road, an improved county road.
The Raft River project currently consists of ten parcels (generally referred to as the U.S. Geothermal Property, the Crank Lease, the Newbold Lease, the Jensen Investments Leases, the Stewart Lease, the Bighorn Mortgage Lease, the Doman Lease, the Griffin Lease, and the Glover Lease) comprising 783.93 acres of fee land and 4,736.79 acres of contiguous leased geothermal rights located on private property in Cassia County, Idaho. All parcels are defined by legal subdivision or by metes and bounds survey description. The ten parcels are as follows:
The U.S. Geothermal Property - Idaho. The U.S. Geothermal Property is comprised of four separate properties that total 1,723.93 acres: the Vulcan, Elena Corporation, Dewsnup and the Wilcox Ranch Properties. The Vulcan Property includes both surface and geothermal rights and consists of two parcels. The first parcel has a total area of approximately 240 acres and three geothermal wells (RRGE-1, RRGP-4 and RRGP-5) are located on this parcel. The second parcel has a total area of approximately 320 acres, and three additional geothermal wells (RRGE-3, RRGI-6 and RRGI-7) are located on this parcel. A fourth well, RRGE-2, although located on the property covered by the Crank lease, was acquired by the Company from a local rancher. The Wilcox Ranch includes 940 acres of agricultural and range lands adjacent to Raft River that provides cooling water.
The Elena Property is comprised of surface and geothermal rights to approximately 100 acres of property, excluding the oil and gas rights to the property. The property is contiguous to other properties owned or leased by the Company.
The Dewsnup Property is comprised of the surface and geothermal rights to approximately 123.93 acres of property, excluding the oil and gas rights to the property, but including all surface water rights. The property is contiguous to other properties owned or leased by the Company.
The Crank Lease. The Crank lease covers approximately 160 acres of mineral and geothermal rights, with right of ingress and egress.
The Newbold Lease. The Newbold lease covers approximately 20 acres of both surface and geothermal rights.
The Jensen Investments Leases. The first Jensen Investments lease covers approximately 2,954.75 acres of geothermal rights only. It is contiguous with the Vulcan Property and property covered by the Crank and Stewart leases. The second Jensen Investments lease covers approximately 44.5 acres of surface and geothermal rights, and is contiguous with property covered by the first Jensen lease.
The Stewart Lease. The Stewart Lease covers approximately 317.54 acres on two adjoining parcels. Parcel 1 contains approximately 159.04 acres and includes surface and geothermal rights. Parcel 2 contains approximately 158.50 acres and only covers surface rights. The underlying geothermal rights for Parcel 2 are subject to the first Jensen Investments Lease.
The Bighorn Mortgage Lease. The Bighorn Mortgage lease covers approximately 280 acres of surface and geothermal rights.
The Doman Lease. The Doman lease covers approximately 640 acres of surface and geothermal rights, excluding oil and gas rights.
The Griffin Lease. The Griffin lease contains approximately 160 acres of geothermal rights.
The Glover Lease. The Glover lease contains approximately 160 acres of geothermal rights.
BLM Lease. The geothermal resources lease agreement with the United States Department of Interior Bureau of Land Management (BLM) was entered into on August 1, 2007. The lease is for approximately 1,685 acres of land located contiguous to the Raft River Property in southeastern Idaho.
Raft River Energy Unit I
Unit I at Raft River became commercially operational on January 3, 2008. As a result of the project financing for Unit I of the Raft River project, the Company has contributed over $17.9 million in cash and property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River Holdings, an affiliate of Goldman Sachs Group, has contributed approximately $34 million to the project. Property assigned to Raft River Energy by the Company includes seven production and injection wells, seven monitoring wells, the Stewart lease, the Crank lease, the Newbold lease, the Doman lease, and the Glover lease. All appropriate permits and contracts have also been assigned to Raft River Energy for Unit I.
Although significant detail has been provided about each specific lease area, the economics of the project is based on the total resource. The reservoir supporting the project encompasses the entire Known Geothermal Resource Area (“KGRA”), which includes all the property owned or leased by the company at Raft River. All discussions of the economics of the project, including future phases, will be based at the project level rather than at the lease level.
Lease/Royalty Terms
The Crank lease, the Newbold lease, the Jensen Investments leases, the Bighorn Mortgage lease, the Doman lease, the Griffin lease and the Glover lease have royalties payable under the following terms:
(a)
Energy produced, saved and used for the generation of electric power, which is then sold by lessee, has a royalty of ten percent (10%) of the net proceeds to RREI.
(b)
Energy produced, saved and sold by lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value.
(c)
Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.
The Stewart lease has production royalties payable under the following terms:
(a) 	
Energy produced, saved and sold by the Lessee, then used by the purchaser for generation of electric power, has a royalty of ten percent (10%) of the market value of the electric power.
(b) 	
Energy produced, saved and used for the generation of electric power, which is then sold by Lessee, has a royalty of three percent (3%) of the market value of the electric power.
(c) 	
Energy produced, which is used for any purpose other than the generation of electricity has a royalty of five percent (5%) of the gross proceeds.
No production royalties have been paid to date under any of the leases. All of the leases may be extended indefinitely if production is achieved during the primary term, so long as production is maintained. For each lease other than the Crank Lease (see below), once production is achieved the amounts due annually will be the greater of the production royalty and the minimum payment for the last year of the primary term. All payments under the leases are made annually in advance on the anniversary date of the particular lease. In addition, the following lease and other royalty terms apply to the individual leases:
The Crank Lease. The lease agreement with Janice Crank was originally entered into June 28, 2002, and had a primary term of 5 years. After U.S. Geothermal Inc. provided evidence to the lessor that the well (RRGE-2) located on lessor’s property was not owned by the lessor (but instead was included in the Vulcan Property), a new lease was entered into on June 28, 2003, which excluded the ownership of RRGE-2, with a four-year initial term.
Payments for years 2002 through 2006 have been recorded as lease expense. After commercial production was attained, these lease payments have been deducted from future production royalties. For later years, during commercial production, there is a minimum annual production royalty of $18,000. The minimum amount that will be payable over the course of the leases is $45,000. Maximum amounts payable will depend on production from the property.
The Newbold Lease. The company leases this property pursuant to a lease agreement with Jay Newbold dated March 1, 2004. The Newbold lease has a primary term of 10 years (through February 28, 2014) and is extended indefinitely so long as production from the geothermal field is maintained. Minimum lease payments are as follows:
Years 1-5: $10.00 per acre or $200 per year
Years 6-10: $15.00 per acre or $300 per year
The minimum amount that will be payable over the course of the lease is $2,500. Maximum amounts payable will depend on royalties on production from the property.
The Jensen Investments Leases. The first Jensen Investments lease was originally with Sergene Jensen, as lessor, is dated July 11, 2002, and has a primary term of 10 years. In September 2005, the property subject to the lease was conveyed and the lease was assumed by Jensen Investments, Inc. Minimum lease payments (on a July to July basis) are as follows:
Years 1-5: $2.50 per acre or $7,386.88 per year
Years 6-10: $3.00 per acre or $8,864.25 per year
The minimum amount that will be payable over the course of the lease is $81,256. Maximum amounts payable will depend on production from the property. The second Jensen Investments lease, with Jensen Investments, Inc., is dated July 12, 2002, and has a primary term of 10 years. Minimum lease payments (on a July to July basis) are as follows:
Years 1-5: $2.50 per acre or $111.25 per year
Years 6-10: $3.00 per acre or $133.50 per year
The minimum amount that will be payable over the course of the lease is $1,224. Maximum amounts payable will depend on royalties on production from the property.
The Stewart Lease. The Stewart lease, with Reid and Ruth Stewart, is dated December 1, 2004, and has a primary term of 30 years. Minimum lease payments are as follows:
Year 1: $8,000
Year 2: $5,000
Year 3-30: $5,000 plus an annual increase of 5% per year.
The minimum amount that will be payable over the course of the lease is $319,614. Maximum amounts payable will depend upon royalties on production from the property.
The Bighorn Mortgage Lease. The Bighorn Mortgage lease, with Conrad Irrevocable Trust, is dated July 5, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:
Year 1-5: $1,400
Year 6-10: $2,100
The minimum amount that will be payable over the course of the lease is $17,500. Maximum amounts payable will depend upon royalties on production from the property.
The Doman Lease. The Doman lease, with Dale and Ronda Doman, is dated June 23, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:
Year 1-5: $1,600
Year 6-10: $3,200
The minimum amount that will be payable over the course of the lease is $24,000. Maximum amounts payable will depend upon royalties on production from the property.
The Griffin Lease. The Griffin lease, with Michael and Cleo Griffin, Harlow and Pauline Griffin, Douglas and Margaret Griffin, Terry and Sue Griffin, Vincent and Phyllis Jorgensen, and Alice Mae Griffin Shorts, is dated June 23, 2005, and has a primary term of 10 years. Minimum lease payments are as follows:
Year 1: $1,600
Year 2-5: $800
Year 6-10: $1,200
The minimum amount that will be payable over the course of the lease is $10,800. Maximum amounts payable will depend upon royalties on production from the property.
The Glover Lease. The Glover lease, with Philip Glover, is dated January 25, 2006, and has a primary term of 10 years. Minimum lease payments are as follows:
Year 1: $2,100
Year 2-5: $1,600
Year 6-10: $2,400
The minimum amount that will be payable over the course of the lease is $20,500. Maximum amounts payable will depend upon royalties on production from the property.
The total minimum amount payable under all of the leases during their primary terms is $522,393. The above listed lease payments are payable annually in advance, and are current through lease years that began in 2009. The leases can be renewed for extended periods as long as the power plant continues to produce power.
BLM Lease. The lease entered into in August of 2007 has a primary term of 10 years. After the primary term, the Company has the right to extend the contract in accordance with regulation 43 CFR subpart 3207. The lease calls for annual payments of $3,502 including processing fees. BLM has the right to terminate the contract upon written notice if the Company does not comply with the terms of the agreement. The royalty rate is based upon 10% of the value of the resource at the well head. The amounts are calculated according to a formula established by Minerals Management Service (“MMS”).
Neal Hot Springs, Oregon
Neal Hot Springs is a geothermal resource located in Eastern Oregon. The Company acquired the Neal Hot Springs geothermal energy and surface rights in September 2006. A geothermal power plant is currently under development.
On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C). Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.
The Company has been issued permits for drilling up to 15 temperature gradient drill holes and all necessary geothermal wells. Successful geothermal resource delineation has continued with the development of a three additional geothermal production wells (NHS-2,5,&8) located north and south of NHS-1 and temperature gradient well 21 which intersected additional geothermal resource south of NHS-1.
A thirty (30) day flow test was conducted in December 2010 and January 2011 to measure reservoir characteristics and evaluate the productivity of the geothermal resource. The results of the flow test were evaluated by Richard Holt, Geothermex and engineers with the U.S. Department of Energy. As a result, the Company has been issued our reservoir certificates and the project is proceeding with support from the DOE’s loan guarantee.
The project is projected to deliver power in the 3rd quarter of 2012.
Lease/Royalty Terms
Cyprus Gold Exploration Corporation. The lease is for mineral rights for 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, and has a primary term of 10 years, and expires January 24, 2017. Minimum lease payments are as follows:
The agreement defines a royalty rate is based upon 2% of the actual revenue for the first 10 years of commercial production and 3% thereafter.
JR Land and Livestock. The lease is for mineral rights for 4,960 acres located in Malheur County, Oregon is dated January 24, 2007, and has a primary term of 10 years, and expires January 24, 2017. Minimum lease payments are as follows:
The agreement defines a royalty rate is based upon 3% of the gross proceeds for the first 5 years of commercial production, 4% of gross proceeds for the next 10 years, and 5% of the gross proceeds thereafter.
San Emidio, Nevada
Effective May 1, 2008, the Company acquired a 3.6 MW operating geothermal power plant and approximately 30,734.21 acres (48.0 square miles) of geothermal energy leases and certain ground water rights all located north of Reno, Nevada. The total purchase price was $16.6 million. The assets are comprised of two locations: the San Emidio assets and the Gerlach/Granite Creek assets. The San Emidio assets are located in the San Emidio Desert, Washoe County, Nevada and include the geothermal power project, approximately 22,944 acres (35.9 square miles) of geothermal leases, and ground water rights used for cooling water. The Gerlach assets are comprised of approximately 3,415 acres (5.3 square miles) of BLM geothermal leases located about 1 mile north of Gerlach, Nevada. The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located about 7 miles north of Gerlach, Nevada. The Gerlach and Granite Creek assets are along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.
The 3.6 -MW geothermal power plant has been producing power since 1987 and sells electricity to Sierra Pacific Power Corporation under an existing power purchase agreement that extends through 2017. A March 2008 resource assessment of the San Emidio geothermal leases by independent experts Susan Petty of Black Mountain Technology and Geologist, Dennis Trexler, estimated a total resource potential of 44 MWs with a 90% probability factor.
The power plant was constructed in 1986 with commercial power generation beginning in 1987. Deeper wells with higher temperatures were drilled in 1994 to supply the plant after output declined due to cooling of the original, shallow production wells. The current configuration of the plant consists of four 1.2 MW Ormat Energy Converters, three injection wells and two production wells. A three cell cooling tower was added in 1998 to improve summer power generation. The plant is connected to the transmission grid via a 60 kilovolt intertie.
San Emidio is our second operating geothermal power plant and is owned by a wholly owned subsidiary of the Company (USG Nevada LLC). The project is a small-scale geothermal power plant selling approximately 2.5 MWs. The plant is approximately 22 years old and employs four binary cycle units. We have conducted a review of the information regarding the project, and we believe that the existing production wells can provide 4,000 to 5,000 gallons per minute of 280 to 300 °F fluid to the current power plant.
The Company’s wholly owned subsidiary, USG Nevada LLC, has entered into agreements with Science Applications International Corporation (“SAIC”), a FORTUNE 500® scientific, engineering, and technology applications company, for a project loan and an engineering, procurement and construction contract for a geothermal power plant for Phase I of the San Emidio project in northwest Nevada. The work will be executed by SAIC’s design-build subsidiary, The Benham Companies, LLC.
The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be expansions. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the first calendar quarter of 2013. The Company expects to be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.
Subsequent to the end of the quarter, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The Company also received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification as to what this means and why our application was treated this way.
Lease/Royalty Terms
BLM Leases. At the closing of the Empire Acquisition, the geothermal leases with the BLM were assigned to the Company. The lease contracts are for approximately 21,905 acres of land and geothermal rights located in the San Emidio Desert, Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 10 years, under two extension periods, at 5 years each, if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases require the lessee to conduct operations in a manner that minimizes adverse impacts to the environment.
The terms of the BLM contracts are detailed as follows:
The BLM lease contracts require royalty payments for the use of geothermal resources. The rate is based upon 10% of the value of the resource at the well head. The amounts are calculated according to a formula established by the Minerals Management Service.
The Company received BLM approval and designation of a Geothermal Unit and a “Participating Area”. The geothermal unit allows USG to hold all geothermal resources within the valley without the risk of lease expiration and allows exploration and development costs to be apportioned between and for the benefit of maintaining all the geothermal leases within the Unit. The first designated participating area encompasses the currently operated southern production zone. Royalties will be portioned to the mineral owners on a percentage of ownership within the participating area. The Unit Area and the Participating Area are key components for long term lease retention and resource development.
Gerlach, Nevada
In May 2008, the Company entered into a joint venture agreement with Gerlach Green Energy LLC of Nevada to form a limited liability company named Gerlach Geothermal LLC. The joint venture owns geothermal rights for 3,615 acres (5.6 square miles) located in northwestern Nevada near the town of Gerlach. The target of the joint venture is the exploration of the regional Gerlach geothermal system. The joint venture is located near the Company’s Granite Creek leases that were recently acquired as part of the San Emidio geothermal power plant acquisition. The Company received BLM approval and designation of a Geothermal Unit. The geothermal unit allows the Company to hold all geothermal resources within the valley without the risk of lease expiration and allows exploration and development costs to be apportioned between and for the benefit of maintaining all the geothermal leases within the Unit. The first designated participating area will be established after the geothermal resource has been delineated and a production strategy is implemented. The Unit Area and the Participating Area are key components for long term lease retention and resource development.
Lease/Royalty Terms
BLM Leases. The Gerlach Geothermal LLC assets are comprised two BLM geothermal leases and one private lease totaling 3,615 acres. Both BLM leases have a royalty rate is based upon 10% of the value of the resource at the wellhead. The amounts are calculated according to a formula established by MMS. One of the two BLM leases has a second royalty commitment to a third party of 4% of gross revenue for power generation and 5% for direct use based on BTUs consumed at a set comparable price of $7.00 per million BTU of natural gas. The private lease has a 10 year primary term and would receive a royalty of 3% gross revenue for the first 10 years and 4% thereafter.
Granite Creek, Nevada
The Granite Creek assets are comprised of approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser.
Lease/Royalty Terms
BLM Leases. The Company has three geothermal lease contracts with the BLM. The lease contracts are for approximately 5,414 acres of land and geothermal water rights located in the northwestern Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $5,414, not including processing fees, and expire October 31, 2012.
Republic of Guatemala
In the prior fiscal year, the Company successfully acquired a geothermal concession in the Republic of Guatemala. The concession consists of 24,710 acres (100 square kilometers) and is located 14 miles southwest of Guatemala City, the capital. Nine wells with depths ranging from 560 to 2,000 feet (170 to 610 meters) were drilled in the El Ceibillo resource area within the concession area during the l990s. Six of the wells have measured reservoir temperatures in the range of 365 to 400°F (185 to 204°C). Fluid sample analysis and the mineralogy associated with drill cuttings suggest the existence of a deeper, higher permeability reservoir with temperature potential of 410 to 446°F (210 to 230°C).
Boise Administration Office, Idaho
The Company entered into a 1 year lease contract effective January 31, 2011 through January 31, 2012, for general office space for an executive office located in Boise, Idaho. The contract allows the Company two annual renewal options. The lease payments are due in monthly installments of $6,160 per month.
Item 3.
Item 3. Legal Proceedings
As of May 31, 2011, management is not aware of any material current or pending legal proceedings in which the Company is a party, as plaintiff or defendant, or which involve any of its properties.
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
NYSE Amex/Over-The-Counter Bulletin Board
From June 3, 2005 to April 15, 2008, the common stock of U.S. Geothermal Inc. was quoted on the Over-The-Counter Bulletin Board (the “Bulletin Board”) under the trading symbol “UGTH”. Effective April 14, 2008, the common stock of U.S. Geothermal Inc. began trading on the American Stock Exchange, now the NYSE Amex Equities, under the trade symbol “HTM.” Future trading prices of our common shares will depend on many factors, including, among others, our operating results and the market for similar securities.
The following sets forth information relating to the trading of our common stock from April 1, 2009.
TSX and TSX Venture Exchange
The Company’s common shares began trading on the Toronto Stock Exchange (“TSX”) on October 1, 2007, under the symbol “GTH.” Prior to trading on the TSX, the Company’s common shares were traded on the TSX Venture Exchange through September 28, 2007 under the same symbol. TSX is the senior equity market in Canada. TSX Venture Exchange is a segment of the Toronto Stock Exchange Group that provides the global financial community with access to Canada's equity capital and energy markets. The following sets forth information relating to the trading on the TSX Exchange:
As of May 31, 2011, we had approximately 20,100 stockholders of record.
The Company has never paid and does not intend to pay dividends on our common stock in the foreseeable future. Although the Company’s articles of incorporation and by-laws do not preclude payment of dividends, we currently intend to retain any future earnings for reinvestment in our business. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and other relevant factors. All of the common shares are entitled to an equal share in any dividend declared and paid.
Item 6.
Item 6. Selected Financial Data
(1)
Long-term obligations represent the stock compensation payable, a convertible loan, construction loan and a capital lease obligation. The stock compensation liability is the fair value of stock options to be exercised by officers, directors, employees and consultants of the Company. These obligations were recorded as a liability since the option exercise price was stated in Canadian dollars, subjecting the Company and the employee to foreign currency exchange risk in addition to the normal market price fluctuation risk.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following is a list of projects that are in operation, under development or under exploration. Projects in operation have producing geothermal power plants. Projects under development have at least a geothermal resource discovery or may have wells in place, but require the drilling of new or additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration do not have a geothermal resource discovery occurrence yet, but have significant thermal and other physical evidence that warrants the expenditure of capital in search of the discovery of a geothermal resource. Due to inflation and marketplace increases in the costs of labor and construction materials, previous estimates of property development costs may be low.
U.S. Geothermal Inc. (“the Company”) is a Delaware corporation. The Company’s common stock trades on the Toronto Stock Exchange under the symbol “GTH” and on the NYSE Amex LLC under the trade symbol “HTM.”
For the quarter ended March 31, 2011, the Company was focused on:
1)
Finalizing the reservoir model for the Neal Hot Springs reservoir and planning the 2011 drilling program;
2)
Negotiating a new PPA for San Emidio;
3)
Constructing the new San Emidio Unit 1 power plant in Nevada;
4)
Closing the Department of Energy Loan Guarantee for the Neal Hot Springs project;
5)
Completing the first phase of the DOE Innovative Exploration program and planning a drill program for the expansion of the San Emidio project;
6)
Negotiating partnership terms for San Emidio Phases I and II and discussing development funding for Phase III;
7)
Optimizing the operations of the existing San Emidio power plant in Nevada;
8)
Optimizing the operation of the well field at the Raft River project in Idaho (“Raft River Unit I”;
9)
Conducting negotiations for PPA and equity partners at the El Ciebello project in Guatemala; and
10)
The evaluation of potential new geothermal project acquisitions.
Raft River, Idaho
Raft River Energy Unit I is located in Idaho and has a 13 MW capacity geothermal power plant in operation.
Raft River Unit II is anticipated to cost approximately $134 million and Raft River Unit III is anticipated to cost approximately $166 million, up to 75% of which we believe may be funded by loans, with the remainder funded through equity financing. Provided funding is available, Raft River Unit II is anticipated to begin construction in the fourth calendar quarter of 2011 with commercial operations commencing in the fourth calendar quarter of 2013 or the first calendar quarter of 2014. Raft River Unit III is anticipated to begin construction in the first calendar quarter of 2014 with commercial operations commencing in the second calendar quarter of 2015.
Neal Hot Springs, Oregon
Neal Hot Springs is located in Malheur County, Oregon and has been established as a commercial geothermal resource.
On February 26, 2009 U.S. Geothermal submitted a loan application for the Neal Hot Springs project to the DOE’s Energy Efficiency, Renewable Energy and Advanced Transmission and Distribution Solicitation loan guarantee program under Title XVII of the Energy Policy Act of 2005. The financial closing for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8 million loan guarantee from the Department of Energy and a direct loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 million loan represents 75% of the total project cost which is now estimated to be $129 million for the project. The DOE loan is a combined construction and 22 year term loan. The interest rate on the loan is set at 37.5 basis points over the current average yield on outstanding marketable obligations of the United States of comparable maturity. With the $18.8 million equity investment made by Enbridge Inc., the project is 100 percent financed.
Notice to proceed was issued to both the EPC contractor (Industrial Builders Inc.) and equipment supplier (TAS Energy) on February 24, 2011. Detailed design and construction of the supercritical cycle power plant utilizing significantly improved technology is currently in progress. The new plant, which will consist of three separate power modules, is designed to deliver approximately 23 megawatt of power net to the grid. The first module is scheduled to begin commercial operations during the second calendar quarter of 2012 and the full plant is scheduled to be complete during the 3rd quarter 2012.
A long term reservoir test was initiated on November 16, 2010 with two production wells flowing brine at an average of 1,800-2,000 gallons per minute. Two injection wells were operated in tandem with the production to dispose of the fluid and to provide additional reservoir data. The flowing portion of the test ran until December 20, 2010 when the production wells were shut in and injection was halted. For a following 30 days, temperature and pressure instruments were maintained in the wells until January 24, 2011 when they were pulled and data downloaded.
Geologic information, flow, temperature and pressure data from the production and T/G drilling programs and the long term reservoir test is being incorporated into the ongoing development of a numerical reservoir model of the Neal Hot Springs geothermal system. The reservoir model was completed on March 24, 2011 and the DOE independent reservoir engineer issued a reservoir certificate on March 31, 2011. The final reservoir report and certificate confirmed that the reservoir was able to sustain the production necessary for the planned 23 megawatt project from the existing four production wells. An injection plan was developed as part of the plan, and drilling operations resumed on April xx, 2011 to complete the injection well field for the project. A large diameter injection well, NHS-12 is being drilled on the western boundary of the geothermal field to an anticipated depth of 5,000 feet.
As part of the injection well program, a temperature gradient (“TG”) well was started on the south end of the resource area to help determine the limit where heat flow from the active geothermal reservoir extended. This extension of heat flow would be used to site a deep injection well. Subsequent to the end of the quarter, the TG well was completed to 3,020 feet deep and indicated a positive temperature gradient.
On November 3, 2010, USG Oregon LLC, had successfully drilled and tested NHS-2, the fourth large diameter production well at the Neal Hot Springs geothermal project located in eastern Oregon. The production well encountered the reservoir at 2,983 feet (979 meters). The well flowed under artesian pressure at a rate of 3,027 gallons per minute (“gpm”). The production temperature of the well is 287º F (142º C). USG Oregon LLC is owned 80% by U.S. Geothermal and 20% by Enbridge Inc. Subject to establishing reservoir pressure support by drilling additional injection wells, the four wells complete the total production wells needed for the 23 net MW project. Three existing production wells have previously been drilled and tested. Well NHS-1 intersected the reservoir at 2,287 feet (750 meters) and flows under artesian pressure at a rate of 2,315 gpm with a production temperature of 286.5º F (141º C). Well NHS-5 encountered the reservoir at 2,796 feet (917 meters) and flows at a rate of 1,500 gpm and with a production temperature of 286º F (141º C). NHS-8 intersected the reservoir at 3,604 feet (1,182 meters) and flows at a rate of 2,770 gpm with a production temperature of 287.5º F (142º C).
Wells with a flowing temperature of 286º F (141º C) and a pumped flow rate of 2,000 to 3,000 gpm are considered very viable to substantiate commercial power generation.
The Company received the Conditional Use Permit from the Malheur County Planning Commission for construction of its proposed 23 net megawatt power plant at Neal Hot Springs in eastern Oregon. The Conditional Use Permit received unanimous approval at a September 24, 2009 Planning Commission meeting and was issued on October 28, 2009. All of the Federal Energy Regulatory Commission (“FERC”) mandated transmission studies have been completed by Idaho Power Company. An interconnection agreement was signed with the Idaho Power Company in February 2009. Private right-of-ways for the transmission line have been acquired, the line route is surveyed and the final engineering design is complete. Idaho Power Company is responsible for the construction of the transmission line with the cost paid for by the project. A notice to proceed was issued to Idaho Power Company to commence procurement and construction of the transmission line on April 8, 2011.
The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per megawatt-hour and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions.
San Emidio, Nevada
The San Emidio expansion will take place in three phases. Phase I is a repower and Phases II and III will be the expansion. Phase I will utilize the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant now under construction and expected to be online in the fourth quarter of 2011. The Phase I repower is anticipated to cost approximately $32 million. The Phase II expansion is anticipated to cost approximately $50 million. For Phases I and II, the Company has made an application for the DOE’s 1705 loan guarantee program anticipating that 75% of the total project capital may be funded by a Department of Energy loan guarantee, with the remainder funded through equity financing. Phase III is a further expansion planned a for 17.2 MW net utilizing two additional power modules similar to Phases I and II. The Phase I repower began construction in the third calendar quarter of 2010. The Phase II expansion is anticipated to begin construction in the second calendar quarter of 2010 with commercial operations commencing in the second calendar quarter of 2013. The Company expects to utilize Investment Tax Credits in connection with both the repower and the Phase II expansion. Both Phases I and II will require an amendment to the Sierra Pacific Power Purchase Agreement. Phase III is expected to follow construction of Phase II and be online by the fourth quarter of 2013. Both Phase II and Phase III are subject to successful development of additional production wells through exploration and drilling activities. Subsequent to the end of the quarter, the Company received a letter from the DOE stating that our application for a loan guarantee for Phases I and II has been put on hold. We are seeking clarification as to what this means and why our application was treated this way.
Phase I will utilize the existing production and injection wells with installation of a new, more efficient power plant. The existing, historic power plant will be placed on operational standby when the Phase I plant comes on line. As shown in the Project Development table above, the Phase I repower is anticipated to cost approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We expect 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.
The Phase I power plant began construction in August of 2010, with final completion scheduled to occur at the end of October 2011. All major foundations have been placed, main brine line tie to the new plant site completed, transmission line from the new plant site to the existing line installed, and the fresh water line for the cooling tower installed. Subsequent to the end of the quarter, the chemical building has been constructed, the main transformer is installed, and the cooling tower is being erected. The bulk of the major components for the power plant are scheduled to start arriving in late June and early July.
Phase II began development in the second calendar quarter of 2010 with commercial operations anticipated to commence in the second calendar quarter of 2013. The Company expects that the project will be granted about $28 million in ITC cash grant in lieu of PTC in connection with approximately $82 million Phase I and Phase II megawatt development.
On June 1, 2011, a PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts of electricity. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 percent annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the PPA. The PPA is subject to signature by NV Energy and approval by the Public Utility Commission of Nevada.
The Company entered into agreements with Science Applications International Corporation (“SAIC”) for a project loan and an engineering procurement and construction contract for the San Emidio Phase I power plant. SAIC’s design-build subsidiary, the Benham Companies LLC, will execute the construction of an 8.6 net megawatt power plant at San Emidio, Nevada. TAS Energy of Houston, Texas will supply a modular power plant to the project. The financing agreement calls for the contractor to provide a non-recourse project loan for the estimated $32 million dollar project. The construction loan is expected to be repaid with long term project loan.
Two System Feasibility Studies were initiated in July 2008 with Sierra Pacific Power Company to begin the FERC mandated transmission study process for the development of the San Emidio resource. The studies examined two levels of power generation; 15 megawatts and 45 megawatts, several transmission routes and the costs associated with each level of generation. The 15 megawatt study, which is directed toward the Phase I repower and Phase II, has completed the study process and resulted in an increase of available transmission to 16 megawatts. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010.
The 45 megawatt study, which is directed toward the full build out of San Emidio with the addition of the 17.2 megawatt Phase III project, completed the second phase System Impact Study in April. A draft Interconnection Facilities Study, the third and final study, was received on November 22, 2010. The remainder of the 45 megawatt study has been put on hold pending further exploration of the project.
On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets.
Surface geologic mapping by the University of Nevada-Reno has been completed and structural analysis of the mapping is underway. State-of-the-art interpretation of satellite data that measures ground surface deformation has also been completed. Preliminary results show excellent correlation between surface deformation and known producing fractures, establishing this method as an effective tool for locating wells. Field work for a high-precision seismic refraction survey is complete. Data processing and interpretation is complete and has been integrated with the structural mapping.
The results of the DOE exploration program have been finalized and submitted to the DOE for review. Drill sites have been selected, and permitting is underway for a targeted 3rd quarter start on the drilling program.
Guatemala
A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April. The concession contains 24,710 acres (100 square kilometers) in the center of the Aqua and Pacaya twin volcano complex.
The concession contains the El Ceibillo geothermal project which has nine existing geothermal wells that were drilled in the l990s and have depths ranging from 560 to 2,000 feet (170 to 610 meters). Six of the wells have measured reservoir temperatures in the range of 365°F to 400°F and have high conductive gradients that indicate rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicate the existence of a high permeability reservoir below the existing well field.
An office and staff are located in Guatemala City and planning is underway to advance the project with initial work focused on negotiating necessary surface and access rights, a power sales agreement with the local utility company, strategic investors, and potential project lenders. Follow up work will include a detailed geophysical program, geologic mapping, sampling of hot springs, and to redrill one or two of the existing wells to test for deep, high temperature permeability. Discussions and planning are underway for the development of a power purchase agreement. Also, discussions are taking place with several interested parties for the potential sale of a minority equity interest in the El Ciebillo project to a qualified local partner.
Gerlach Joint Venture
The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at 1,070 total depth. Temperature surveys and a short clean out flow test were conducted on the well.
A 2,000 foot deep temperature gradient well is permitted for the BLM lease site and is designed to test the deep temperature potential of the central portion of the interpreted reservoir block. A production target has been identified from previous drilling data at a depth of 2,700 to 3,000 feet.
Granite Creek
The Granite Creek assets are comprised of three BLM geothermal leases totaling approximately 5,414 acres (8.5 square miles) located about 6 miles north of Gerlach, Nevada along a geologic structure known to host geothermal features including the Great Boiling Spring and the Fly Ranch Geyser. A first stage gravity geophysical program was completed in the third quarter of 2008 and will be used to evaluate the resource potential, and help determine where to drill temperature-gradient exploration wells.
A summary of projects under development is as follows:
Factors Affecting Our Results of Operations
Although other factors may impact our operations and financial condition, including many that we do not or cannot foresee, we believe that our results of operations and financial condition for the foreseeable future will be affected by the following factors.
Raft River Energy I LLC
Raft River Unit I operated at 98.4% availability and generated an average of 7.95 net megawatts during the fourth fiscal quarter. For the 2010 calendar year, the plant averaged 8.39 net megawatts of generation with 97.7% availability. The plant is operating at reduced output due to the continued loss of temperature from production well RRG-7 and the shutdown of production well RRG-2.
In early January 2009, production well RRG-7 underwent a temperature decline that has now reduced the inlet fluid temperature to the power plant by approximately 11.8 degrees Fahrenheit. Power generation has been reduced by an estimated 1.5 megawatts due to the lower fluid temperature entering the plant. It was determined that the cement in a lap joint (an overlap of well casing) had failed and washed out, thereby allowing lower temperature fluid to enter the wellbore. Production well RRG-2 was shut down on June 10, 2010 due to a reduction in flow and increased motor load which indicates an impending pump failure.
The project does not generate sufficient revenue to complete the repairs out of cash flow so the repairs must be completed by additional capital investment by the partners or some other infusion of capital. Until the repairs are completed, the plant output will continue at an estimated annual average of about 7.8 megawatts. Plans for repair of both RRG-7 and RRG-2 are under a continuing discussion with Raft River I Holdings, a wholly owned subsidiary of Goldman Sachs Group Inc and the majority joint venture partner for Raft River Unit I.
On May 17, 2011, Raft River I Holdings, LLC finally consented to a repair plan for both RRG-2 and RRG-7. A Repair Services Agreement was executed between US Geothermal Services and Raft River Energy I LLC, whereby US Geothermal Services will provide up to $1.65 million in funding and manage the well repairs. The cost of the repairs will be repaid from project cash flow, and will be paid preferentially at a rate of 90% of increased cash created by the repairs. A fee of 12.75 percent of the actual repair cost incurred will be paid to USG Services. The outstanding balance of the repair cost will also earn USG Services interest income at the rate of 12.0 percent per-annum.
The $10.2 million DOE cost-shared thermal fracturing program continues on schedule. The Company’s contributions are made in-kind by the use of the RRG-9 well, well field data, and monitoring support totaling $228,089. Eight solar powered seismic stations were installed in June and will be used to monitor potential impacts from the test. Construction is complete on the injection pipeline that extends from the Unit 1 power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was completed during the 3rd fiscal quarter of 2010. It is now expected that a drill rig will be mobilized to set casing down to the geologic formation targeted for the thermal fracture test, and the first phase of cold water injection will commence during the 2nd quarter of 2011.
Raft River Operating Agreement
We hold a 50% interest in Raft River Energy I LLC, which owns Raft River Unit I (“Unit I”). Construction of Unit I required substantial capital, and partnering with a co-venturer tax partner allowed us to share the risks of ownership and monetize valuable tax credits and benefits. The joint venture partner structure allowed the project to monetize production tax credits which would not otherwise have been available to us. When Unit I operates at full capacity of 13 megawatts, we estimate we will receive cash payments totaling approximately $1.6 million for each of the first four years of its operations. While Unit I generates at less than full capacity, our annual cash payments from the Raft River I project will be lower. If insufficient cash is generated to satisfy all joint venture obligations, the management fees will be deferred. See Note 5 “Investment in Subsidiaries” in the financial statements for detail of cash payments from RREI.
The Company’s interests in the RREI as defined in the partnership agreements are summarized as follows:
(1)
U.S. Geothermal allocates 70% of income and receives 70% of available cash from RECs sold to third- parties. After year 10, REC income is shared with Idaho Power Co. For additional details, see U.S. Geothermal’s Form 10-Q filed on August 10, 2009 (Exhibit 10.36).
(2)
Flip to next tier occurs after the later of 10 years or Raft River I Holdings’ target IRR is achieved.
(3)
Flip to next tier occurs after Raft River I Holdings’ target IRR is achieved.
San Emidio, Nevada
The San Emidio geothermal power plant has been producing power since 1987 and sells electricity to Sierra Pacific Power Corporation under an existing power purchase agreement that extends through 2017. Deeper wells with higher temperatures were drilled in 1994 to supply the plant after output declined due to cooling of the original, shallow production wells. The current configuration of the plant consists of four 1.2 gross megawatt Ormat Energy Converters (“OEC”), five production wells (two wells in use), and four injection wells (three wells in use). A cooling tower was added in 1998 to improve summer peak power generation. During the third fiscal quarter ended December 31, 2010, the San Emidio plant operated at 99.6% availability and generated an average of 2.63 net megawatts during the period.
Power Purchase Agreements
Prior to the construction of a geothermal project, we typically enter into a power purchase agreement with a utility, which fixes the price of energy produced at a project for a 20 to 25 year period. Such PPAs are typically negotiated with the utility company and approved by a state utility commission or similar regulating body.
Power purchase agreements generally provide for the payment of energy payments, capacity payments, or both. Energy payments are calculated based on the amount of electrical energy delivered to the relevant power purchaser at a designated delivery point. The rates applicable to such payments are either fixed, subject to adjustments in certain cases, or are based on the relevant power purchaser’s short-run avoided costs calculated as the incremental costs that the power purchaser avoids by not having to generate such electrical energy itself or purchase it from others. Capacity payments, on the other hand, are generally calculated based on the amount of time that our power plants are available to generate electricity. Some power purchase agreements provide for bonus payments in the event that the producer is able to exceed certain target levels and forfeiture of payments if minimum target levels are not met.
Raft River Energy I LLC currently earns revenue from a full-output PPA with Idaho Power, which is expected to be 13-MWs annual average. The PPA expires in 2032. This PPA was signed as part of ongoing negotiations with Idaho Power for PPAs covering an expected total output of 45.5 MWs and may be used as the template for additional PPAs. The price of energy sold under the Idaho Power PPA is split into three seasons: power produced during the peak periods of July, August, November and December will be purchased at 120% of the set price; power produced in the three month low demand season will be purchased at 73.50% of the set price; and power produced in the remaining five months of the year will be purchased at 100% of the set price. The PPA sets a first year average purchase price of $53.60 per MW hour. The $53.60 purchase price is escalated each year at a compound annual rate of 2.1% until year 15. From years 16 to 25 of the contract the escalation rate will drop to 0.6% per year.
Power generated by San Emidio is sold to Sierra Pacific Power Corp. (NV Energy) pursuant to a 30 year PURPA PPA that terminates in December 2017. The PPA includes energy and capacity payment components, as well as peak and off-peak rates. Contract prices are adjusted annually on March 1 based upon the Handy-Whitman price index, total steam production plant category, as specified by Nevada Public Utility Commission standards for PURPA contracts. On May 31, 2011, we entered into a new power purchase agreement (“PPA”) with NV Energy. The PPA contemplates the purchase by NV Energy of an annual average of up to 19.9 net megawatts from the San Emidio Geothermal Project located in Washoe County, Nevada. The 25-year PPA anticipates the development of two electric power generation units at San Emidio. The PPA is subject to the Public Utilities Commission of Nevada (“PUCN”) approval and is expected to be submitted to the PUCN by NV Energy within 100 days of the announcement. USG Nevada LLC is currently investigating remedies for certain existing constraints related to transmission that may limit the total output of the project to 16 net megawatts. The base contract price is subject to adjustment annually based upon a fixed annual escalator. Upon PUCN approval, the PPA will replace the current 30 year Power Purchase Agreement that was scheduled to terminate in December 2017 with Sierra Pacific Power Corp. (NV Energy).
The power purchase agreement (“PPA”) for the Neal Hot Springs project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting price of $96 per MW-hour and escalates at a variable percentage annually. Idaho Power Company submitted the PPA to the Idaho Public Utilities Commission (“IPUC”) on December 28, 2009. Subsequent to the end of the year, the PPA was approved by the IPUC on May 20, 2010.
Results of Operations
San Emidio, Nevada Plant Operations
Summarized statements of operations for the San Emidio power plant are as follows:
* - represents eleven months of operations.
% - represents the percentage of total operating revenues.
Effective May 1, 2008, the Company purchased geothermal rights and a geothermal power plant located in the San Emidio Desert of North Western Nevada. The primary objective of the acquisition was to secure water rights for future development. While the plant was expected to produce positive cash flows, the plant was not expected to generate significant operating profits. The plant has produced positive cash flows for nine out of the last eleven quarters of full operations.
For the year ended March 31, 2011, energy sales totaled $2,438,471, an increase of $694,487 (39.8%) over same period ended in 2010 and an increase $1,021,619 (72.1%) from the same period ended in 2009. The increase was due to higher production levels and contracted rate increases. Significant improvements and repairs were made to the plant primarily in 2008 and 2009, which resulted in less downtime and increased plant efficiency. For the year ended March 31, 2011, the plant sold 22,303,021 kilowatt hours of energy (monthly average 1,858,585 kilowatt hours) which was an increase of 4,521,997 kilowatt hours from the same period ended in 2009 (monthly average 1,481,754). See quarterly production levels in the table below that details select financial information. For the fiscal year ended March 31, 2011, the average rate per kilowatt hour was $0.1093, which was an increase of 11.4% and 26.2% from the same periods ended 2010 and 2009; respectively. The plant is paid for energy production according to the terms of the PPA which are based on an energy plus capacity payment. Rates are adjusted annually (September 1 to September 1) with the energy price component based upon the producer price index for coal and the capacity price component based upon the Handy-Whitman Total Steam Production Plant Index. Premium rates are paid during the months June through September. The contracted rates per kilowatt hour for the San Emidio power plant are summarized as follows:
During the fiscal year ended March 31, 2010, repair and maintenance costs totaled $596,516 which was $478,757 (406.6%) and $396,410 (198.1%) higher than the same periods ended 2011 and 2009; respectively. In 2010, the Company’s notable repairs were made to: electrical breakers and system controls, the pentane storage and transfer system, gear boxes and drive shafts on all cooling tower fans, condenser tubes, turbine gaskets, the OEC oil cooler water pipelines, and production pumps. Repair costs in 2011 are considered to be at normal levels. Also, repair costs are being kept to a minimum since the plant is scheduled to be replaced in October 2011.
Select financial information by quarter is as follows:
Gain on Investment in Subsidiary (Raft River Energy I LLC)
The Company uses the hypothetical liquidation at book value method (“HLBV”) for allocating of Raft River Energy I LLC’s (“RREI”) profits and losses. This method utilizes the specific terms outlined in the RREI’s operating agreement or other authoritative documents. These terms include cash disbursement terms, associated financial instruments, debt arrangements, and rights to specific revenue streams. The primary element of the profit and loss allocation from inception has been the amount of renewable energy credits earned.
The Company’s gain from RREI of $288,612 for the fiscal year ended March 31, 2011, decreased $35,317 (10.9%) from same fiscal period ended in 2010, and decreased $251,203 (46.5%) from the same period ended 2009. This was primarily due to energy production levels decreases. Energy production for the fiscal years ended March 31, 2011, 2010, and 2009 totaled 68,490,568, 73,272,800 and 90,547,326 kilowatt hours; respectively. While the plant continues to function according to expectations, the volume and temperature of the geothermal water being delivered to the plant has been trending downward since 2009. This is due to the lap joint failure that began in January 2009 and the shut down of production well RRG-2 on June 10, 2010. An agreement between the partners has been reached, in principal, on the financing of the repairs. A repair program for the pump in RRG-2 (estimated $599,583) and lap joint in RRG-7 (estimated $994,017) began in May of 2011.
Summarized unaudited (based on different fiscal year-end than RREI Financial Statements included in Exhibit 13.2) statements of operations for RREI are as follows:
% - represents the percentage of total operating revenues.
Professional and Management Fees
For the fiscal year ended March 31, 2011, the Company incurred professional and management fees of $1,108,170, which is a decrease of $561,057 from the same period ended 2010, and a slight increase from the same period in 2009. For all three periods, significant legal costs were incurred for compliance with the SEC and the TSX exchange, as well as routine contract review. Legal fees exceeded $430,000, $529,000 and $395,000 in the fiscal years ended 2011, 2010 and 2009; respectively. In the fiscal year ended 2011, additional legal fees were incurred for the direct placement equity offering. In the 2010 fiscal year, additional legal fees were incurred for a private placement offering and responses to SEC comment letters. Costs paid to a consultant to document and test internal controls for compliance with the Sarbanes-Oxley Act totaled $95,192, $99,478, $135,499 for the fiscal years ended 2011, 2010 and 2009; respectively.
Salary and Related Costs
For the fiscal year ended March 31, 2011, the Company reported $1,084,385 in salaries and related costs, which was reasonably consistent with the same fiscal periods ended in 2010 and 2009. Overall, salary and related costs increased in 2011 due to the addition of two management and development employees, company-wide bonuses and a general wage increase. These increases were offset by a higher percentage of salaries and related costs that were allocated to capital projects. Allocations have been made for the Neal Hot Springs project for engineering, design, permitting and project management efforts needed for well drilling, reservoir evaluation and preliminary plant construction. At San Emidio, salary cost allocations have been made for efforts primarily related to the transmission line studies, the new power plant design, and on site construction for Phase I of the project.
Management and development employee salaries and related costs allocated to major U.S. Geothermal projects are summarized as follows:
% - represents the percentage of change from 2010 to 2011.
Amounts capitalized in 2009 were not significant.
Stock Based Compensation
For the fiscal year ended March 31, 2011, the Company reported $1,066,565 in stock based compensation, which was a decrease of $401,604 (27.4%) from the same fiscal period ended in 2010, and a decrease of $548,224 (34.0%) from the same fiscal period ended in 2009. The decreases were primarily due to the two factors that included the delay in the issuance of the 2010 stock options and a lower average common share price. In prior years, the annual stock option grants were awarded in the first fiscal quarter of the year. In the current fiscal year, the option grant was made on September 10, 2010, which resulted in a decrease of approximately $202,000 in stock based compensation recognized in the year ended March 31, 2011 from the same period ended in 2010. For the fiscal year ended 2011, there was a decrease in average stock price by approximately 29.7% from the same period in 2010 (39.0% from 2009), which resulted in approximately $218,000 decrease reported stock compensation.
Travel and Promotion
For the fiscal year ended March 31, 2011, costs were 22.7% higher than 2010 and 26.0% lower than 2009. Travel and promotions costs, generally, consist of business show sponsorships, investor relations services, and general employee and director travel reimbursement. Investor relations and general travel costs have been reasonably consistent over the past 3 fiscal years. Business and trade show sponsorships amounted to over $190,000, $89,000, and $297,000 for the fiscal years ended March 31, 2011, 2010, and 2009; respectively. In the fiscal year ended 2011, significant business show sponsorships were incurred for two European trades shows ($78,169) and the Clinton Global Initiative ($20,000). In the fiscal year ended 2009, significant sponsorships were paid to the Money Channel ($27,000), and MJD Media LLC ($200,000).
Liquidity and Capital Resources
We believe our cash and liquid investments at March 31, 2011 are adequate to fund our general operating activities through March 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, the issuance of equity and/or through the sale of ownership interest in tax credits and benefits.
The current financial credit crisis is not anticipated to impact the ability of our customers, Idaho Power Company and Sierra Pacific Power, to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. Projections for 2011 indicate that both projects, Raft River and San Emidio, will generate positive cash flows to the Company. However, the current status of the credit and equity markets could delay our project development activities while the Company seeks to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels. We are also pursuing additional available DOE loans and guarantees in order to reduce interest costs for any debt instruments the Company may require.
On March 7, 2011, the Company closed a direct registered placement of 5,000,000 shares of Common Stock at a price of $1.00 per share for gross proceeds of $5 million. Each investor also received a Common Stock Purchase Warrant exercisable for 50% of number of shares of Common Stock purchased. Each Warrant will entitle the holder to purchase one additional share of Common Stock for $1.075 per share. The Warrants expire March 3, 2012. The issue included a placement agent fee of 112,000 Common Shares and 56,000 Warrants plus expenses of approximately $15,000. The securities were offered by the Company pursuant to a registration statement filed with the Securities and Exchange Commission (“SEC”), which became effective on December 31, 2010. A prospectus supplement relating to the offering was filed with the SEC on February 28, 2010. After deducting for fees and expenses, the net proceeds were approximately $4.95 million. The net proceeds of the offering will be used for general working capital, including exploration, development and expansion of its geothermal properties
On February 24, 2011, the Company completed the financial closing with the U.S. Department of Energy (“DOE”) of a $96.8 -million loan guarantee to construct its planned 23-megawatt-net power plant at Neal Hot Springs in Eastern Oregon. Neal Hot Springs is the first geothermal project to complete a loan guarantee under DOE’s Title XVII loan guarantee program, which was created by the Energy Policy Act of 2005 to support the deployment of innovative clean energy technologies. The DOE loan guarantee will guarantee a loan from the U.S. Treasury’s Federal Financing Bank. The $96.8 -million Federal Financing Bank loan represents 75% of total project cost. When combined with the previously announced equity investment by Enbridge Inc., the loan provides 100 percent of the anticipated capital remaining to fully construct the project.
In September 2010, USG Oregon LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note. Upon conversion, the note shall be considered to be an equity contribution to the Company’s subsidiary. The conversion occurs automatically upon the closing of the Department of Energy (“DOE”) guaranteed project loan. The agreements also provide for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note, will earn Enbridge a 20% direct ownership in the subsidiary. In the event of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $5 million would be contributed by Enbridge that would increase their direct ownership by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments could increase Enbridge’s ownership to a maximum of 27.5% . Subsequent to the period end, Enbridge’s convertible promissory note converted into equity if the LLC and Enbridge contributed an additional $13,000,000.
In August 2010, USG Nevada LLC (a wholly owned subsidiary) entered into agreements with Benham Companies, LLC (subsidiary of Science Applications International Corporation) for a project loan. The project loan is expected to provide substantially all of the funding needed to construct an 8.6 net megawatt power plant for Phase I of the San Emidio project in northwest Nevada. Construction costs are estimated to be approximately $32 million and expected to be completed in October 2011. The construction loan is planned to be repaid with long term financing from available sources such as the Section 1705 loan guarantee program from the U.S. Department of Energy.
On March 16, 2010, the Company closed a private placement of securities issued pursuant to a securities purchase agreement (the "Purchase Agreement") entered into with several institutional investors, pursuant to which the Company issued 8,209,519 shares of common stock at a price of $1.05 per share for gross proceeds of approximately $8.6 million (the "Private Placement"). Pursuant to the terms of the Private Placement, each investor was also issued a common share purchase warrant (a "Warrant") exercisable for 50% of the number of shares of common stock purchased by the investor. The Company paid commissions to agents in connection with the Private Placement in the amount of approximately $516,000 and issued warrants to purchase up to 246,285 shares of common stock. The net proceeds of the offering (approximately $8.0 million) will be used by the Company to further develop its Neal Hot Springs geothermal project and for general working capital purposes.
On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The project at San Emidio will apply innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets.
On August 17, 2009, the Company completed a private placement of 8,100,000 Subscription Receipts (“Receipt”) at $1.35 CDN per Receipt for aggregate gross proceeds of CDN $10,935,000. Each Receipt was exchanged on December 17, 2009 for one share of common stock of the Company and one half of one common stock purchase warrant (a "Warrant"). Each Warrant entitles the holder thereof to acquire one additional share of common stock of the Company for $1.75 for 24 months from closing. The placement agents have been paid an aggregate cash fee of CDN $656,100, representing 6% of the aggregate gross proceeds of the offering, and have been issued compensation options, exercisable for 24 months, entitling the placement agents to purchase up to 243,000 shares of common stock of the Company at $1.22. The proceeds provided funds to drill production size wells at Neal Hot Springs to increase production capacity to 22 MW and allow a 30-day flow test to verify the well reservoir capacity. Completion of drilling is a condition precedent to the funding from the DOE loan program, if our application is approved.
Potential Acquisitions
The Company intends to continue its growth through the acquisition of ownership or leasehold interests in properties and/or property rights that it believes will add to the value of the Company’s geothermal resources, and through possible mergers with or acquisitions of operating power plants and geothermal or other renewable energy properties.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been made. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for the financial statements.
Cash and Cash Equivalents
The Company considers cash deposits and highly liquid investments to be cash and cash equivalents for financial reporting presentation on the consolidated balance sheet and statement of cash flows. The Company subscribes to the accounting standards that define cash equivalents as highly liquid, short-term instruments that are readily convertible to known amounts of cash, which are generally defined investments that have original maturity dates of less than three months. With the large value of funds invested in short-term deposits, small variations in short term interest rates may materially affect the value of cash equivalents. Investments in government obligations accumulate higher interest, but the principal balance is not insured by the FDIC.
Property, Plant and Equipment
During the development stage of operations, the Company has purchased and otherwise acquired geothermal properties for the production of power. The geothermal properties include: drilled wells, power plant components, power plant support components, land, land rights, surface water rights, and geothermal water rights. The Company’s first power plant became operational in January 2008. When the plant became operational, plant property and equipment costs were charged to operations in a systematic manner based upon the estimated useful lives of the individual assets. The factors and assumptions that comprise this allocation process will be based upon the best information available to us, and will be evaluated, at least, annually for viability. If it is determined that our cost allocations have produced results that vary significantly from the conditions surrounding the value of the Company’s geothermal properties, a gain or loss adjustment will be made in the period in which this determination is made. The cost allocation or amortization process is not intended to present the fair market value of our geothermal properties; rather to allocate the actual historical costs of those properties over their service lives.
Income Taxes
According to generally accepted accounting practices, entities must recognize assets and/or liabilities that originate with the differences in revenues and expenses presented for financial reporting purposes and those revenues and expenses that are utilized to comply with federal and state income tax law. Often deductions can be accelerated for income tax purposes, thus creating temporary timing differences. Other items (generally non-allowable expenses) do not reverse over time, and are considered to be permanent differences. These types of costs are, typically, not factored into the deferred income tax asset or liability calculation. The Company’s primary element that impacts the liability or asset calculation relates to the operating losses generated in its early stages of operation that will be allowed to offset future earnings. Stock-based compensation is another significant area that impacts that recognition of deferred income taxes. Compensation that has been provided to employees and contractors based upon the value of the issuance of stock options is reported as an operating cost. However, this compensation is not an allowable deduction for income tax purposes. At the end of the fiscal year, the Company’s significant tax differences would ultimately result in the recognition of an asset; however, due to the uncertainty surrounding future earnings, an allowance has been calculated that effectively removes the asset. The Company continues to track the financial elements that comprise the deferred income tax calculation and will remove or reduce the asset allowance if the Company is determined to be in position where it is likely to produce earnings.
Stock-Based Compensation
Effective April 1, 2007, the Company adopted a standard that states that if certain conditions are present surrounding the issuance of equity instruments as share based compensation, then circumstances may warrant the recognition of a liability for financial reporting purposes. One such condition was present when the Company originally issued stock options in a foreign currency (Canadian dollars) to employees before the beginning of the fiscal year. Authors of the standard have reasoned that when a condition is present that creates a financial risk to the recipient in addition to normal market risks (i.e., foreign currency translation risk), then the instrument takes on the characteristics of a liability, rather than an equity item. As the underlying stock options are exercised or are forfeited, then the stock based compensation liability will be reduced. The Company’s financial statements reflect these changes in the consolidated balance sheet. As the value of the options change over the vesting periods, these changes will ultimately be reflected in the amount of expense charged to operations.
The Company awards stock options for compensation to non-employees for services performed and/or services performed above and beyond expectations. After the services have been completed, the awards are made at the discretion of the Board of Directors. The fair value of the options are determined on the date the options are awarded according to several factors that include the exercise price of the option, the current price of the underlying share, the expected life of the options and the expected volatility of the stock. Generally speaking, a longer life and higher expected volatility yields a higher value of the option. In accordance with appropriate accounting guidance, the Company amortizes the value of these options as operating expense during the period in which they vest. Stock options awarded to Company employees are also valued on the date they are awarded. However, the value of these options are capitalized and expensed over the vesting period. The current vesting period for all options is eighteen months. The nature of the services provided determines whether the value will be expensed or added to the value of a Company asset. To date, no services have been provided directly related to the construction of property and equipment, thus, all services have been charged to operations.
Contractual Obligations
As of March 31, 2011, the following table denotes contractual obligation by payments due for each period:
(1)
Construction loan with Benham will be replaced at completion of construction period with long-term financing anticipated through a loan backed by DOE 1705 loan guarantee program.
(2)
Loan convertible to project equity in Neal Hot Springs project upon closing of DOE loan and receipt of GeoThermex reservoir certificate. The certificate was received and the conversion occurred in April 2011.
(3)
Payable liquidated to additional paid-in capital as stock options are exercised or expire.
Off Balance Sheet Arrangements
As of March 31, 2011, the Company does not have any off balance sheet arrangements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Risk on Investments
At March 31, 2011, the Company held investments of $7,610,027 in money market accounts. These are highly liquid investments that are subject to risks associated with changes in interest rates. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms.
Foreign Currency Risk
The Company is subject to limited amount of foreign currency risks associated with cash deposits maintained in Canadian currency. The Company has utilized and it is continuing to utilize the Canadian markets for raising capital. By proper timing of the transactions and then maintenance of adequate operating funds in other financial resources, the Company has been able to mitigate some of the risks surrounding foreign currency exchanges. At fiscal year end, the Company did not hold any deposits in Canadian currency. Also, the Canadian currency exchange rate has been reasonably consistent over the past fiscal year. As a matter of standard operating practice, the Company does not maintain large balances of Canadian currency; and, substantially, all operating transactions are conducted in U.S. dollars.
The strike price for the Company’s stock option grants prior to April 2007 has been stated in Canadian dollars as the plan has been administered through our Vancouver office and Pacific Corporate Trust Company. This subjects the Company to foreign currency risk in addition to the normal market risks associated with the stock price fluctuations. A long-term liability has been established to reflect the fair value of the stock options payable. The strike price on future option grants will be stated in US dollars.
Commodity Price Risk
The Company is exposed to risks surrounding the volatility of energy prices. These risks are impacted by various circumstances surrounding the energy production from natural gas, nuclear, hydro, solar, coal and oil. The Company has been able to mitigate, to a certain extent, this risk by entering into long-term power purchase contracts for the Raft River, Neal Hot Springs and San Emidio power plants. These types of arrangement will be the model for power purchase contracts planned for future power plants.
Item 8.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,” “Consolidated Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit),” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the consolidated financial statements that are a part of this Report (See Part IV, Item 15, exhibit 13.1) . Other financial information and schedules are included in the consolidated financial statements that are a part 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
In connection with the preparation of this annual report on Form 10-K, an evaluation was carried out by the Company’s management, with the participation of the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (“Exchange Act”)) as of March 31, 2011. Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosures.
Based on their evaluation, our Chief Executive Officer and Chief Financial Officer concluded disclosure controls and procedures were effective as of March 31, 2011.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The Company’s internal control over financial reporting includes those policies and procedures that:
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
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
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.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2011. In making this assessment, it used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management concluded that, as of March 31, 2011, the Company’s internal control over financial reporting is effective based on those criteria.
BehlerMick, P.S., independent registered public accounting firm, who audited and reported on the consolidated financial statements of U.S. Geothermal, Inc. included in this report, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of March 31, 2011, which report appears as Exhibit 13.1.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
As of the end of the period covered by this report, there have been no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the quarter ended March 31, 2011, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
The information required by this item is set forth below or incorporated by reference to information under the caption “Proposal 1 - Election of Directors” and to the information under the captions “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance-Board Qualifications and Selection Process” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on September 9, 2011. See also Part I - Item1 - Executive Officers of the Registrant.
Audit Committee and Audit Committee Financial Expert
Our Board has a separately-designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are John H. Walker, Paul A. Larkin and Leland L. Mink. Our Board has determined that Paul A. Larkin, Chairman of the Audit Committee, is an audit committee financial expert as defined by Item 407(d)(5) of Regulation S-K under the Exchange Act and that each member of the Audit Committee is independent under the NYSE Amex independence standards applicable to audit committee members.
Code of Ethics and Governance Guidelines
Our Board of Directors has adopted the U.S. Geothermal, Inc. Code of Business Conduct and Ethics to provide a corporate governance framework for our directors and management to effectively pursue U.S. Geothermal Inc.’s objectives for the benefit of our shareholders. The Board annually reviews and updates these guidelines and the charters of the Board committees in response to evolving “best practices” and the results of annual Board and committee evaluations. Our Code of Business Conduct and Ethics can be found at www.usgeothermal.com. by clicking on About Us and then Code of Ethics. Shareholders may request a free printed copy of our Code of Business Conduct and Ethics from our investor relations department by contacting them at info.usgeothermal.com or by calling (208) 424-1027. We will post any amendments to the Code of Business Conduct and Ethics at that location. In the unlikely event that the Board of Directors approves any sort of waiver to the Code of Business Conduct and Ethics for our executive officers or directors, information concerning such waiver will also be posted at that location. No waivers were granted in the most recent fiscal year. In addition to posting information regarding amendments and waivers on our website, the same information will be included in a Current Report on Form 8-K within four business days following the date of the amendment or waiver, unless website posting of such amendments or waivers satisfies applicable NYSE Amex listing rules.
Item 11
Item 11 - Executive Compensation
The information required by this item is incorporated by reference to information under the captions “Proposal 1 - Election of Directors” and “Executive Compensation” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on September 9, 2011.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated by reference to information under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Proposal 1 - Election of Directors” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on September 9, 2011.
Securities Authorized for Issuance under Equity Compensation Plans
The following table details the number of securities authorized for issuance under the Company’s equity compensation plans for the fiscal year ended March 31, 2011:
Item 13
Item 13 - Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to information under the captions “Corporate Governance” and “Certain Relationships and Related Transactions” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on September 9, 2011.
Item 14
Item 14 - Principal Accounting Fees and Services
The information required by this item is incorporated by reference to information under the caption “Audit Committee Report and Payment of Fees to Auditors” in the Company’s definitive Proxy Statement for its annual meeting of shareholders to be held on September 9, 2011.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
The following documents are filed as a part of this report:
2. Consolidated Financial Statements.
See Item 8 of Part II for a list of the Financial Statements filed as part of this report.
3. Financial Statement Schedules.
See Exhibit 13.2 for the following Financial Statement Schedules filed as part of this report:
Financial Statements for Raft River Energy I LLC
Report of Independent Auditors
Balance Sheets at December 31, 2010 and December 31,
Statements of Operations for the periods ended December 31, 2010, December 31, 2009, December 26, 2008 and November 28,
Statements of Cash Flows
Statement of Members’ Equity
Notes to the Financial Statement
3. Exhibits. See below.
EXHIBIT LIST
*Portions of these exhibits have been omitted based on a grant of, or an application for, confidential treatment from the SEC. The omitted portions of these exhibits have been filed separately with the SEC.
** Management contracts or compensation plans or arrangements in which directors or executive officers are eligible to participate.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
U.S. Geothermal Inc.
(Registrant)
June 9, 2011
/s/ Daniel J. Kunz
Date
Daniel J. Kunz
Chief Executive Officer and President
(Principal Executive Officer)
Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons on behalf of the Registrant in the capacities and on the date indicated: