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US GEOTHERMAL INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) 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: º our business and growth strategies; º our future results of operations; º anticipated trends in our business; º the capacity and utilization of our geothermal resources; º our ability to successfully and economically explore for and develop geothermal resources; º our exploration and development prospects, projects and programs, including timing and cost of construction of new projects and expansion of existing projects; º availability and costs of drilling rigs and field services; º our liquidity and ability to finance our exploration and development activities; º our working capital requirements and availability; º our illustrative plant economics; º market conditions in the geothermal energy industry; and º 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: º the failure to obtain sufficient capital resources to fund our operations; º unsuccessful construction and expansion activities, including delays or cancellations; º incorrect estimates of required capital expenditures; º increases in the cost of drilling and completion, or other costs of production and operations; º the enforceability of the power purchase agreements for our projects; º impact of environmental and other governmental regulation, including delays in obtaining permits or ongoing impacts of the sequester; º hazardous and risky operations relating to the development of geothermal energy; º our ability to successfully identify and integrate acquisitions; -36- -------------------------------------------------------------------------------- º the failure of the geothermal resource to support the anticipated power capacity; º our dependence on key personnel; º the potential for claims arising from geothermal plant operations; º general competitive conditions within the geothermal energy industry; and º 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. All references to "dollars" or "$" are to United States dollars. General Background and Discussion The following discussion should be read in conjunction with our unaudited consolidated financial statements for the quarter ended June 30, 2014 and notes thereto included in this report. U.S. Geothermal Inc. ("the Company") is a Delaware corporation. The Company's common stock trades on the NYSE MKT LLC under the trade symbol "HTM" and on the Toronto Stock Exchange under the symbol "GTH". For the quarter ended June 30, 2014, the Company was focused on: 1) Operating and optimizing Neal Hot Springs, San Emidio and Raft River power plants; 2) Evaluating drill results, leasing additional lands, and planning new drilling at El Ceibillo; 3) Permitting new wells and drilling at San Emidio for Phase II; 4) Completing acquisition of the WGP Geysers project; and 5) Evaluating potential new geothermal projects and acquisition opportunities. Project Overview 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 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. -37- -------------------------------------------------------------------------------- Projects in Operation Generating Contract Project Location Ownership Capacity Power Expiration (megawatts) Purchaser Raft River (Unit I) Idaho JV(2) 13.0(1) Idaho 2032 Power San Emidio (Unit I) Nevada 100% 9.0 Sierra 2038 Pacific Neal Hot Springs Oregon JV(3) 22.0 Idaho 2036 Power (1) Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently is approximately 10.0 megawatts annual average. (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 $1.4 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) 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"). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. Enbridge's equity interest in the project is 40%. Projects Under Development Estimated Target Projected Capital Development Commercial Required Project Location Ownership (Megawatts) Operation ($million) Power Purchaser Date El Ceibillo Phase I Guatemala 100% 25 3rd $135 MOU Quarter 2016 San Emidio Phase II Nevada 100% 11 4th $66 TBD Quarter 2016 WGP Geysers California 100% 26 TBD TBD TBD Additional Properties Project Location Ownership Target Development (Megawatts) Gerlach Nevada 60% TBD Granite Creek Nevada 100% TBD El Ceibillo Phase II Guatemala 100% 25 San Emidio Phase III Nevada 100% 17.2 Neal Hot Springs II Oregon 100% 28 Raft River Unit II Idaho 100% 26 Raft River Unit III Idaho 100% 32 Vale Butte Oregon 100% TBD Resource Details Property Size Property (square miles) Temperature (ºF) Depth (Ft) Technology Raft River 10.8 275-302 4,500-6,000 Binary WGP Geysers 6.0 500 6,000-10,000 Steam San Emidio 35.8 289-316 1,500-3,000 Binary Neal Hot Springs 9.6 311-347 2,500-3,000 Binary Gerlach 5.6 338-352 2,000-3,000 Binary Granite Creek 3.8 TBD TBD Binary El Ceibillo 38.6 410-526 1,800-TBD Steam Vale Butte 0.6 290-300 TBD Binary Neal Hot Springs, Oregon Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. The Neal Hot Springs facility is designed as a 22 megawatt net annual average power plant, consisting of three separate, 7.33 net megawatt modules. The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the second quarter of 2014 totaled 40,629 megawatt-hours with an average of 20.34 net megawatts per hour of operation. Plant availability was 91.4% during the quarter. Our planned annual maintenance outages were taken during the quarter with each Unit going through their respective maintenance schedules while the other two units remained in operation. A total of 453 hours (18.9 days) of scheduled maintenance were taken in April and May. Plant availability exclusive of the scheduled maintenance was 98.3% -38- -------------------------------------------------------------------------------- On June 27, 2013, the Company accepted substantial completion by the EPC contractor of all three of the Neal Hot Springs units. Final completion of the project was achieved on July 31, 2013. The DOE loan for the project was closed at final completion with a balance of $70.4 million that bears an interest rate of 2.598% over a 22 year term. The total construction cost of the project was $128.1 million, plus an additional $11.2 million is held in various project reserve accounts. In February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal received an approximate $6.2 million cash distribution from the partnership. The first cash distribution of profits was made from the project in March, and U.S. Geothermal received $4.6 million. Under the terms of the U.S. Department of Energy loan agreement, profits from the project are distributed to the equity partners semi-annually (February and August). 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 average price for the year 2012 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. Power generated during 2013 was paid at an average price of $99.00 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.3% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $102.78 per megawatt-hour. San Emidio, Nevada The Phase I power plant at San Emidio is located approximately 100 miles north-east of Reno, Nevada near the town of Gerlach, and achieved commercial operation on May 25, 2012. Generation from the facility during the second quarter 2014 totaled 15,686 megawatt-hours, with an average of 9.18 net megawatts per hour of operation. Plant availability was 78.2% during the quarter due to an extended maintenance outage that was required to perform a one-time warranty modification to the turbine that added a squeeze film dampener, or 5th bearing to the unit to minimize vibration over the life of the turbine. The same squeeze film dampener bearings were also previously added successfully to the three units at Neal Hot Springs in 2013. A total of 439 hours (18.3 days) of scheduled maintenance was taken during the quarter. Plant availability exclusive of scheduled maintenance was 97.9% The Phase I plant completed its capacity testing during the first quarter of 2013, and as a result of the capacity test exceeding the design output, the plant was up-rated to 9.0 megawatt net annual average per hour from the design point basis of 8.6 megawatts. Substantial Completion under the Engineering Procurement and Construction ("EPC) contract with SAIC was achieved February 21, 2013 and Final Completion under the terms of the EPC was executed on June 24, 2013. Upon Substantial Completion, SAIC held a construction loan on the project with a balance of $27 million, which was divided into a $25 million loan (which has been paid in full) and a $2 million unsecured loan with a 5 year term at 7% interest which is being paid down with quarterly payments of $119,382. The $25 million construction loan held by SAIC was paid off in September of 2013, and was replaced with long term notes purchased by Prudential Capital Group's related entities. The Prudential notes are for an aggregate of approximately $30.74 million, have a term of approximately 24 years, and bear a fixed interest rate of 6.75% per annum. 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 was approved by the Public Utility Commission of Nevada on December 27, 2011. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate. Power generated during 2013 was paid at the price of $90.27 per megawatt-hour. The average price paid under the PPA for 2014 has increased to $91.17 per megawatt-hour. -39- -------------------------------------------------------------------------------- As a result of the delays experienced in permitting additional wells on BLM administered leases, it has been determined that it is not possible to complete the development of the Phase II project within the development time frame required in the existing 19.9 megawatt NV Energy PPA. The Phase II expansion is dependent on successful development of additional production and injection well capacity. The cost of development for Phase II is estimated at approximately $66 million. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing. A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. An application to increase the interconnection agreement to the full 19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9, 2014. 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 first stage of the DOE project 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 and was completed in 2011. 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, a South Zone and a North Zone. The second stage of the DOE program is a 50-50 cost shared drilling plan that is intended to follow up on targets identified in the first stage. Drilling started in the South Zone, and two wells were completed by the Company. After approval of the drilling program by the DOE in November 2011, one of the first two wells was deepened and three additional wells were completed in the South Zone with the costs being shared on a 50-50 basis. Permitting was initiated with the Bureau of Land Management ("BLM") for four new observation wells to be drilled in the South Zone to follow up on the high temperatures found in wells 61-21 (302°F) and 45-21 (316°F). As part of the permitting process, cultural and biological surveys were performed, and the well design and drilling program were submitted during the quarter. Permits for three wells were issued by the BLM on April 29th and a drill rig was mobilized to the site on June 26th. Subsequent to the end of the quarter, the first well (OW-14) was completed. Well 61-21 (formerly OW-10) in the South Zone, was reworked beginning on October 25, 2013 and was completed on November 2, 2013. Flow testing of 61-21 was completed subsequent to the end of the quarter. To allow early for early long term testing of this southern resource area, a cross tie is being constructed between the two project area, Construction of the cross tie pipeline has been started, and once complete well 61-21 will be connected into the existing plant. Well 61-21 is expected to start delivering fluid to the plant during the third quarter. In the North Zone, well OW-12 was drilled during the fourth quarter of 2013 to a depth of 3,643 feet and found a bottomhole temperature of approximately 180°F. No additional drilling is currently planned for the North Zone. Raft River, Idaho The Raft River project is located in Southern Idaho, near the town of Malta, and achieved commercial operation in January 2008. Generation from the facility during the second quarter 2014 totaled 18,069 megawatt-hours, with an average of 8.78 net megawatts per hour of operation. Plant availability was 94.0% during the quarter. Second quarter availability was impacted by 108 hours of annual scheduled maintenance, with availability for the balance of the quarter at 99.1% . -40- -------------------------------------------------------------------------------- The PPA for the project was signed on September 24, 2007 with the Idaho Power Company. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year. Power generated during 2013 was paid at an average price of $59.47 per megawatt-hour. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In addition to the price paid for energy by Idaho Power, Raft River currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits to Holy Cross Energy, a Colorado electric cooperative. The project was awarded an $11.4 million cost-shared, thermal fracturing program grant from the Department of Energy, which began the first stage of injection in June 2013 and continued until September 2013 when the second stage was started. Four, 300 foot deep seismic monitoring wells were completed in the area around well RRG-9 and seismic geophones were installed. Seismic monitoring will be conducted for the duration of the thermal fracturing program. Injection continued through the quarter from power plant injectate at an approximate temperature of 140°F. Flow in to the well has seen a moderate increase indicating that additional permeability was developing. In early April, high pressure injection of brine into the well was initiated over two days with injection pressures of 850 to 1000 pounds at the well head. There has been an approximate 100% increase in the amount of fluid well RRG-9 is now taking, with injection of spent brine continuing through the quarter. If the fracturing program is successful, and permeability is improved to a commercial level, well RRG-9 may be utilized as a production or injection well for the existing Raft River power plant. The Company's contributions for the thermal fracturing program are made in-kind by the use of the RRG-9 well, well field data, and monitoring support. 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 2010. The concession has a 5 year term for the development and construction of a power plant. Discussions are being held with the Guatemalan Ministry of Energy and Mines to support a new schedule based on the current status of the project. There are 24,710 acres (100 square kilometers) in the concession which is at the center of the Aqua and Pacaya twin volcano complex. We have also applied to the Guatemalan Ministry of Energy for an extension to our lease concession, and expect approval shortly. An office and staff are located in Guatemala City and a 17 acre plant site has been leased on land adjacent to the existing wells. A new lease was negotiated during the quarter for an additional 80 acres, bringing the total surface lease positon to 97 acres. Several parties have expressed interest in the potential purchase of an equity interest in the El Ceibillo project. El Ceibillo, the first development target on the concession, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast. An initial development of a 25 megawatt (Phase I) power plant is planned in the El Ceibillo area of the concession, but the final size of the facility will be determined after drilling and resource delineation has advanced. Initial transmission studies have been completed, and identified the grid interconnection point approximately 1.2 miles (2 kilometers) from the site. A temperature gradient ("TG") drilling program was initiated during the first quarter of 2014 with a series of 656 foot (200 meter) deep wells planned. Nine TG wells have been completed with depths ranging from 656 to 1,312 feet (200 to 400 meters). Bottom hole temperatures found in this shallow drilling program range from 176 to 413°F (80 to 211°C) with two of the wells encountering permeability and flowing brine. The data from these wells provided a more accurate temperature gradient map of the underlying geothermal resource which has assisted in identifying future drilling targets. -41- -------------------------------------------------------------------------------- A first phase of drilling took place during the third quarter of 2013 when well EC-1 was drilled to a depth of 4,829 feet (1,472 meters) and encountered a bottom hole temperature of 491°F (255°C), with the temperature gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet (129.1°C/km) . High temperatures in excess of 392°F (>200°C) were encountered in the well beginning at a depth of 2,625 feet (800 meters), which represents a potential high temperature reservoir interval in excess of 2,204 feet (672 meters) thick. Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well. The final depth of the well is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of 526°F (274°C). Clean out and short term flow tests were conducted along with temperature surveys and have been incorporated in the geologic model of the reservoir. In early September 2013, the Guatemalan Ministry of the Environment and Natural Resources ("MARN") issued the Environmental License for the construction and operation of the planned, first phase, 25 megawatt power plant at the El Ceibillo site. The license is based on the Environmental Impact Assessment Study that was submitted in December 2012, describing the initial design of the 25 megawatt facility, and requires the submittal of final design specifications for review by MARN prior to starting physical construction of the plant. Additionally, the license requires compliance with all legal and regulatory requirements under Guatemalan law, submittal of an air quality monitoring plan, and that final design comply with the strict guidelines for noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an environmental bond of Q344,850 Quetzals (approximately US $45,000) was posted with the Ministry of Environment and Natural Resources. A binding Memorandum of Understanding ("MOU") was signed on October 18, 2012 with one of the largest power brokers in Central America. The MOU establishes the framework for a PPA that includes a 15-year term for an initially estimated 25 megawatts of power generation up to a maximum of 50 megawatts of power generation. The MOU includes a project power price that the Company believes is competitive with the prevailing energy prices in the region. Several conditions precedent must be met before the PPA is negotiated and becomes effective, including confirming the geothermal reservoir by an independent reservoir engineer, obtaining all required permits and authorizations, and securing a project finance commitment. The MOU may be terminated (i) as a result of the bankruptcy of any of the parties, (ii) on January 1, 2015, unless such date is extended by mutual agreement, because the construction of the project has not been initiated and/or the commercial operation date has been moved beyond the date set out in the PPA framework, or (iii) if the geothermal resource found lacks the conditions to sustain a long-term commercial production that allows electric power to be produced under the necessary conditions of profitability. The El Ceibillo geothermal project area had nine previous wells drilled into the geothermal concession during the 1990s which have depths ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had adequate flow and temperature to support a direct use application. Six of the wells had measured reservoir temperatures in the range of 365°F to 400°F and had high conductive gradients that indicated rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicated the existence of a high permeability reservoir below or near the existing well field. WGP Geysers The WGP Geysers project is located in the broader Geysers geothermal field located approximately 75 miles north of San Francisco, California. The broader Geysers geothermal field is the largest producing geothermal field in the world generating more than 850 megawatts of power for more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was completed on April 22, 2014 for $6.4 million. -42- -------------------------------------------------------------------------------- WGP Geysers is an advanced stage project that encompasses the former Pacific Gas and Electric Unit 15, which once had a 62 megawatt (gross) capacity geothermal power plant that was shut down in l989. The project includes 3,809 acres of geothermal leases and property, development design plans, and permits for a proposed 26 (net) megawatt power plant. There are four existing wells drilled in 2008-2009 which are immediately available for production or injection, with a fifth, historic well that has temporary plugs installed but can be reworked. The four new wells have been tested with an initial steam flow totaling 462,000 pounds per hour. A report prepared in 2012 by GeothermEx, a third party reservoir engineering firm, states that the total initial power capacity from these wells is estimated at about 30 megawatts (gross). The report further estimated that the sustainable long-term production from the resource is conservatively estimated at 26 megawatts (net) assuming 25% of the geothermal fluid that is withdrawn is injected back into the reservoir. A 12 month extension for the Sonoma County Conditional Use Permit to construct the 26 megawatt power plant was applied for and was approved on June 12th. Additionally, an application was made to the Sonoma County Air Quality Board for a permit to conduct flow tests on the four production wells drilled in 2009. The Air Quality permit was approved on June 19th. Two development scenarios are under consideration for the WGP Geysers site, either a power sales or a steam sale agreement. The evaluation of these two options is underway and discussion with potential off takers is expected to begin during the third quarter. 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, 2011. 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. Drilling to intersect a previously identified lost circulation target at 1,600 feet deep resumed on well 18-10a on April 14, 2012 and was stopped on April 18, 2012 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. A plan and budget has been developed to deepen well 18-10a to intersect the lost circulation zone at 2,800 feet deep to provide temperature information on the deep structure. Further work is dependent upon additional funding from the partners. 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). -43--------------------------------------------------------------------------------- Operating Results For the six months ended June 30, 2014, the Company reported net income attributable to the Company of $186,607 ($0.00 income per share) which represented a $174,442 increase from net income of $12,165 reported in the same period in 2013 ($0.00 loss per share). For the three months ended June 30, 2014, the Company reported a net loss attributable to the Company of $1,152,813 ($0.01 loss per share) which represented a favorable decrease of $223,546 from the net loss of $1,376,359 reported in the same period in 2013 ($0.01 loss per share). Generally, favorable variances were reported related to the operations of the Company's three power plants. Notable favorable variances were reported in professional and management fees, salaries and wages, and exploration costs. Notable unfavorable variances were reported in stock based compensation and interest expense. Plant Operations During the six months ended June 30, 2014, the Company's energy production revenues and related operating costs originated from its three fully operational power plants. The San Emidio plant (USG Nevada LLC) is located in the San Emidio Desert in the northwestern 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 May 2012. The Raft River plant (Raft River Energy I LLC) is located in South Eastern Idaho. The Raft River plant began operations in January of 2008. The new plant at Neal Hot Springs, Oregon (USG Oregon LLC) is located by Vale, Oregon and began commercial operations on November 16, 2012. Overall, plant production for the second quarter 2014 was down from the first quarter 2014 due to down time for scheduled maintenance. Also, the contracted energy rates are lower in the second quarter for two power plants. The Neal Hot Springs and the Raft River plants earn 73.5% of the contracted rate in the months of March through May. A summary of energy sales by plant location for the two reporting periods are as follows: For the Six Months Ended June 30, 2014 2013 $ % $ % Energy sales by plant: Neal Hot Springs, Oregon 8,668,773 61.2 6,632,554 55.8 San Emidio, Nevada 3,385,617 23.9 3,355,309 28.3 Raft River, Idaho 2,106,744 14.9 1,887,635 15.9 14,161,134 100.0 11,875,498 100.0 % - represents the percentage of total Company energy sales. For the Three Months Ended June 30, 2014 2013 $ % $ % Energy sales by plant: Neal Hot Springs, Oregon 3,402,318 59.1 2,435,303 49.9 San Emidio, Nevada 1,450,525 25.2 1,628,382 33.3 Raft River, Idaho 907,194 15.7 823,154 16.8 5,760,037 100.0 4,886,839 100.0 % - represents the percentage of total Company energy sales. -44--------------------------------------------------------------------------------- A quarterly summary of megawatt hours generated by plant are as follows: For the Quarter Ended, June 30, September 30, December 31, March 31, June 30, 2013 2013 2013 2014 2014 Neal Hot Spring, 30,016 25,832 53,445 56,047 40,629 Oregon San Emidio, Nevada 18,039 18,317 21,112 21,223 15,686 Raft River, Idaho 17,248 18,687 21,951 21,614 18,069 65,303 62,836 96,508 98,884 74,384 Neal Hot Springs, Oregon (USG Oregon LLC) Plant Operations The Neal Hot Springs plant was considered to be commercially operational on November 16, 2012. The quarter ended March 31, 2013, was the plant's first full quarter of operations. For the six months ended June 30, 2014, plant energy revenues increased 30.7% (39.7% for the three months ended June 30, 2014) from the same period ended 2013. In April 2014, the plant completed its scheduled maintenance shutdown. A total of 400.5 hours of production was lost during the shutdown which was significantly less than experienced in 2013. Due to issues related to startup in 2013, the plant suffered down time of 490 hours in the first quarter of 2013 and 927 hours in the second quarter of 2013. Plant operating costs increased $801,645 ($341,688 for the three months ended June 30, 2014), which was a 29.5% increase (24.4% increase for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. The largest variances were noted in administrative support, insurance, and plant and well field maintenance costs. For the six months ended June 30, 2014 administrative and corporate support costs increased $154,230 ($51,751 for the three months ended June 30, 2014), which was a 65.6% increase (41.2% increase for the three months ended June 30, 2014) from the same period in 2013. Effective 2014, a contracted monthly corporate support fee of $13,750 was established. Additional consulting fees related to the general plant maintenance that amounted to over $38,000 for the six months ended June 30, 2014. For the six months ended June 30, 2014, the plant's insurance costs totaled $209,500 ($104,692 for the three months ended June 30, 2014), which was an increase of $193,660 ($95,818 for the three months ended June 30, 2014) from the same period in 2013. In July 2013, the plant's insurance coverage transferred from a builders' risk policy to a full property coverage policy which resulted in a significant increase in cost. Plant and field maintenance costs increased $263,878 ($193,308 for the three months ended June 30, 2014), which was a 213.4% increase (242.9 % for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. In July 2013, the plant's Engineering, Procurement and Construction Company turned over plant maintenance responsibilities to the Company; therefore, most of the repair costs incurred after June 30, 2013, were not covered under warranty. -45--------------------------------------------------------------------------------- Summarized statements of operations for the Neal Hot Springs, Oregon plant are as follows: Six Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 8,668,772 100.0 6,632,554 100.0 2,036,218 30.7 Plant expenses: General operations 1,884,945 21.7 1,127,596 17.0 (757,349 ) (67.2 ) Depreciation and 1,638,029 18.9 1,593,733 24.0 (44,296 ) (2.8 ) amortization 3,522,974 40.6 2,721,329 41.0 (801,645 ) (29.5 ) Operating 5,145,798 59.4 3,911,225 59.0 1,234,573 31.6 income Other income (expense): Interest expense (890,227 ) (10.3 ) (982,213 ) (14.8 ) 91,986 9.4 Other and interest 11,182 0.1 14,394 0.2 (3,212 ) (22.3 ) income (879,045 ) (10.2 ) (967,819 ) (14.6 ) 88,774 (9.2 ) Net 4,266,753 49.2 2,943,406 44.4 1,323,347 45.0 income % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary's operations. Three Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 3,402,318 100.0 2,435,303 100.0 967,015 39.7 Plant expenses: General operations 944,950 27.8 609,354 25.1 (335,596 ) (55.1 ) Depreciation and 820,526 24.1 814,434 33.4 (6,092 ) (0.7 ) amortization 1,765,476 20.4 1,423,788 58.5 (341,688 ) (24.0 ) Operating 1,636,842 48.1 1,011,515 41.5 625,327 61.8 income Other income (expense): Interest expense (444,895 ) (13.0 ) (502,111 ) (20.6 ) 57,216 11.4 Other and interest 4,457 0.1 9,352 0.4 (4,895 ) (52.3 ) income (440,438 ) (12.9 ) (492,759 ) (20.2 ) 52,321 10.6 Net 1,196,404 35.2 518,756 21.3 677,648 130.6 income % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary's operations. -46- -------------------------------------------------------------------------------- Key quarterly production data for the Neal Hot Springs, Oregon plant is summarized as follows: Mega- Ave. Rate Depreciation watt Energy per & Hours Sales Megawatt Net Income* Amortization Quarter Ended: Produced ($) Hour ($) ($) ($) December 31, 2012 23,256 2,329,030 88.7 1,451,523 256,670 March 31, 2013 46,137 4,197,252 90.6 2,424,648 779,299 June 30, 2013 30,016 2,435,304 80.2 518,754 814,434 September 30, 2013 25,832 2,875,686 110.9 829,374 810,573 December 31, 2013 53,445 6,058,169 113.3 3,644,359 812,766 March 31, 2014 56,047 5,266,454 93.8 3,070,350 817,503 June 30, 2014 40,629 3,402,318 83.7 1,196,404 820,526 * - The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary's net income. San Emidio, Nevada Plant Energy Sales and Plant Operating Expenses (USG Nevada LLC) For the six months ended June 30, 2014, the San Emidio plant reported net income of $219,927 which was a decrease of $402,277 (64.7% decrease) from the $622,204 in net income reported in the same period in 2013. For the three months ended June 30, 2014, the San Emidio plant reported a net loss of $203,424 which was a favorable decrease of $8,637 (4.1% decrease) from the $212,061 net loss reported in the same quarter in 2013. During the current quarter, the plant produced 15,686 megawatt hours, which was 13.0% lower than produced in the same quarter in 2013. In April 2014, the plant completed its annual scheduled maintenance shut down. A total of 415 hours of production was lost during the shutdown, which was more than 265 hours (176.7% increase) needed for the shutdown in April 2013. In the current quarter, additional time was needed to install a squeeze film dampener that will reduce the vibration on the turbine. Overall, the total plant operating costs for the current six months ended June 30, 2014 were consistent with the total costs incurred in the same period ended 2013. For the six months ended June 30, 2014, the plant's interest expense increased $410,430 (66.0% increase) from the same period ended 2013. During the quarter ended March 31, 2013, the plant loan had not been finalized and most of the interest incurred under the contractor's obligations was capitalized. In the three months ended June 30, 2013, the plant incurred interest costs that totaled $621,712. In the three months ended March 31 and June 30, 2014, the plant incurred interest expense of $517,406 and $514,859; respectively. -47--------------------------------------------------------------------------------- Summarized statements of operations for the San Emidio, Nevada plant are as follows: Six Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 3,385,617 100.0 3,355,309 100.0 30,308 0.9 Plant expenses: Operations 1,504,312 44.4 1,338,916 39.9 (165,396 ) (12.4 ) Depreciation and 629,190 18.6 772,374 23.0 143,184 18.5 amortization 2,133,502 63.0 2,111,290 62.9 (22,212 ) (1.1 ) Operating 1,252,115 37.0 1,244,019 37.1 8,096 0.7 income Other income (expense): Interest expense (1,032,265 ) (30.5 ) (621,835 ) (18.5 ) (410,430 ) (66.0 ) Other income 77 0.0 20 0.0 57 285.0 (1,032,188 ) (30.5 ) (621,815 ) (18.5 ) (410,373 ) (66.0 ) Net 219,927 6.5 622,204 18.6 (402,277 ) (64.7 ) income % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary's net operating income/loss. Three Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 1,450,525 100.0 1,628,382 100.0 (177,856 ) (10.9 ) Plant expenses: Operations 822,884 56.7 853,425 52.4 30,541 3.6 Depreciation and 316,283 21.8 365,314 22.4 49,031 13.4 amortization 1,139,167 99.2 1,218,739 74.8 79,572 6.5 Operating 311,358 78.5 409,643 25.2 (98,285 ) (24.0 ) income Other income (expense): Interest expense (514,859 ) (35.5 ) (621,712 ) (38.2 ) 106,853 17.2 Other income 77 0.0 8 0.0 69 # (514,782 ) (35.5 ) (621,704 ) (38.2 ) 106,922 17.2 Net (203,424 ) (14.0 ) (212,061 ) (13.0 ) 8,637 (4.1 ) income % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary's net operating income/loss. -48--------------------------------------------------------------------------------- Key quarterly production data for the San Emidio, Nevada plant is summarized as follows: Mega- Ave. Rate Depreciation watt Energy per Net Income & Hours Sales Megawatt (Loss)* Amortization Quarter Ended: Produced ($) Hour ($) ($) ($) June 30, 2012 (1) 5,465 427,931 77.6 (8,693 ) 181,333 September 30, 2012 8,280 745,494 89.7 101,154 253,429 December 31, 2012 16,231 1,459,078 90.0 (223,412 ) 416,091 March 31, 2013 19,228 1,726,927 90.3 834,266 407,060 June 30, 2013 18,039 1,628,382 90.3 (212,058 ) 365,314 September 30, 2013 18,317 1,531,260 83.6 355,499 307,854 December 31, 2013 21,112 1,905,813 90.3 180,931 312,273 March 31, 2014 21,223 1,935,091 91.2 423,351 312,908 June 30, 2014 15,686 1,450,526 92.5 (203,424 ) 316,283 (1) - The new power plant became commercially operational on May 25, 2012. The plant produced power at a lower "test rate" in May and at the full contract rate of .08975 per kilowatt hour in June. * - The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary's net income/loss. Raft River, Idaho Unit I (Raft River Energy I LLC) Plant Operations The net loss from Raft River Energy I LLC ("RREI") operations of $517,819 for the six months ended June 30, 2014, favorably decreased by $116,970 (18.4% decrease) from the net loss for the same period ended in 2013. The net loss of $579,568 for the three months ended June 30, 2014, favorably decreased by $136,035 (19.0% decrease) from the net loss for the same quarter ended in 2013. During the current quarter, the plant produced 18,069 megawatt hours, which was 4.8% lower than produced in the same quarter in 2013. In April 2014, the plant completed its annual scheduled maintenance shutdown. A total of 108 hours of production was lost during the shutdown, which was 128 hours (54.3% fewer hours) less than the hours needed for the April 2013 scheduled shutdown. In April 2013, additional repairs were needed for the circulation water pumps. Total plant operating costs increased $124,398 ($112,680 for the three months ended June 30, 2014), which was a 4.7% increase (16.9% for the three months ended June 30, 2014) for the six months ended June 30, 2014 from the same period ended 2013. For the current quarter, plant and field maintenance costs were reasonably consistent with the maintenance costs incurred in 2013. In the quarter ended March 31, 2013, RREI offset repair costs with proceeds received from grants related to well repairs that amounted to $217,594. These repairs of wells RRG-2 and RRG-7 were completed in January 2012. -49--------------------------------------------------------------------------------- The summarized statements of operations for RREI are as follows: Six Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 2,106,745 91.9 1,887,635 91.1 219,110 11.6 Energy credit sales 186,705 8.1 184,566 8.9 2,139 1.2 2,293,450 100.0 2,072,201 100.0 221,249 10.7 Plant expenses: General operations 1,895,921 82.7 1,683,476 81.2 (212,445 ) (12.6 ) Depreciation and 856,087 37.3 944,134 45.6 88,047 9.3 amortization 2,752,008 120.0 2,627,610 126.8 (124,398 ) (4.7 ) Operating (458,558 ) (20.0 ) (555,409 ) (26.8 ) 96,851 17.4 income Other income (expense): Interest expense (59,728 ) (2.6 ) (93,001 ) (4.5 ) 33,273 35.8 Other and interest 467 0.0 13,621 0.7 (13,154 ) 996.6 ) income (59,261 ) (2.6 ) (79,380 ) (3.8 ) 20,119 25.3 Net income (517,819 ) (22.6 ) (634,789 ) (30.6 ) 116,970 (18.4 ) % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary's operations. -50- -------------------------------------------------------------------------------- Three Months Ended June 30, 2014 2013 Variance $ % $ % $ %* Plant revenues: Energy sales 907,194 91.4 823,154 90.5 84,040 10.2 Energy credit sales 85,837 8.6 86,237 9.5 (400 ) (0.5 ) 993,031 100.0 909,391 100.0 83,640 9.2 Plant expenses: General operations 1,118,614 112.6 1,103,739 121.4 (14,875 ) (1.3 ) Depreciation and 428,180 43.1 472,094 51.9 43,914 9.3 amortization 1,546,794 155.7 1,575,833 173.3 29,039 1.8 Operating (553,763 ) (55.7 ) (666,442 ) (73.3 ) 112,679 16.9 income Other income (expense): Interest expense (26,009 ) (2.6 ) (49,370 ) (5.4 ) 23,361 47.3 Other and interest 204 0.0 210 0.0 (6 ) (2.9 ) income (25,805 ) (2.6 ) (49,160 ) (5.4 ) 23,355 47.5 Net income (579,568 ) (58.3 ) (715,602 ) (78.7 ) 136,034 19.0 % - represents the percentage of total plant operating revenues. %* - represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures. The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary's operations. Key quarterly production data for RREI is summarized as follows: Mega- Ave. Rate Depreciation watt Energy per Net Income & Hours Sales Megawatt (Loss)* Amortization Quarter Ended: Produced ($) Hour ($) ($) ($) June 30, 2012 15,999 765,255 50.3 (805,286 ) 507,783 September 30, 2012 17,836 1,176,107 68.1 2,348 505,560 December 31, 2012 21,170 1,398,218 67.9 154,752 505,559 March 31, 2013 19,675 1,064,481 56.1 67,620 472,040 June 30, 2013 17,248 823,154 49.9 (715,605 ) 472,094 September 30, 2013 18,687 1,260,124 69.5 (1,165 ) 450,222 December 31, 2013 21,951 1,479,499 69.0 254,302 450,222 March 31, 2014 21,614 1,199,551 57.9 61,749 427,907 June 30, 2014 18,069 907,194 52.6 (579,568 ) 428,180 * - Net income (loss) does not include intercompany elimination adjustments for interest expense, management fees and lease costs. Professional and Management Fees For the six months ended June 30, 2014, the Company incurred professional and management fees of $567,947, which was a decrease of $163,624 (22.4.6 % decrease) from the same period in 2013. For the three months ended June 30, 2014, the Company incurred professional and management fees of $197,964, which was a decrease of $234,226 (54.2% decrease) from the same period in 2013. The contract with the former CEO's consulting firm began in May 2013. Consulting fees of $155,393 were paid in the second quarter of 2013. During the first and second quarters of 2014, fees were paid to the former CEO's consulting firm of $39,761 and $14,400; respectively. The original contract ended April 2014, and was extended through December 2014 at a reduced rate of $1,000 per month. Consulting costs of $95,702 ($58,421 for the three months ended June 30, 2014) were paid to a geologist in the six months ended June 30, 2014, which was an increase of $62,259 ($32,978 increase for the three months ended June 30, 2014). In the quarter ended March 31, 2013, these costs were included in the Company salaries and wages. During the six months ended June 30, 2014, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $168,000, $135,000 and $47,000; respectively. During the six months ended June 30, 2013, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $224,000, $131,000 and $65,000; respectively. -51- -------------------------------------------------------------------------------- Salaries and Wages Salaries and wages include payroll and related costs incurred for exploration, design and development costs that cannot be capitalized, as well as general management and administration. Payroll and related costs for plant operations are expensed as plant production costs. For the six months ended June 30, 2014, the Company reported $1,072,057 in salaries and related costs which was a decrease of $46,086 (4.1% decrease) from the same period in 2013. For the three months ended June 30, 2014, the Company reported $677,344 in salaries and related costs, which was an increase of $123,689 (22.3% increase) from the same period in 2013. Salaries and related costs for administration and development employees before allocations were $261,816 ($259,879 in the three months ended June 30, 2014), which was 20.6% (40.4% higher in the three months ended June 30, 2014) higher in the six months ended June 30, 2014 than in the same period ended 2013. In the current six months, fewer amounts of payroll costs ($245,502 less) were allocated to capital projects than in the same period in 2013. In April 2014, the Company awarded raises to its employees that averaged 2.9%, and bonuses were awarded that totaled $376,750. In April 2013, employee bonuses were awarded that totaled $171,000. For the first and second quarters of 2013, approximately $188,000 and $138,000; respectively, in payroll and related costs were capitalized for design and other development activities for the Neal Hot Springs, Oregon project. For the six months ended June 30, 2013, $306,108 ($122,018 for the three months ended June 30, 2013) of the portions of plant managements' time was allocated to general corporate management and other non-capital development activities. Management and development employee salaries and related costs are as follows: For the Six Months Ended June 30, 2014 2013 Variance Financial Element $ $ $ % Total Company salary and related costs, excluding plant operations 1,531,537 1,269,721 261,816 20.6 Cost allocations: Capital projects (212,184 ) (457,686 ) 245,502 53.6 Operating management charged to general corporate management and other non-capital development activities - 306,108 (306,108 ) # Corporate management and support for plant operations (247,296 ) - (247,296 ) # 1,072,057 1,118,143 (46,086 ) (4.1 ) % - represents the percentage of change from 2013 to 2014. # - variance percentage that is extremely high or undefined. -52- -------------------------------------------------------------------------------- For the Three Months Ended June 30, 2014 2013 Variance Financial Element $ $ $ % Total Company salary and related costs, excluding plant operations 902,821 642,942 259,879 40.4 Cost allocations: Capital projects (100,466 ) (211,305 ) 110,839 52.5 Operating management charged to general corporate management and other non-capital development activities - 122,018 (122,018 ) # Corporate management and support for plant operations (125,011 ) - (125,011 ) # 677,344 553,655 123,689 22.3 % - represents the percentage of change from 2013 to 2014. # - variance percentage that is extremely high or undefined. Stock Based Compensation For the six months ended June 30, 2014, the Company reported $777,465 in stock based compensation, which was an increase of $513,712 (194.8% increase) from the same period in 2013. For the three months ended June 30, 2014, the Company reported $630,153 in stock based compensation, which was an increase of $425,763 (208.3% increase) from the same period in 2013. Stock based compensation includes the calculated values for both Company stock and stock options. The Company uses the Black-Scholes option-pricing model to value the cost of the outstanding stock options. The higher value of the stock options for the current quarter was directly impacted by the number of outstanding options and the increase in the Company's stock price and the related increase in the volatility of the Company's stock price. On April 2, 2014, the Company awarded employees 2,883,500 stock options and 559,122 shares (restricted shares). In the prior year, the Company did not issue stock options to employees until July 22, 2013 (1,950,000 options, no restricted shares to employees). During the current six months ended June 30, 2014, the Company's common stock price reached a high of $0.95 and a low of $0.38 ($0.62 average daily closing price). During the six months ended June 30, 2013, the Company's common stock price reached a high of $0.43 and a low of $0.31 ($0.35 average daily closing price). The stock based compensation components are summarized as follows: For the Six Months Ended June 30, 2014 2013 Variances $ $ $ %Total Stock Based Compensation: Stock option compensation 662,390 242,460 419,930 173.2 Stock compensation 115,075 21,293 93,782 440.4 777,465 263,753 513,712 194.8 % - represents the percentage of change from 2013 to 2014. -53- -------------------------------------------------------------------------------- For the Three Months Ended June 30, 2014 2013 Variances $ $ $ % Total Stock Based Compensation: Stock option 541,328 183,098 358,230 195.7 compensation Stock compensation 88,825 21,293 67,532 316.3 630,153 204,391 425,762 208.3 % - represents the percentage of change from 2013 to 2014. Exploration Costs For the six months ended June 30, 2014, the Company reported $24,086 in exploration costs, which was a decrease of $137,923 (85.1% decrease) from the same quarter in 2013. For the three months ended June 30, 2014, the Company reported $19,402 in exploration costs, which was a decrease of $394,975 (95.3% decrease) from the same quarter in 2013. During the six months ended June 30, 2013, the Company incurred drilling costs that exceeded $565,000 ($396,000 for the three months ended June 30, 2014) for test wells at Guatemala (U.S. Geothermal Guatemala S.A.). Interest Expense During the six months ended June 30, 2014, the Company reported $1,989,729 in interest expense from notes payable, which was an increase of $385,544 (24.0% increase) from the same period in 2013. During the three months ended June 30, 2014, the Company reported $1,008,737 in interest expense from notes payable, which was a decrease of $115,146 (10.2% decrease) from the same period in 2013. The primary reason for the increase related to the amount interest expense incurred by USG Nevada LLC (San Emidio, Nevada). During the quarter ended March 31, 2013, the Prudential Capital Group loan had not been finalized and most of the interest incurred under the contractor's obligations was capitalized. In the three months ended June 30, 2013, USG Nevada LLC incurred interest costs that totaled $621,712. In the three months ended March 31 and June 30, 2014, USG Nevada LLC incurred interest expense of $517,406 and $514,859; respectively. Net Income Attributable to the Non-Controlling Interests The net income attributable to the non-controlling interest entities is the line item that removes the portion of the total consolidated operations that are owned by the Company's subsidiaries. For the six months ended June 30, 2014, the Company reported $1,052,154 in net income attributable to non-controlling interests, which was an increase of $795,866 from the $256,288 net income reported in the same period ended 2013. For the three months ended June 30, 2014, the Company reported $155,517 in net loss attributable to non-controlling interests, which was a favorable decrease of $434,751 from the $590,268 net loss reported in the same quarter ended 2013. The primary reason for the increase was due to the operations of the Neal Hot Springs plant which reported net income of $4,266,753, which was an increase of $1,323,347 for the six months ended June 30, 2014 from the same period ended 2013. For the three months ended June 30, 2014, the USG Oregon LLC reported net income of $1,196,404, which was an increase of $677,648 for the quarter ended 2013. The impact of the USG Oregon LLC's operations on the Company's reported income attributable to non-controlling entities was an increase of $529,338 ($271,059 increase for the three months) from the six months ended June 30, 2013 as compared to the same period ended 2014. -54- -------------------------------------------------------------------------------- The net income or (loss) attributable to the non-controlling interest entities is detailed as follows: For the Six Months Ended June 30, Subsidiaries and Non-Controlling 2014 2013 Variance Interest Entities $ $ $ % Oregon USG Holdings LLC interest 1,694,707 1,027,180 667,527 65.0 held by Enbridge Inc. Raft River Energy I LLC interest (641,467 ) (768,855 ) 127,388 16.6 held by Raft River I Holdings, LLC Gerlach Geothermal LLC interest held (1,086 ) (2,037 ) 951 46.7 by Gerlach Green Energy, LLC 1,052,154 256,288 795,866 310.5 % - represents the percentage of change from 2013 to 2014. For the Three Months Ended June 30, Subsidiaries and Non-Controlling 2014 2013 Variance Interest Entities $ $ $ % Oregon USG Holdings LLC interest held 478,562 179,490 299,072 166.6 by Enbridge Inc. Raft River Energy I LLC interest held (633,000 ) (767,952 ) 134,952 17.6 by Raft River I Holdings, LLC Gerlach Geothermal LLC interest held (1,079 ) (1,806 ) 727 40.3 by Gerlach Green Energy, LLC (155,517 ) (590,268 ) 434,751 73.7 % - represents the percentage of change from 2013 to 2014. Off Balance Sheet Arrangements As of June 30, 2014, the Company does not have any off balance sheet arrangements. Liquidity and Capital Resources We believe our cash and liquid investments at June 30, 2014 are adequate to fund our general operating activities through December 31, 2015. Other project development, such as Guatemala, Geysers and the San Emidio expansion, 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, issuance of debt or equity, and/or through the sale of ownership interest in tax credits and benefits. The recent financial credit crisis has not impacted the ability of our customers, Idaho Power Company and Sierra Pacific Power (NV Energy), to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. The 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. -55- -------------------------------------------------------------------------------- On April 21, 2014, the Company completed the acquisition of Ram Power Corp.'s Geysers project for a total of $6.4 million in cash. The Ram subsidiaries included in the acquisition are Western GeoPower, Inc., Skyline Geothermal Holding, Inc., and Etoile Holdings Inc., which in turn includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The acquired Ram subsidiaries possess the full development interest in the project. These interests include all geothermal leases (covering 3809 acres), development design plans, and permits for a proposed 26 net megawatt power plant, and includes land and geothermal mineral rights ownership of the Mayacamas property purchased by Ram in 2010. This property contains 4 existing geothermal wells immediately available for production or injection and one historic well available for use after reworking. Finally, the acquisition includes a 50% undivided interest in the geothermal mineral rights relating to the property that contains the 5th existing well also purchased by Ram in 2010. The other 50% interest in this property is contained within an acquired leasehold interest. On November 29, 2013 the Company filed a replacement shelf registration statement on Form S-3 with the SEC. The replacement shelf registration statement was filed as routine course of business due to the impending expiration of the Company's existing shelf registration statement that, under SEC rules, would have expired on December 1, 2013. Pursuant to SEC rules, the expiration date of the existing shelf registration statement has been extended until the earlier of the effective date of the replacement shelf registration statement or May 30, 2014. Upon effectiveness of the S-3 on February 4, 2014, the Company may use the replacement shelf registration statement to offer and sell from time to time for a period of three years in one or more public offerings up to $50 million of common stock, warrants, or units consisting of any combination thereof. The terms of any securities offered under the replacement shelf registration statement, and the intended use of the resulting net proceeds, will be established at the times of any future offerings and will be described in prospectus supplements filed at such times with the SEC. The Company has no immediate plans to sell any additional stock under the replacement shelf registration statement at this time, but wishes to preserve the option in support of its future growth and development of its projects as well as strategic M&A opportunities. Following the receipt of the Section 1603 Federal Investment Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit funds, and after the receipt and disbursement of all remaining construction reserve funds, which was finalized on January 27, 2014, the final ownership interest in the Neal Hot Springs project was calculated in accordance with the terms of the partnership agreement. Ownership interest in the project is final with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal has received a $6.2 million cash distribution from the partnership. Under the terms of the DOE loan agreement, project profits are distributed to the equity partners semi-annually (February and August), following Final Completion, which was achieved on August 1, 2013. U.S. Geothermal's share of this first distribution received March 5, 2014 is $4.6 million, out of a total distribution to the partners of $7.7 million, which represents profits generated from the project since initial operation began in November 2012. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At June 30, 2014, $16.4 million in USG Oregon LLC funds were deposited at PNC Bank, and were unavailable for immediate corporate needs. For projects under construction before the end of 2010 and online before the end of 2013, a project was eligible to take a 30% investment tax credit ("ITC") in lieu of the production tax credit ("PTC"). The ITC was able to be converted into a cash grant within the first 90 days of operation of the plant. Phase I at San Emidio attained commercial operation on May 25, 2012. An application was submitted in July 2012 electing to take the ITC cash grant in lieu of the PTC. The United States Department of Treasury notified the Company that it would allow $10.65 million in cash grant. The cash grant proceeds were received on November 10, 2012 and used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC. An additional $1.05 million of cash grant items were subsequently approved and paid in March 2013. For the Neal Hot Springs project, an application was submitted in the first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for approximately $35.9 million from U.S. Treasury and the funds would be used to fund reserves required under the DOE Loan Guarantee Agreement and return funds to our partner in the project, Enbridge. Due to federal sequestration in early 2013, the ITC cash grant amount received in April 2013 was reduced by 8.7% to $32.7 million. -56- -------------------------------------------------------------------------------- In July 2010, the Company applied to the Oregon Department of Energy for the Business Energy Tax Credit ("BETC"), which allows an income tax credit for up to $20 million in qualifying expenditures for a renewable energy project. The Neal Hot Springs project completed final certification for the credit and sold it to a pass-through partner, monetized at a cash value of $7.36 million (less a broker fee) in November 2013. On May 21, 2012, 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, ("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 LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Following this initial purchase, 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 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 TSX. 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, 2014, the Company has sold LPC an aggregate of 4,625,506 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $1,343,639 (net of $86,911 broker and legal fees). On December 21, 2012, the Company and LPC entered into an Amendment No. 1 to the Purchase Agreement (the "Amendment") to reduce the total amount that can be purchased under the Purchase Agreement, including amounts already purchased, from $10,750,000 to $6,500,000. In September 2010, Oregon USG Holdings, 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, which converted. The DOE guaranteed project loan was treated as an equity contribution by Enbridge to the project. The agreements also provided for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note earned Enbridge a 20% direct ownership in the project. As a result 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 in the project by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments increased Enbridge's ownership to 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 increased their ownership in USG Oregon LLC based on running a project financial model and determining what percentage of the forecasted project income would be allocated to Enbridge to arrive at a predetermined rate of return for the additional investment. In February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal Inc. received an approximate $6.2 million cash distribution from the partnership. -57--------------------------------------------------------------------------------- Potential Acquisitions and Acquisitions Completed Subsequent to Period End 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. See Management's Discussion and Analysis and the financial statements and related footnotes included in our Transition Report on Form 10-K for the year ended December 31, 2013, for a description of our critical accounting policies. |