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 is substantially complete and is in the process of becoming commercially operational. 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 fourth calendar quarter of 2013. The third phase is planned as a further expansion for 17.2 MW net utilizing two additional power modules similar to the first and second phases. The third phase is planned to be on line the fourth calendar quarter of 2014.
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. The project’s partner (Enbridge Inc.) has contributed over $32.8 million as of May 31, 2012. Enbridge’s equity interest has not been determined; however it will exceed 20%. The project is expected to be fully financed with the partners’ contributions and the DOE loan proceeds.
In October 2011, USG Oregon LLC began drawing on the DOE loan. During the fiscal year ended March 31, 2012, the Company completed drilling several wells for the Neal Hot Springs Oregon Project and substantial progress was made on construction of the power plant modules, cooling towers, support buildings and other critical components.
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 Creek, 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 may 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 may 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, 2012 are adequate to fund our general operating activities through December 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. Other project development, such as Guatemala, may require additional funding. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, market loans, 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. 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.
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 (“ITC”) in lieu of the production tax credit (“PTC”). The ITC may be converted into a cash grant within the first 60 days of operation of the plant. Phase I at San Emidio attained commercial operation on May 25, 2012. An application will be submitted in July 2012 electing to take the ITC cash grant in lieu of the PTC, which will result in a check from the U.S. Treasury for approximately $11 million by September 2012 and will be used to retire an existing bridge loan of approximately $7.5 million.
On May 21, 2012, U.S. Geothermal Inc. (the “Company”) entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, par value $0.001 per share (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof.
Pursuant to the Purchase Agreement, upon the satisfaction of all of the conditions to the Company’s right to commence sales under the Purchase Agreement (the “Commencement”), LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Thereafter, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT LLC exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the Toronto Stock Exchange.
The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares.
As of June 30, 2012, the Company has sold 750,000 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $259,425. Sales of shares of our common stock by our sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE MKT LLC or sales made through a market maker other than on an exchange. Our sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between our sales agent and us.
The Company has entered into an agreement with Kuhns Brothers Securities Corporation (“KBSC”), pursuant to which KBSC agreed to act as the placement agent in connection with the sale of shares of Common Stock to LPC. Subject to the Company’s and KBSC’s receipt of written confirmation that the Corporate Finance Department of Financial Industry Regulatory Authority, Inc. (“FINRA”) has determined not to raise any objection with respect to the fairness or reasonableness of the compensation terms of the Company’s arrangement with KBSC, the Company will pay KBSC the following compensation for its services in acting as placement agent in the sale of Common Stock to LPC: (A) the Company will pay a cash fee to KBSC in an amount equal to: (i) 6% of the aggregate gross proceeds received by the Company from the initial sale of $750,000 in shares of Common Stock to LPC pursuant to the Purchase Agreement, and (ii) 3% of the aggregate gross proceeds received by the Company from additional sales of Common Stock to LPC pursuant to the Purchase Agreement; and (B) the Company will issue to KBSC the number of warrants (the “Compensation Warrants”) equal to: (i) in the case of the initial sale of $750,000 in shares of Common Stock to LPC, 6% of the aggregate number of shares sold to LPC; and (ii) in the case of additional sales of Common Stock to LPC, 3% of the aggregate gross proceeds received by the Company from such sales divided by 115% of the closing sale price of one share of Common Stock on the day prior to the respective issuance of the Compensation Warrant. The Compensation Warrants issued pursuant to clause (ii) in the preceding sentence will be based on incremental sales to LPC of $2 million in aggregate gross proceeds. Each Compensation Warrant will have an exercise price equal to 115% of the closing sale price of one share of Common Stock on the day prior to its issuance, a term of five years from the date of its issuance and will otherwise comply with the rules of FINRA.
On November 14, 2011, U.S. Geothermal Inc. entered into a bridge loan agreement between its wholly owned subsidiary USG Nevada LLC and Ares Capital Corporation. The bridge loan has monetized the Section 1603 ITC cash grant associated with the planned commercial operation of the new Phase I power plant at the San Emidio Geothermal Project, located in Washoe County, Nevada. The loan agreement provides for payment to the Company of approximately 90% of the total expected cash grant and consists of an initial funding of $7.5 million which has been received by the Company. The funds are drawn from a loan facility that includes commercial terms for the payment of interest and associated fees. Once the placed in service date has been achieved, an application will be submitted to the United States Department of the Treasury for an estimated $11 million ITC cash grant. The cash grant proceeds will be used to repay the Ares Capital bridge loan facility with the remaining balance payable to USG Nevada LLC.
On September 30, 2011, U.S. Geothermal Inc., a Delaware corporation (the “Company”), entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”), pursuant to which the Company, from time to time, may issue and sell through MLV, acting as the Company’s sales agent, shares of the Company’s common stock. The Company’s board of directors has authorized the issuance and sale of shares of the Company’s common stock under the Sales Agreement for aggregate gross sales proceeds of up to $10,000,000, subject to certain limitations based on the sales price per share, for a period of one year from the date of execution of the Sales Agreement. Pursuant to the Sales Agreement, MLV will be entitled to compensation at a fixed commission rate of the greater of (i) 3% of the gross sales price per share sold or (ii)(1) $0.03 per share sold if the sale price per share is $0.80 or greater or (2) $0.0225 per share sold if the sale price per share is less than $0.80 (but in no event shall compensation exceed 8% of gross proceeds). The Company has agreed to reimburse a portion of MLV’s expenses in connection with the offering of the Company’s common stock under the Sales Agreement. This agreement was cancelled effective May 19, 2012.
As of May 19, 2012, the Company has sold 241,989 shares of common stock pursuant to the Sales Agreement for net proceeds of approximately $126,133. Sales of shares of our common stock by our sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE MKT LLC or sales made through a market maker other than on an exchange. Our sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between our sales agent and us.
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% 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 was considered to be an equity contribution to the Company’s subsidiary. The conversion occurred 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 $8 million was contributed by Enbridge that increased 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% . An additional $6 million cost overrun facility was established by Enbridge to cover costs that resulted from unexpected poor results from injection well drilling. The additional investment by Enbridge will increase their ownership in USG Oregon LLC based on running a project financial model and determine what percentage of the forecasted project income will be allocated to Enbridge to arrive at a predetermine rate of return for the additional investment. Current estimates of the ownership assuming that all of the investment is used for drilling shows that Enbridge could own up to 44% of the subsidiary. The model will be rerun after all of the variables have been fixed which is anticipated to be in the 4th quarter of 2012 to set the final ownership ratios between the two parties.
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 commercial sources.
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 96.8% availability and generated an average of 9.3 net megawatts during the third fiscal quarter. For the 2011 calendar year, the plant averaged 7.6 net megawatts of generation with 97.3% availability.
The plant operated at reduced output during the month of March due to a mechanical problem with the production pump in well RRG-2. The potential causes are being evaluated and plans are being made to pull the pump and inspect it.
The $10.2 million Department of Energy (“DOE”) cost-shared thermal fracturing program has been delayed while a NEPA evaluation was being done to address any potential seismic issues that may result from the program. 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 2010 to provide a base line of seismic data 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.
A drill rig for the DOE program was mobilized to the Raft River site in late December and began operations on December 30. A 9 7/8” liner was installed and cemented in place in preparation for the first phase of stimulation. The well was side-tracked during operations to remove a packer in the wellbore, and a new leg was completed through the geothermal target formation. A short duration, high pressure stimulation test was performed which indicated a temporary increase in permeability. Due to funding requirements, the project was placed on stand-by pending review of the results generated to date and further funding from the DOE.
On May 16, 2011, Eugene Water and Electric Board notified the Company that the PPA for Raft River Unit II has been terminated since a Notice to Proceed had not been issued on or before the required milestone date.
San Emidio, Nevada
The original San Emidio geothermal power plant produced power beginning in 1987 and sold electricity to Sierra Pacific Power Corporation. The original plant was shut down on December 12, 2011 and placed on operational standby in preparation for start up of the new Phase I power plant.
The San Emidio expansion is planned to take place in three phases. Phase I is a repower, and Phases II and III are planned to be expansions. Phase I utilizes the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant which achieved commercial operation on May 25, 2012. Phase II is a planned expansion within the bounds of the existing San Emidio geothermal reservoir and is subject to the successful development of additional production wells through exploration and drilling activities. Phase III is planned as a further expansion for 17.2 MW net utilizing two additional power modules similar to Phases I and II.
For Phases I and II, the Company 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. Due to funding difficulties experienced by the DOE loan guarantee program, a DOE loan guarantee is no longer available to the San Emidio project. Discussions with several senior lenders for a long term loan to take out the SAIC construction loan are ongoing.
On November 14, 2011, U.S. Geothermal Inc.’s wholly owned subsidiary USG Nevada LLC entered into a bridge loan agreement with Ares Capital Corporation. The bridge loan monetized the Section 1603 ITC cash grant associated with the new Phase I power plant at the San Emidio Geothermal Project, located in Washoe County, Nevada. The loan agreement provides for borrowing of up to 90% of the total expected cash grant and consisted of an initial funding of $7.5 million which has been received by the Company. No addition borrowings are expected at this time. The funds are drawn from a loan facility that includes commercial terms for the payment of interest and associated fees. Once the placed in service date has been achieved, an application will be submitted to the United States Department of the Treasury for an estimated $11 million ITC cash grant. The cash grant proceeds will be used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC.
The Phase I repower began construction in the third calendar quarter of 2010 and was delayed in the startup due to technical issues related to the new plant. The Phase II expansion began construction in the second calendar quarter of 2011 with commercial operations originally anticipated to commence in the fourth calendar quarter of 2013. Given the delay in getting Phase I online we are not able to accurately determine when Phase II will be completed. The Company expects to utilize the cash grant in lieu of the Investment Tax Credit in connection with both the repower and the Phase II expansion. The Phase II expansion is still dependent on successful development of additional production well capacity.
The capital cost of the Phase I repower is estimated at approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We expect that 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.
Phase I achieved mechanical completion in December 2011 and commercial operation on May 25, 2012. Commissioning was extended due to a series of mechanical issues that include defective capacitors, the mechanical failure of the 2,500 horsepower process pump, and excessive vibration in the turbine gear box. Performance testing of the power plant began in early May. The EPC contractor is providing its services under a fixed price contract that includes financial guarantees for the original completion date and power output of the plant.
Phase II began development in the second calendar quarter of 2010 with commercial operations, subject to successful production well development and timing related to financing availability for the construction of the plant, originally anticipated to commence in the fourth calendar quarter of 2013. The Company anticipated that the project would be granted approximately $16 million for Phase II in ITC cash grant in lieu of PTC in connection with the estimated $50 million of capital cost for Phase II development. There is uncertainty at this time if financing will be available to construct the Phase II plant in time to qualify for a startup prior to the end of 2013.
On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. 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 amended and restated PPA. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.
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, SAIC Energy, Environment & Infrastructure LLC, is executing 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 a 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 cost associated with each level of generation. The 15 megawatt study, which was directed at providing transmission for the Phase I and Phase II plants, 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. An additional System Impact Study was initiated on September 8, 2011 for an additional 3.9 megawatts of transmission to increase the transmission capacity to match the maximum limit of the new PPA. The 3.9 megawatt System Impact Study was completed in April and is being reviewed by the Company.
The 45 megawatt study, which was 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 has applied 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. Two zones along the 4.5 mile long San Emidio fault structure were identified as high quality targets for drilling during the first phase of the DOE program.
The second stage of the DOE program is a cost shared drilling plan that follows up on the targets identified in the first stage. In order to meet construction targets for Phase II plant construction, the drilling stage of the program commenced prior to DOE approval, and two observation/temperature gradient wells were completed by the Company. The proposed drilling program was approved by the DOE in early November 2011. One of the first two wells was deepened and three additional wells have been completed in the South Resource Area under the 50-50 cost share grant.
Three of the five wells exhibit commercial permeability and temperature with well OW-10 producing a flowing temperature of 302°F, well OW-9 exhibited a flowing temperature of 280°F and well OW-6 with a flowing temperature of 279°F. Well OW-9 also has a zone of high permeability at 1,830’ deep, which was put behind casing during drilling operations that has a measured static temperature of 294°F. Additional drilling operations would be required to test this zone. Well OW-8 encountered 320°F fluid, but did not produce commercial quantities during flow testing. The last well drilled, 45A-21, has just been completed and will undergo testing after a heat up period. The North Resource Area has an additional five observation/temperature gradient wells and one production well planned.
Neal Hot Springs, Oregon
Neal Hot Springs is a commercial geothermal resource located in Eastern Oregon that has a planned 23 megawatt power plant under construction.
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 67% of the total project cost which is now estimated to be $143.6 million for the project, a $14.6 million increase. 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 as determined on each date that a draw is made on the loan. As of May 31, 2012, eight monthly draws totaling $64.16 million have been taken on the DOE loan, which have a combined annual interest rate of 2.654% .
Over the course of the ongoing construction, the budget was increased by $14.6 million in equity contributions by the partners. The first increase was for $7.0 million to cover additional drilling costs and modifications in plant controls and the cooling mechanism. Enbridge Inc. of Canada, our partner at Neal Hot Springs, provided the additional investment in exchange for increased ownership interest in the project from 20% to approximately 27%. The project already has 100% of the required production capacity and about 60% of the required injection capacity proven. Certain wells were drilled into deep injection zones but two of these wells do not have satisfactory capacity; therefore, a second increase of $6 million has been established for an extended drilling program, about to be initiated, that is engineered to provide the required 40% capacity. Depending on the amounts contributed by each partner, this cash call may result in further adjustments in the ownership of the project.
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 megawatts of power net to the grid. The first module is scheduled to begin commercial operations during the third calendar quarter of 2012 and the full plant is scheduled to be completed late in the 3rd quarter 2012. As of May 31, construction of the total project is estimated to be 90 percent complete with about 65% of the DOE loan already drawn.
The EPC contractor has continued site construction work and the equipment supplier commenced equipment delivery. On May 27, the Company was notified by the EPC contractor that mechanical completion was achieved. All of the air cooled condensers for the three units have been installed and all major components are on site for Unit 2. Unit 2 mechanical completion is scheduled for June 7 and Unit 3 mechanical completion for by the end of June. Production and injection pipelines are being completed and insulation installed. Four production pumps have been installed and are ready to supply fluid to the power plant.
After the long term flow test that was completed in January 2011, a reservoir model was completed on March 24, 2011 by the Company’s consulting reservoir engineer, and after review, 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.
Four large diameter injection wells (NHS-3, NHS-9, NHS-12, and NHS-13) and three slim hole injectors (NHS-10, T/G 16b and T/G 3) have been completed and provide an estimated 70 percent of the capacity needed. NHS-4 and NHS-11, both planned as deep injectors, did not find the capacity needed. Three additional injection wells (two shallow ones and one deep injector) have been planned with drilling expected to be initiated during the first week of June. Once the Unit 1 power plant has achieved substantial completion and is operating continuously, reservoir and tracer testing will be started to complete the numerical reservoir model for the project.
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. As of the end of the quarter, Idaho Power has completed the transmission line and substation, and it is ready to accept power delivery.
The Power Purchase Agreement (“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 $96.00 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 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 feet total depth. Temperature surveys and a short clean out flow test were conducted on the well. The well flowed at an estimated 300-400 gallons per minute and the flowing temperature was 208°F. Geochemistry indicates an average potential source temperature of 374°F for the Gerlach site.
Drilling commenced on observation well 18-10a on October 30. The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. The well was secured and the drill rig was moved back to San Emidio. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160’ of surface and a temperature gradient of 6.4°F per 100’ in the bottom section of the hole. There are two previously identified lost circulation targets at 1,600’ and 2,800’ deep that will be targeted when drilling is resumed.
Drilling resumed on well 18-10a on April 14 and was stopped on April 18 at 1,943 feet deep. Circulation was lost in minor zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an isothermal temperature profile at 241°F which may indicate that higher temperature fluid does not occur below the 18-10a well site.
Granite Creek, Nevada
The Granite Creek assets are 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.
After a detailed review of the geologic setting, the lease position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles). One full lease and portions of the two remaining leases were relinquished to the Bureau of Land Management.
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 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 Ceibillo 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 recently decommissioned San Emidio plant was 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.
(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 and August 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.
(3)
Due to the delays experienced with bringing San Emidio Phase I on line, development dates for Phase II and Phase III at San Emidio have been effected and will be determined after Phase I has reached final completion.
(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)
An estimate by Black Mountain Technology of 44.0 megawatts.
(5)
A third party resource estimate with respect to 23.0 megawatts, remainder is an internal estimate.
(6)
Internal estimate.
Employees
At March 31, 2012, the Company had 42 full-time and one part time employee (14 administrative and project development, and 28 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.
Agency Approval
Status Effective
Date Approval
Number or
Designation
ODEQ (Oregon Department of Environmental
Quality) (Underground Injection Control Permit) Approved
3/29/2010
13281-8
ODWR (Oregon Department of Water Resources)
(Water Right) Approved
3/13/2008
LL-1103
ODEQ
(WPCF-1200 C; Storm Water Discharge Permit) Approved
10/12/2010
ORR10-C818
US Fish and Wildlife Service
(Endangered Species Act Consultation)
Completed
7/30/2009 13420-2009-TA-
Bureau of Land Management
(Drilling Permit)
Approved
12/07/2009
OR-66192
Bureau of Land Management
(Right-of-Way) Approved
1/12/2010
OR-65701
Bureau of Land Management
(NEPA/Environmental Assessment)
Completed
9/14/2009
DOI-BLM-OR-
V040-2009-030-
EA
Oregon Department of Geology and Mineral
Industries
(Well Drilling Permits)
Approved
2/11/2008
through
10/7/2010 DOGAMI Well
ID-184 through
Malheur County
(Conditional Use Permit) Approved
8/13/2009
10/21/2009
Malheur County
(Road Crossing Permit) Approved
3/5/2008
08-10
Idaho PUC Approval regarding the PPA
Approved
5/20/2010 Final Order
#31087
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 operating revenues for the three most recent fiscal years ended March 31, 2012 and 2011 were $5,894,113 and $3,253,545; 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.
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.
On December 10, 2010, a second REC contract was signed with Public Utility District No. 1 of Clallam County, Washington. The term of the agreement is from 2018 to 2034 and includes sales of an estimated 50,000 MWHs annually, representing the 49% ownership in RECs retained by RRU1 under the Idaho Power PPA.
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 sold 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 Chief Executive Officer, Daniel J. Kunz, our Chief Financial Officer, Kerry D. Hawkley, our Treasurer and Executive Vice President, Jonathan Zurkoff, our President and 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 MKT 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, 2012, from a low of $0.34 CDN to a high of $1.07 CDN on the TSX Exchanges and from a low of $0.34 to a high of $1.11 on the NYSE MKT. The trading price of our common stock on the TSX Exchange and on the NYSE MKT 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.
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 has a population of about 11,000 and 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.
All of the leases may be extended indefinitely as long as production is maintained from the lease either individually or as a geothermal unit. 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. 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 and scheduled for initial power production late in the third quarter of 2012.
USG Oregon LLC, has drilled four production wells (NHS-1, 2, 5, and 8) and eight injection (NHS-3, 5, 9, 10, 11, 12, 13, 14) wells at the project.
The Company has been issued permits for three additional wells if necessary. The annual permit renewal obligation with the Oregon Department of Geology is $500 per well or ($6,000) annually.
The project is projected to deliver power in the 2nd 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 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 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. Annual rental is credited against production royalty payments.
San Emidio, Nevada
In 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 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 produced power from 1987 until December 2011. The power plant was constructed in 1986 with commercial power generation beginning in 1987. The original plant has been replaced with a new 8.6 MW facility located on private land owned by USG Nevada. Phase 1 repowering is being completed utilizing the existing production and injection wells. The facility is being tested during the first and second quarters of 2012 with commercial power production expected in the second quarter of 2012.
USG Nevada is still investigating the opportunity for expansion under Phase II and III.
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.
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, as long as 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 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. The federal royalty is calculated based upon the percentage of acres of federal geothermal resources within the participating area and production royalty of 10.0% of the value of the resources prior to production cost deductions as required by a formula established by the Minerals Management Service.
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 2,443 acres (3.8 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 a geothermal lease contract with the BLM. The lease contract is for approximately 2,443 acres of land and geothermal water rights located in the northwestern Nevada. The lease contract has a primary term of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years as long as the lessee maintains production in commercial quantities. The lease requires an annual lease payment of $2,443, not including processing fees, and will expire October 31, 2012.
Republic of Guatemala
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 first annual renewal option was exercised in January 2012. The lease payments are due in monthly installments of $6,345 per month.
Item 3.
Item 3. Legal Proceedings
As of June 30, 2012, 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 MKT/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 MKT, 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, 2010.
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 loans 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. As of March 31, 2012, long-term obligations did not include stock compensation payable.
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 MKT LLC under the trade symbol “HTM.”
For the fiscal year ended March 31, 2012, the Company was focused on:
1)
Commissioning and performance testing of the new San Emidio Unit I power plant in Nevada;
2)
Drilling injection wells and construction for the Neal Hot Springs project in Oregon;
3)
Started the drilling of observation and production wells for the San Emidio Phase II project in conjunction with the DOE Innovative Exploration program;
4)
Negotiating long term financing for San Emidio Phases I and II and discussing development funding for Phase III;
5)
Conducting negotiations with potential equity partners for the El Ciebillo project in Guatemala; and
6)
The evaluation of potential new geothermal projects acquisitions.
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 67% of the total project cost which is now estimated to be $143.6 million for the project, a $14.6 million increase. 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 as determined on each date that a draw is made on the loan. As of May 31, 2012, eight monthly draws totaling $64.16 million have been taken on the DOE loan, which have a combined annual interest rate of 2.654% .
Over the course of the ongoing construction, the budget was increased by $14.6 million in equity contributions by the partners. The first increase was for $7.0 million to cover additional drilling costs and modifications in plant controls and the cooling mechanism. Enbridge Inc. of Canada, our partner at Neal Hot Springs, provided the additional investment in exchange for increased ownership interest in the project from 20% to approximately 27%. The project already has 100% of the required production capacity and about 60% of the required injection capacity proven. Certain wells were drilled into deep injection zones but two of these wells do not have satisfactory capacity; therefore, a second increase of $6 million has been established for an extended drilling program, about to be initiated, that is engineered to provide the required 40% capacity. Depending on the amounts contributed by each partner, this cash call may result in further adjustments in the ownership of the project.
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 megawatts of power net to the grid. The first module is scheduled to begin commercial operations during the third calendar quarter of 2012 and the full plant is scheduled to be completed late in the 3rd quarter 2012. As of May 31, construction of the total project is estimated to be 90 percent complete with about 65% of the DOE loan already drawn.
The EPC contractor has continued site construction work and the equipment supplier commenced equipment delivery. On May 27, the Company was notified by the EPC contractor that mechanical completion was achieved. All of the air cooled condensers for the three units have been installed and all major components are on site for Unit 2. On June 28th, the construction contractor provided notice of mechanical completion for the second of the three 7.3 net megawatt, air cooled power plant modules. Production and injection pipelines are being completed and insulation installed. Four production pumps have been installed and are ready to supply fluid to the power plant.
After the long term flow test that was completed in January 2011, a reservoir model was completed on March 24, 2011 by the Company’s consulting reservoir engineer, and after review, 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.
Four large diameter injection wells (NHS-3, NHS-9, NHS-12, and NHS-13) and three slim hole injectors (NHS-10, T/G 16b and T/G 3) have been completed and provide an estimated 70 percent of the capacity needed. NHS-4 and NHS-11, both planned as deep injectors, did not find the capacity needed. Three additional injection wells (two shallow ones and one deep injector) have been planned with drilling expected to be initiated during the first week of June. Once the Unit 1 power plant has achieved substantial completion and is operating continuously, reservoir and tracer testing will be started to complete the numerical reservoir model for the project.
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. As of the end of the quarter, Idaho Power has completed the transmission line and substation, and it is ready to accept power delivery.
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 $96.00 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 is planned to take place in three phases. Phase I is a repower, and Phases II and III are planned to be expansions. Phase I utilizes the existing production and injection wells with installation of a new, more efficient 8.6 MW net power plant which achieved commercial operation on May 25, 2012. Phase II is a planned expansion within the bounds of the existing San Emidio geothermal reservoir and is subject to the successful development of additional production wells through exploration and drilling activities. Phase III is planned as a further expansion for 17.2 MW net utilizing two additional power modules similar to Phases I and II.
For Phases I and II, the Company 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. Due to funding difficulties experienced by the DOE loan guarantee program, a DOE loan guarantee is no longer available to the San Emidio project. Discussions with several senior lenders for a long term loan to take out the SAIC construction loan are ongoing.
On November 14, 2011, U.S. Geothermal Inc.’s wholly owned subsidiary USG Nevada LLC entered into a bridge loan agreement with Ares Capital Corporation. The bridge loan monetized the Section 1603 ITC cash grant associated with the new Phase I power plant at the San Emidio Geothermal Project, located in Washoe County, Nevada. The loan agreement provides for borrowing of up to 90% of the total expected cash grant and consisted of an initial funding of $7.5 million which has been received by the Company. No addition borrowings are expected at this time. The funds are drawn from a loan facility that includes commercial terms for the payment of interest and associated fees. Once the placed in service date has been achieved, an application will be submitted to the United States Department of the Treasury for an estimated $11 million ITC cash grant. The cash grant proceeds will be used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC.
The Phase I repower began construction in the third calendar quarter of 2010 and was delayed in the startup due to technical issues related to the new plant. The Phase II expansion began construction in the second calendar quarter of 2011 with commercial operations originally anticipated to commence in the fourth calendar quarter of 2013. Given the delay in getting Phase I online we are not able to accurately determine when Phase II will be completed. The Company expects to utilize the cash grant in lieu of the Investment Tax Credit in connection with both the repower and the Phase II expansion. The Phase II expansion is still dependent on successful development of additional production well capacity.
The capital cost of the Phase I repower is estimated at approximately $32 million, with Phase II at approximately $50 million and Phase III approximately $100 million. We expect that 75% of the Phase I and Phase II development may be funded by project loans, with the remainder funded through equity financing.
Phase I achieved mechanical completion in December 2011 and commercial operation on May 25, 2012. Commissioning was extended due to a series of mechanical issues that include defective capacitors, the mechanical failure of the 2,500 horsepower process pump, and excessive vibration in the turbine gear box. Performance testing of the power plant began in early May. The EPC contractor is providing its services under a fixed price contract that includes financial guarantees for the original completion date and power output of the plant.
Phase II began development in the second calendar quarter of 2010 with commercial operations, subject to successful production well development and timing related to financing availability for the construction of the plant, originally anticipated to commence in the fourth calendar quarter of 2013. The Company anticipated that the project would be granted approximately $16 million for Phase II in ITC cash grant in lieu of PTC in connection with the estimated $50 million of capital cost for Phase II development. There is uncertainty at this time if financing will be available to construct the Phase II plant in time to qualify for a startup prior to the end of 2013.
On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1 % annual escalation rate. The electrical output from both Phase I and Phase II will be sold under the terms of the amended and restated PPA. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.
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, SAIC Energy, Environment & Infrastructure LLC, is executing 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 a 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 cost associated with each level of generation. The 15 megawatt study, which was directed at providing transmission for the Phase I and Phase II plants, 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. An additional System Impact Study was initiated on September 8, 2011 for an additional 3.9 megawatts of transmission to increase the transmission capacity to match the maximum limit of the new PPA. The 3.9 megawatt System Impact Study was completed in April and is being reviewed by the Company.
The 45 megawatt study, which was 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 has applied 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. Two zones along the 4.5 mile long San Emidio fault structure were identified as high quality targets for drilling during the first phase of the DOE program.
The second stage of the DOE program is a cost shared drilling plan that follows up on the targets identified in the first stage. In order to meet construction targets for Phase II plant construction, the drilling stage of the program commenced prior to DOE approval, and two observation/temperature gradient wells were completed by the Company. The proposed drilling program was approved by the DOE in early November 2011. One of the first two wells was deepened and three additional wells have been completed in the South Resource Area under the 50-50 cost share grant.
Three of the five wells exhibit commercial permeability and temperature with well OW-10 producing a flowing temperature of 302°F, well OW-9 exhibited a flowing temperature of 280°F and well OW-6 with a flowing temperature of 279°F. Well OW-9 also has a zone of high permeability at 1,830’ deep, which was put behind casing during drilling operations that has a measured static temperature of 294°F. Additional drilling operations would be required to test this zone. Well OW-8 encountered 320°F fluid, but did not produce commercial quantities during flow testing. The last well drilled, 45A-21, has just been completed and will undergo testing after a heat up period. The North Resource Area has an additional five observation/temperature gradient wells and one production well planned.
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. Construction dates have not been established for Raft River Unit II and Unit III.
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 Ceibillo 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 feet total depth. Temperature surveys and a short clean out flow test were conducted on the well. The well flowed at an estimated 300-400 gallons per minute and the flowing temperature was 208°F. Geochemistry indicates an average potential source temperature of 374°F for the Gerlach site.
Drilling commenced on observation well 18-10a on October 30. The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. The well was secured and the drill rig was moved back to San Emidio. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160’ of surface and a temperature gradient of 6.4°F per 100’ in the bottom section of the hole. There are two previously identified lost circulation targets at 1,600’ and 2,800’ deep that will be targeted when drilling is resumed.
Drilling resumed on well 18-10a on April 14 and was stopped on April 18 at 1,943 feet deep. Circulation was lost in minor zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an isothermal temperature profile at 241°F which may indicate that higher temperature fluid does not occur below the 18-10a well site.
Granite Creek
The Granite Creek assets are 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.
After a detailed review of the geologic setting, the lease position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles). One full lease and portions of the two remaining leases were relinquished to the Bureau of Land Management.
A summary of projects under development is as follows:
(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 and August 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.
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 96.8% availability and generated an average of 9.3 net megawatts during the third fiscal quarter. For the 2011 calendar year, the plant averaged 7.6 net megawatts of generation with 97.3% availability.
The plant operated at reduced output during the month of March due to a mechanical problem with the production pump in well RRG-2. The potential causes are being evaluated and plans are being made to pull the pump and inspect it.
The $10.2 million DOE cost-shared thermal fracturing program has been delayed while a NEPA evaluation was being done to address any potential seismic issues that may result from the program. 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 2010 to provide a base line of seismic data 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.
A drill rig for the DOE program was mobilized to the Raft River site in late December and began operations on December 30. A 9 7/8” liner was installed and cemented in place in preparation for the first phase of stimulation. The well was side-tracked during operations to remove a packer in the wellbore, and a new leg was completed through the geothermal target formation. A short duration, high pressure stimulation test was performed which indicated a temporary increase in permeability. Due to funding requirements, the project was placed on stand-by pending review of the results generated to date and further funding from the DOE.
On May 16, 2011, Eugene Water and Electric Board notified the Company that the PPA for Raft River Unit II has been terminated since a Notice to Proceed had not been issued on or before the required milestone date.
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-venture 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 generates 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.
Initially, Raft River Energy I LLC (“RREI”) was a wholly owned subsidiary of the Company and was recorded as a fully consolidated subsidiary into the Company’s financial statements. In 2006, Raft River I Holdings (“Holdings”), a subsidiary of the Goldman Sachs Group, acquired an equity interest by providing a significant capital investment in RREI under a tax equity structure. Subsequent accounting activity of RREI was reflected under the equity method on the Company’s consolidated financial statements.
Based on management’s annual review of the conditions and circumstances surrounding the relationship between the Company and Holdings, it was determined that the Company would no longer use the equity method to reflect the Company’s interest in RREI as of April 1, 2011. The Company will now fully consolidate RREI’s assets, liabilities and operations and recognize a non-controlling interest. When making this determination, Management analyzed whether control had shifted to the Company for accounting purposes, and noted that participation by Holdings is passive. The Board of Managers does not hold regular meetings, does not formally approve the annual operating budgets, and Holdings declines to contribute additional funds even when benefits can be shown. The Company has possession of and operates the facility, makes all day-to-day operating decisions, and contributes additional required capital repair funding as needed. Active participation in the operations of RREI is a primary role of the Company’s operating staff. The most critical point that has changed is the economics of the project due to the zero balance in the Raft River Holding’s tax capital account. Tax deductions associated with an additional $12.1 million equity contribution from the Company accelerated the exhaustion of the Holdings tax capital account to zero sooner than originally anticipated. The Company will be allocated 100% of the tax deductions and operating losses for the tax year 2011 and subsequent years. Since the current structure of RREI was established to allocate significant tax benefits to Holdings, the exhaustion of the Holdings tax capital account to zero demonstrates that the majority of the tax benefits have been monetized. Holdings no longer has any tax capital at risk. The Company is the only partner with tax capital at risk, so future operating decisions will primarily impact the Company.
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 original San Emidio geothermal power plant produced power beginning in 1987 and sold electricity to Sierra Pacific Power Corporation. The original plant was shut down on December 12, 2011 and placed on operational standby in preparation for start up of the new Phase I power plant.
Power Purchase Agreements (“PPA”)
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 allows power sales up to 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 the original San Emidio power plant was sold to Sierra Pacific Power Corp. (NV Energy) pursuant to a 30 year PURPA PPA was scheduled to terminate in December 2017. The PPA included energy and capacity payment components, as well as peak and off-peak seasonal rates. Contract prices were 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 June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. 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 amended and restated PPA. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011.
The power purchase agreement 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 and it was approved by the IPUC on May 20, 2010.
Results of Operations
For the fiscal year ended March 31, 2012, the Company reported a net loss of attributable to the Company’s operations of $6.2 million ($0.07 loss per share) which represented an unfavorable increase of $2.2 (55.0%) from the fiscal year ended 2011. Notable favorable variances were reported in earned management fees and travel and promotion expenses. Notable unfavorable variances were reported for the San Emidio operations, Raft River operations, professional and management fees, salaries and related costs and stock based compensation. Also, additional information was provided concerning the loss on the disposal of water rights and the removal of exploration costs included in the other operation expenses line item.
Plant Operations and Other Plant Expenses
During the current fiscal year, the Company’s operating revenues from energy production and related operating costs originated from two power plants. The San Emidio plant (USG Nevada LLC) is located in the San Emidio Desert in the North Western part of the State of Nevada. The original San Emidio plant and related water rights were purchased in 2008. The old plant ceased operations in December 2011 and was replaced with a new plant that began commercial operations in June of 2012. The Raft River plant (Raft River Energy I LLC) is located in the South Eastern Idaho. The Raft River plant began operations in January of 2008.
San Emidio, Nevada Plant Operations
The energy and energy credit sales generated from the San Emidio power plant represented 28.8% of total operating revenues for the Company for the year ended March 31, 2012.
For the fiscal year ended March 31, 2012, the San Emidio plant reported net loss of $880,764 which was a higher loss from the $640,057 net loss from the fiscal year ended 2011. On December 12, 2011, the old power plant was shut down to facilitate the change to the new power plant. Due to the shut down, no energy was produced in the fourth fiscal quarter March 31, 2012 and less than average amounts of energy were produced during the third fiscal quarter ended December 31, 2011. See the key quarterly production data presented below for additional energy production and revenue information. For the fiscal year ended March 31, 2012, energy sales deceased $823,282 (33.8%) from the same fiscal year ended 2011. Operating expenses decreased $174,048 (6.3%) from fiscal year ended 2011 to 2012. One factor that the decrease in operating expenses was not proportional to the decrease operating revenues was the significant increase in property taxes. During the current fiscal year, annual property taxes of $292,711 were paid to Washoe County, which was a significant increase (188.0%) from the prior year’s tax assessment. The increase in taxes was primarily based upon the assessed value of the new power plant. Property taxes were included in the general and administrative line item of the summarized financial information. The current fiscal year depreciation costs decreased (24.9%) from the prior fiscal year due to some assets reaching their estimated useful lives and the power plant and related components being taken out of operation. Summarized financial and production information is presented below.
A new 25 year PPA was signed in December of 2011 that sets the new set rate at $0.0897 per kilowatt hour with a 1% annual escalation rate.
Summarized statements of operations for the San Emidio power plant are as follows:
%* - represents the percentage of total operating revenues.
%** represents the percentage of change from 2011 to 2012.
Key quarterly production and financial data for the San Emidio, Nevada plant is summarized as follows:
* - The old power plant ceased operations on December 12, 2011, to facilitate the transfer of operations to the new power plant.
Raft River Plant Operations
The energy and energy credit sales generated from the Raft River power plant represented 71.2% of total operating revenues for the Company for the year ended March 31, 2012.
In January 2009, the lap joint for one of the production wells (RRG-7) began to fail. The failure resulted in a reduction in water temperature that had a negative impact on energy production for both fiscal years ended March 31, 2011 and 2012. In June of 2010, a production well RRG-2 was shut down. In May 2011, the repairs of wells RRG-2 and RRG-7 began under the terms of the Repair Service Agreement between the two partners. The repairs were completed in January 2012 and amounted to over $1.65 million. From January 2012 to March 2012, the plant operated at an average of 9.29 megawatts, which was a 27.8% increase from the average production levels from April 2011 to December 2011. Summarized financial and production information is presented below.
Summarized statements of operations for RREI are as follows:
%* - represents the percentage of total operating revenues.
%** - represents the percentage of change from 2011 to 2012.
# - percentage of variance either exceeds 600% or is undefined.
Key quarterly production and financial data for RREI is summarized as follows:
Management Fees; Land, Water and Mineral Rights Lease Revenues
In the fiscal year ended March 31, 2011, the Company recognized management fees and revenues from the lease of land and water rights of $250,000 and $196,893; respectively. All of these operating revenues originated from the Company’s subsidiary (Raft River Energy I LLC). As of April 1, 2011, the Company no longer reports Raft River Energy I LLC operations under the equity method. Accordingly, these revenues are now eliminated during the consolidation process.
Professional and Management Fees
For the fiscal year ended March 31, 2012, the Company incurred professional and management fees of $1,889,142, which was an increase of $760,149 (67.3%) from the fiscal year ended 2011. In the first fiscal quarter ended June 30, 2011, fees of $1,088,091 were paid to a placement agent for obtaining the equity partner in the Neal Hot Springs, Oregon project. This type of cost has not been incurred in prior periods. During the year ended March 31, 2012, operational legal fees amounted to approximately $310,000 that were primarily incurred for SEC filing/reporting and preparing a prospectus for an At-the-Market offering. Consulting costs directly identified as incurred for compliance with the Sarbanes-Oxley Act decreased approximately $33,000 (34.7%) from the fiscal year ended 2011.
Salary and Related Costs
For the fiscal year ended March 31, 2012, the Company reported $1,237,461 in salaries and related costs, which was increase of $175,084 (46.3%) from the fiscal year ended 2010. Overall, salary and related costs increased in 2012 due to the addition of two management and development employees, company-wide bonuses and a general wage increase. The company-wide bonuses totaled $450,000. A portion of these increases were offset by a portion 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 plant construction. At San Emidio, salary cost allocations have been made for efforts primarily related to the new power plant construction management for Phase I of the project.
% - represents the percentage of change from 2011 to 2012.
Stock Based Compensation
For the year ended March 31, 2012, the Company reported $1,454,376 in stock based compensation, which was an increase of $387,811 (36.4%) from the fiscal year ended 2011. Stock based compensation includes the calculated values of both Company stock and stock options. The variance was primarily a related to of the timing of the issuance of the stock option grants. On June 3, 2011, the Board of Directors approved a grant of 2,590,000 stock options to employees. In the prior year, the stock option grant was not approved until September 10, 2010. On September 10, 2010, the Company granted of 705,000 common shares to officers, directors and select employees shares to vest over three six-month periods. The value of the employee stock compensation for the years ended March 31, 2012 and 2011 was $248,577 and $261,372; respectively.
Travel and Promotion
For the fiscal year ended March 31, 2012, costs were $175,084 (46.3%) lower than the fiscal year ended 2011. The majority of the decrease related to shifting resources away from investor relation and other promotional activities. Investor relations and other business promotional sponsorships totaled $113,043 and $235,331 for the years ended March 31, 2012 and 2011; respectively, which was a decrease of $122,288 (52.0%) .
Other Operating Expenses
For the year ended March 31, 2012, the Company reported $559,066 in other operating expenses, which was an increase of $425,511 (318.6%) from the fiscal year ended 2011. During the quarter ended December 31, 2011, the Company expensed $463,391 in costs associated with the development of test wells held by USG Gerlach LLC. Some of the costs were incurred in the current quarter and $260,641 was removed from construction in progress. Since these costs by were shared by our partner who holds a 40% non-controlling interest in USG Gerlach LLC; $185,356 was added back to net income attributable to the Company’s operations.
Net Loss Attributable to the Non-Controlling Interest
The net loss attributable for the non-controlling interest entities is the line item that removes the portion of the Company’s consolidated operations that is owned by the Company’s subsidiaries. For the year ended March 31, 2012, the Company reported $4,567,155 in net loss attributable to non-controlling interest, which was an increase of $4,549,235 from the same fiscal year ended 2011. The primary reasons for the increase were the consolidation of Raft River Energy I LLC (“RREI”) and the loss reported by USG Gerlach LLC. Effective April 1, 2011, the operations of RREI were fully consolidated into the Company’s consolidated financial statements. The impact of including the operations RREI in the Company’s financial statements on the loss attributable to non-controlling entities amounted to $4,362,683 for the fiscal year ended March 31, 2012. As noted above, the loss attributable to USG Gerlach LLC increased significantly ($185,356) due to the costs associated with the development of test wells.
Loss on Disposal of Water Rights
In February 2012, water rights on 2,917 acres leased property in the Granite Creek area located in the State of Nevada were relinquished and removed from intangible assets at their carrying amounts that totaled $548,701. The relinquishment was considered to be a loss that was recognized in the current year ended March 31, 2012.
Liquidity and Capital Resources
We believe our cash and liquid investments at March 31, 2012 are adequate to fund our general operating activities through December 31, 2012 including drilling at Neal Hot Springs, general development support activities at San Emidio and repair activities at Raft River. Other project development, such as Guatemala, may require additional funding. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, market loans, 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. 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.
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 (“ITC”) in lieu of the production tax credit (“PTC”). The ITC may be converted into a cash grant within the first 60 days of operation of the plant. Phase I at San Emidio was completed and in operation in May 2012. An application will be submitted in June 2012 electing to take the ITC cash grant in lieu of the PTC, which will result in a check from the U.S. Treasury for approximately $11 million by August 2012 and will be used to retire an existing bridge loan of approximately $7.5 million.
On May 21, 2012, U.S. Geothermal Inc. (the “Company”) entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, par value $0.001 per share (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof.
Pursuant to the Purchase Agreement, upon the satisfaction of all of the conditions to the Company’s right to commence sales under the Purchase Agreement (the “Commencement”), LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Thereafter, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT LLC exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the Toronto Stock Exchange.
The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares.
As of June 30, 2012, the Company has sold 750,000 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $259,425. Sales of shares of our common stock by our sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE MKT LLC or sales made through a market maker other than on an exchange. Our sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between our sales agent and us.
The Company has entered into an agreement with Kuhns Brothers Securities Corporation (“KBSC”), pursuant to which KBSC agreed to act as the placement agent in connection with the sale of shares of Common Stock to LPC. Subject to the Company’s and KBSC’s receipt of written confirmation that the Corporate Finance Department of Financial Industry Regulatory Authority, Inc. (“FINRA”) has determined not to raise any objection with respect to the fairness or reasonableness of the compensation terms of the Company’s arrangement with KBSC, the Company will pay KBSC the following compensation for its services in acting as placement agent in the sale of Common Stock to LPC: (A) the Company will pay a cash fee to KBSC in an amount equal to: (i) 6% of the aggregate gross proceeds received by the Company from the initial sale of $750,000 in shares of Common Stock to LPC pursuant to the Purchase Agreement, and (ii) 3% of the aggregate gross proceeds received by the Company from additional sales of Common Stock to LPC pursuant to the Purchase Agreement; and (B) the Company will issue to KBSC the number of warrants (the “Compensation Warrants”) equal to: (i) in the case of the initial sale of $750,000 in shares of Common Stock to LPC, 6% of the aggregate number of shares sold to LPC; and (ii) in the case of additional sales of Common Stock to LPC, 3% of the aggregate gross proceeds received by the Company from such sales divided by 115% of the closing sale price of one share of Common Stock on the day prior to the respective issuance of the Compensation Warrant. The Compensation Warrants issued pursuant to clause (ii) in the preceding sentence will be based on incremental sales to LPC of $2 million in aggregate gross proceeds. Each Compensation Warrant will have an exercise price equal to 115% of the closing sale price of one share of Common Stock on the day prior to its issuance, a term of five years from the date of its issuance and will otherwise comply with the rules of FINRA.
On November 14, 2011, U.S. Geothermal Inc. entered into a bridge loan agreement between its wholly owned subsidiary USG Nevada LLC and Ares Capital Corporation. The bridge loan has monetized the Section 1603 ITC cash grant associated with the planned commercial operation of the new Phase I power plant at the San Emidio Geothermal Project, located in Washoe County, Nevada. The loan agreement provides for payment to the Company of approximately 90% of the total expected cash grant and consists of an initial funding of $7.5 million which has been received by the Company. The funds are drawn from a loan facility that includes commercial terms for the payment of interest and associated fees. Once the placed in service date has been achieved, an application will be submitted to the United States Department of the Treasury for an estimated $11 million ITC cash grant. The cash grant proceeds will be used to repay the Ares Capital bridge loan facility with the remaining balance payable to USG Nevada LLC.
On September 30, 2011, U.S. Geothermal Inc., a Delaware corporation (the “Company”), entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with McNicoll, Lewis & Vlak LLC (“MLV”), pursuant to which the Company, from time to time, may issue and sell through MLV, acting as the Company’s sales agent, shares of the Company’s common stock. The Company’s board of directors has authorized the issuance and sale of shares of the Company’s common stock under the Sales Agreement for aggregate gross sales proceeds of up to $10,000,000, subject to certain limitations based on the sales price per share, for a period of one year from the date of execution of the Sales Agreement. Pursuant to the Sales Agreement, MLV will be entitled to compensation at a fixed commission rate of the greater of (i) 3% of the gross sales price per share sold or (ii)(1) $0.03 per share sold if the sale price per share is $0.80 or greater or (2) $0.0225 per share sold if the sale price per share is less than $0.80 (but in no event shall compensation exceed 8% of gross proceeds). The Company has agreed to reimburse a portion of MLV’s expenses in connection with the offering of the Company’s common stock under the Sales Agreement. This agreement was cancelled effective May 19, 2012.
As of May 19, 2012, the Company has sold 241,989 shares of common stock pursuant to the Sales Agreement for net proceeds of approximately $126,133. Sales of shares of our common stock by our sales agent have been made in privately negotiated transactions or in any method permitted by law deemed to be an “At The Market” offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NYSE MKT LLC or sales made through a market maker other than on an exchange. Our sales agent has made all sales using commercially reasonable efforts consistent with its normal sales and trading practices on mutually agreed upon terms between our sales agent and us.
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% 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 was considered to be an equity contribution to the Company’s subsidiary. The conversion occured 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 $8 million was contributed by Enbridge that increased 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% . An additional $6 million cost overrun facility was established by Enbridge to cover costs that resulted from unexpected poor results from injection well drilling. The additional investment by Enbridge will increase their ownership in USG Oregon LLC based on running a project financial model and determine what percentage of the forecasted project income will be allocated to Enbridge to arrive at a predetermine rate of return for the additional investment. Current estimates of the ownership assuming that all of the investment is used for drilling shows that Enbridge could own up to 44% of the subsidiary. The model will be rerun after all of the variables have been fixed which is anticipated to be in the 4th quarter of 2012 to set the final ownership ratios between the two parties.
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 commercial sources.
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, 2012, the following table denotes contractual obligations by payments due for each period:
Total < 1 year 1-3 years 3-5 years > 5 years
Operating Leases $ 383,340 $ 200,626 $ 205,496 $ 186,867 $ 538,749
Capital Leases 14,183 14,183
Bridge Loan 7,500,000 7,500,000
Construction Loan (1) 27,037,642
2,150,000 3,200,000 21,687,642
Construction Loan (2) 31,958,065
2,750,000 4,200,000 25,008,065
Retention payable (3) 8,374,762
675,000 1,000,000 6,699,762
Convertible Loan (4) 2,125,000
2,125,000
(1)
Construction loan with SAIC will be replaced at completion of construction period with long-term financing anticipated through a loan backed by DOE 1705 loan guarantee program. Payout is estimated to occur over a 25 year period.
(2)
Construction loan with the Department of Energy. Payout is estimated to occur over a 22 year period.
(3)
Retention payable will be financed as part of the long-term financing described for the SAIC and DOE loans.
(4)
Loan convertible to project equity in Oregon USG Holdings, LLC (Neal Hot Springs project).
Off Balance Sheet Arrangements
As of March 31, 2012, 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, 2012, 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, 2012. 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, 2012.
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, 2012. 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, 2012, the Company’s internal control over financial reporting is effective based on those criteria.
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, 2012, 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 October 12, 2012. 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 MKT 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 MKT 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 October 12, 2012.
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 October 12, 2012.
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, 2012:
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 October 12, 2012.
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 October 12, 2012.
PART IV
Item 15.
Item 15. Exhibits and 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.
2.
Exhibits. See below.
EXHIBIT INDEX
EXHIBIT
NUMBER EXHIBIT
DESCRIPTION
3.1
Certificate of Incorporation of U.S. Cobalt Inc. (now known as U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.2
Certificate of Domestication of Non-U.S. Corporation (Incorporated by reference to exhibit 3.2 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.3
Certificate of Amendment of Certificate of Incorporation (changing name of U.S. Cobalt Inc. to U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.3 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.4
Second Amended and Restated Bylaws of U.S. Geothermal Inc. (Incorporated by reference to exhibit 3.4 to the registrant’s Form 8-K as filed on October 18, 2010)
3.5
Plan of Merger of U.S. Geothermal Inc. and EverGreen Power Inc. (Incorporated by reference to exhibit 3.5 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.6
Amendment to Plan of Merger (Incorporated by reference to exhibit 3.6 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
3.7
Certificate of Amendment to Certificate of Incorporation filed on August 26, 2008 (incorporated by reference to Exhibit 3.4 to the Company’s Form 8-K as filed on August 27, 2008)
4.1
Form of Stock Certificate (Incorporated by reference to exhibit 4.1 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
4.2
Provisions Regarding Rights of Stockholders (Incorporated by reference to Exhibit 4.3 to the Company’s Form SB-2 registration statement as filed on July 8, 2004)
4.3
Form of Warrant used in private placement of April 2008 (Incorporated by reference to Exhibit 10.3 to the Company’s Form 8-K current report as filed on May 2, 2008)
4.4
Form of Broker Warrant (Incorporated by reference as exhibit 10.4 to the Company’s Form 8-K current report as filed on May 2, 2008)
4.5
Form of Subscription Agreement for Subscription Receipts relating to private placement of August 2009 (Incorporated by reference to Exhibit 4.3 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.6
Subscription Receipt Agreement dated August 17, 2009 among the Company, Dundee Securities Corporation, Clarus Securities Inc., Toll Cross Securities Inc. and Computershare Trust Company of Canada (Incorporated by reference to Exhibit 4.4 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.7
Form of Warrant used in private placement of August 2009 (Incorporated by reference to Exhibit 4.5 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.8
Form Broker Warrant (Incorporated by reference to Exhibit 4.6 to the Company’s Form S-1 registration statement as filed on November 27, 2009)
4.9
Form of Warrant used in March 2011 registered offering (Incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on February 28, 2011)
4.10
Form of Subscription Agreement used in March 2011 registered offering (Incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 28, 2011)
4.11 Form of Compensation Warrant (Incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed on May 22, 2012)
10.1
Geothermal Lease and Agreement dated July 11, 2002, between Sergene Jensen, Personal Representative of the Estate of Harlan B. Jensen, and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.5 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
10.2
Geothermal Lease and Agreement dated June 14, 2002, between Jensen Investments Inc. and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.6 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
10.3
Geothermal Lease and Agreement dated March 1, 2004, between Jay Newbold and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.7 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
10.4
Geothermal Lease and Agreement dated June 28, 2003, between Janice Crank and the children of Paul Crank and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.8 to the registrant’s Form SB-2 registration statement as filed on July 8, 2004)
10.5
Geothermal Lease and Agreement dated December 1, 2004, between Reid S. Stewart and Ruth O. Stewart and US Geothermal Inc. (Incorporated by reference to exhibit 10.9 to the registrant’s Amendment No. 2 to Form SB-2 registration statement as filed on January 10, 2005)
10.6
Geothermal Lease and Agreement, dated July 5, 2005, between Bighorn Mortgage Corporation and US Geothermal Inc. (Incorporated by reference to exhibit 10.11 to the registrant’s Form 10-QSB quarterly report as filed on February 17, 2006)
10.7
Geothermal Lease and Agreement, dated June 23, 2005, among Dale and Ronda Doman, and US Geothermal Inc. (Incorporated by reference to exhibit 10.13 to the registrant’s Form 10-QSB quarterly report as filed on February 17, 2006)
10.8
Geothermal Lease and Agreement, dated June 23, 2005, among 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, and US Geothermal Inc. (Incorporated by reference to exhibit 10.14 to the registrant’s Form 10- QSB quarterly report as filed on February 17, 2006)
10.9
Geothermal Lease and Agreement dated January 25, 2006, between Philip Glover and US Geothermal Inc. (Incorporated by reference to exhibit 10.9 to the registrant’s Form 10-QSB quarterly report as filed on February 17, 2006)
10.10
Geothermal Lease and Agreement, dated May 24, 2006, between JR Land and Livestock Inc. and US Geothermal Inc. (Incorporated by reference to exhibit 10.30 to the registrant’s Form 10-KSB annual report as filed on June 29, 2006)
10.11
Employment Agreement dated September 29, 2011 with Daniel J. Kunz (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on September 30, 2011)
10.12
Employment Agreement dated April 1, 2011 with Kerry D. Hawkley (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on April 6, 2011)
10.13
Employment Agreement dated April 1, 2011 with Douglas J. Glaspey (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on April 6, 2011)
10.14
Amended and Restated Stock Option Plan of U.S. Geothermal Inc. dated September 29, 2006. (Incorporated by reference to exhibit 10.23 to the registrant’s Form SB-2 registration statement as filed on October 2, 2006.)
10.15
Power Purchase Agreement dated December 29, 2004 between U.S. Geothermal Inc. and Idaho Power Company (Incorporated by reference to exhibit 10.19 to the registrant’s Amendment No. 2 to Form SB-2 registration statement as filed on January 10, 2005)
10.16
Engineering, Procurement and Construction Agreement dated December 5, 2005 between U.S. Geothermal Inc. and Ormat Nevada Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form 10-QSB quarterly report as filed on February 17, 2006)
10.17
Amendment to the Engineering, Procurement and Construction Agreement dated April 26, 2006 between U.S. Geothermal Inc. and Ormat Nevada Inc. (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on May 2, 2006)
10.18
At Market Issuance Sales Agreement dated September 30, 2011 between U.S. Geothermal Inc. and McNicoll, Lewis & Vlak LLC (Incorporated by reference to exhibit 1.1 to the registrant’s Form 8-K as filed on September 30, 2011).
10.19
Renewable Energy Credits Purchase and Sales Agreement dated July 29, 2006 between Holy Cross Energy and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form SB-2 as filed on September 29, 2006).
10.20
Transmission Agreement dated June 24, 2005 between Department of Energy’s Bonneville Power Administration - Transmission Business Line and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.27 to the registrant’s Form 10-QSB quarterly report as filed on August 12, 2005)
10.21
Interconnection and Wheeling Agreement dated March 9, 2006 between Raft River Rural Electric Co-op and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.28 to the registrant’s Form 10-KSB annual report as filed on June 29, 2006)
10.22
Construction Contract dated May 16, 2006 between Raft River Rural Electric Co-op and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.31 to the registrant’s Form SB-2 as filed on September 29, 2006).
10.23
Membership Admission Agreement, dated August 9, 2006, among Raft River Energy I LLC, U.S. Geothermal Inc., and Raft River I Holdings, LLC (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on August 23, 2006)
10.24
Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of August 9, 2006, among Raft River Energy I LLC, Raft River I Holdings, LLC and U.S. Geothermal Inc (Incorporated by reference to exhibit 10.2 to the registrant’s Form 8-K as filed on August 23, 2006).
10.25
Management Services Agreement, dated as of August 9, 2006, between Raft River Energy I LLC and U.S. Geothermal Services, LLC (Incorporated by reference to exhibit 10.3 to the registrant’s Form 8-K as filed on August 23, 2006)
10.26
Construction contract dated May 22, 2006 between Industrial Builders and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.31 to the registrant’s Form 10- KSB annual report as filed on June 29, 2006)
10.27
First Amendment to the Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of November 7, 2006, among Raft River Energy I LLC, Raft River I Holdings, LLC and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.36 to the registrant’s Form 10-QSB as filed on February 20, 2007).
10.28
Geothermal Lease and Agreement dated August 1, 2007, between Bureau of Land Management and U.S. Geothermal Inc. (Incorporated by reference as exhibit 10.34 to the registrant’s Form S-1 as filed on March 26, 2010)
10.29
Asset Purchase Agreement dated as of March 31, 2008, between U.S. Geothermal Inc., and Empire Geothermal Power LLC and Michael B. Stewart (Incorporated by reference as exhibit 99.1 to the registrant’s Form 8-K current report as filed on April 7, 2008)
10.30
Water Rights Purchase Agreement Michael B. Stewart and U.S. Geothermal Inc. dated March 31, 2008 (Incorporated by reference as exhibit 99.2 to the registrants Form 8-K current report as filed on April 7, 2008).
10.31
Power Purchase Agreement dated as of December 11, 2009, between Idaho Power Company and USG Oregon LLC (Incorporated by reference to Exhibit 10.43 to the Company’s Form 10-Q quarterly report as filed on February 9, 2010)
10.32
Amended and Restated Long-Term Portfolio Energy Credit and Renewable Power Purchase Agreement dated May 31, 2011 between Sierra Pacific Power Company d/b/a NV Energy, and USG Nevada LLC (Incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on January 4, 2012)
10.33
Long Term Agreement For the Purchase and Sale of Electricity, dated December 31, 1986, between Sierra Pacific Power Company and Empire Farms, as amended (Incorporated by reference to Exhibit 10.43 to the registrant’s Form 10-Q/A quarterly report as filed on March 3, 2010)
10.34
Engineering, Procurement and Construction Contract, dated as of August 27, 2010, between USG Nevada LLC and Benham Constructors LLC August 27, 2010. (Incorporated by reference to exhibit 99.1 to the registrant’s Form 8-K as filed on November 8, 2010) *
10.35
Amended and Restated Change in Control Guaranty made and entered into as of October 13, 2010, by U.S. Geothermal Inc., in favor of Benham Constructors, LLC. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on November 8, 2010)
10.36
Credit Addendum to Engineering, Procurement and Construction Contract, dated as of August 27, 2010, between USG Nevada LLC and Benham Constructors LLC August 27, 2010. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on November 8, 2010)
10.37
Amended and Restated Limited Liability Company Agreement made and entered into as of September 7, 2010, by and among Oregon USG Holdings LLC, U.S. Geothermal Inc., and Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on November 8, 2010) *
10.38
Conditional Guaranty Agreement, entered into as of September 7, 2010, by US Geothermal Inc. to Enbridge (U.S.) Inc. (Incorporated by reference to exhibit 99.5 to the registrant’s Form 8-K as filed on November 8, 2010)
10.39
2009 Stock Incentive Plan of the Registrant (Incorporated by reference to Appendix A to the Company’s definitive proxy statement on Schedule 14A as filed on November 6, 2009)**
10.40 Loan Guarantee Agreement dated as of February 23, 2011, among USG Oregon LLC, U.S. Department of Energy, and PNC Bank N.A. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on August 31, 2011)
10.41 Equity Pledge Agreement dated as of February 23, 2011, among Oregon USG Holdings LLC, USG Oregon LLC, and PNC Bank, N.A. (Incorporated by reference to exhibit 99.3 to the registrant’s Form 8-K as filed on August 31, 2011)
10.42 Future Advance Promissory Note dated February 23, 2011, among USG Oregon LLC and Federal Financing Bank (Incorporated by reference to exhibit 99.4 to the registrant’s Form 8-K as filed on August 31, 2011)
10.43 Note Purchase Agreement dated as of February 23, 2011 among the Federal Financing Bank, USG Oregon LLC, and the Secretary of Energy, acting though the Department of Energy (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on September 15, 2011)
10.44 Financing Agreement dated November 9, 2011, between USG Nevada LLC and Ares Capital Corporation (incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on November 16, 2011)
10.45 Purchase Agreement dated May 21, 2012, between U.S. Geothermal Inc. and Lincoln Park Capital Fund, LLC ( incorporated by reference to Exhibit 10.1 to the Registrant’s From 8-K as filed on May 22, 2012)
13.1 Audited Consolidated Financial Statements of U.S. Geothermal Inc. as of March 31, 2012.
21.1 Subsidiaries of the Registrant
23.1 Consent of MartinelliMick, PLLC
23.2 Consent of GeothermEx Inc.
23.3 Consent of Black Mountain Technology, Inc.
23.4 Consent of Geothermal Science, Inc.
31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1 Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*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)
July 13, 2012
/s/ Daniel J. Kunz
Date
Daniel J. Kunz
Chief Executive Officer
(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:
Name
Title Date
Chief Executive Office and Director (Principal
/s/ Daniel J. Kunz
Executive Officer) July 13, 2012
Daniel J. Kunz
Chief Financial Officer (Principal Financial and
/s/ Kerry Hawkley
Accounting Officer) July 13, 2012
Kerry Hawkley
/s/ Douglas J. Glaspey
President, Chief Operating Officer and Director July 13, 2012
Douglas J. Glaspey
/s/ John H. Walker
Chairman and Director July 13, 2012
John H. Walker
/s/ Paul A. Larkin
Director July 13, 2012
Paul A. Larkin
/s/ Leland L. Mink
Director July 13, 2012
Leland R. Mink