UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2016
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For transition period _______ to _______
Commission File Number 001-34023
U.S. GEOTHERMAL INC.
(Exact name of Registrant as specified in its charter)
| Delaware | 84-1472231 |
| (State or Other Jurisdiction of | (I.R.S. Employer |
| Incorporation or Organization) | Identification No.) |
| 390 Parkcenter Blvd, Suite 250 | |
| Boise, Idaho | 83706 |
| (Address of Principal Executive Offices) | (Zip Code) |
| Registrant’s Telephone Number, Including Area Code | 208-424-1027 |
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange on Which Registered |
| Common Stock, $0.001 par value | NYSE MKT LLC |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities Act
[
] Yes [X] No
Indicate by check mark if the registrant is not required to
file reports pursuant to Section 13 or Section 15(d) of the Act.
[ ] Yes [X] No
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for at least the past 90 days.
[X]
Yes [ ] No
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Website, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of
Regulations S-T (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such
files).
[X] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer [ ] | Accelerated filer [ ] |
| Non-accelerated filer [ ] (Do not check if a smaller reporting company) |
Smaller reporting company [X] |
Indicate by check mark whether the registrant is a shell
company (as defined in Rule 12b-2 of the Act).
[ ]
Yes [X] No
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of the end of the registrant’s most recent second quarter based upon the closing sale price of the registrant’s common stock as reported by the NYSE MKT LLC on June 30, 2016, was $92,730,531
The number of shares outstanding of the registrant’s common stock as of March 6, 2017 was 19,017,157.
DOCUMENTS INCORPORATED BY REFERENCE
None
U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2016
U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2016
PART I
Item 1. 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. 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.
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.
U.S. Geothermal Inc. (the “Company,” “we” or “us” or words of similar import) is in the renewable “green” energy business. Through our 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 United States and the Republic of Guatemala. 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.
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Development of Business
U.S. Geothermal Inc. was originally incorporated on March 10, 2000 in the State of Delaware. The Company constructs, manages and operates power plants that utilize geothermal resources to produce electricity. The Company’s operations have been, primarily, focused in the Western United States.
The Company currently owns and operates the following geothermal power plant projects: Raft River, Idaho; San Emidio, Nevada; and Neal Hot Springs, Oregon. The Company also has geothermal property interests in the Republic of Guatemala; the Geysers in California; Vale, Oregon; Crescent Valley, Nevada; Ruby Hot Springs, Nevada; Lee Hot Springs, Nevada; and Gerlach, Nevada, some of which are under development or exploration.
History
Geo-Idaho was formed as an Idaho corporation in February 2002 to conduct geothermal resource development.
U.S. Cobalt Inc. entered into a merger agreement with Geo-Idaho on February 28, 2002, which was amended and restated on November 30, 2003, and closed on the reverse take-over 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 was the surviving corporation and is the subsidiary through which the Company conducts operations. As part of this acquisition, the Company name was changed to U.S. Geothermal Inc.
Plan of Operations
Our business strategy is to identify, evaluate, acquire, develop, and operate geothermal assets and resources economically, safely and efficiently. Our management evaluates our operating projects based on revenues and expenses, and our projects under development, based on costs attributable to each project. We examine different factors when assessing projects at different stages of development or potential acquisitions, such as the internal rate of return of the investment, technical and geological matters and other relevant business considerations.
We intend to execute this strategy in several steps outlined below:
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Maximize Our Operations – Our operating power plants and operations team provide revenue to the Company through both power sales and Operations & Maintenance contracts. We strive to optimize plant operations though high safety standards, quality preventative maintenance programs, operator education, equipment selection and by exceeding our annual budgetary goals.
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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.
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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 typically have consulting reports from various industry experts supporting our belief in those projects’ potential. We are evaluating the potential of those projects and expect to negotiate Power Purchase Agreements (“PPAs”) for power deliveries with counterparties for some of these growth opportunities. If realized, our identified project pipeline will greatly expand our renewable power generation capacity as we move forward with the development of those opportunities.
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Utilize Production Tax Credits, Investment Tax Credits and Other Incentives – Although geothermal power production can be cost competitive with fossil fuel power generating facilities on a life cycle cost basis, government incentives such as production tax credits (“PTC”) and Investment Tax Credits (“ITC”) available to geothermal power producers help offset the high upfront project capital cost by enhancing the project economics and attracting 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 is to structure project ownership to optimize project economics. Under current legislation, a company may elect to take 30% ITC for certain qualified investments (or the PTC) provided construction of the project was started prior to the end of 2016. We believe that the second phase of our San Emidio project, our WGP Geysers project, and our Crescent Valley project each qualify for this credit.
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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 capital intensive, 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.
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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.
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During the year ended December 31, 2016, the Company was focused on these specific items:
- operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;
- conducting annual maintenance outages at all three projects;
- drilling and flow testing two wells at San Emidio II;
- permitting the deepening of three additional temperature gradient wells at San Emidio II;
- continuing to optimize and engineer the power plant/hybrid cooling design, obtaining the Conditional Use Permit, and pursuing PPA opportunities for the WGP Geysers project;
- drilling and flow testing a well at El Ceibillo;
- drilling a second leg on a production well at Raft River
- preparing for and drilling a water well at Neal Hot Springs; and
- evaluating potential new geothermal projects and acquisition opportunities.
Project Overview
The following are lists of projects that are in operation and projects that are under development or under exploration. Projects in operation currently have producing geothermal power plants. Projects under development have a geothermal resource discovery and have wells in place, but require the drilling of additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration may have a discovery well or 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, estimates provided for project development costs could understate actual costs.
Projects in Operation
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 factors discussed below. A summary of the Company’s operations is as follows:
| Projects in Operation | ||||||||||
| Generating | Contract | |||||||||
| Project | Location | Ownership | Capacity (megawatts) | Power Purchaser | Expiration | |||||
| Neal Hot Springs | Oregon | JV(1) | 22.0 | Idaho Power | 2036 | |||||
| San Emidio (Unit I) | Nevada | 100% | 10.0 | Sierra Pacific | 2038 | |||||
| Raft River (Unit I) | Idaho | JV(2) | 13.0(3) | Idaho Power | 2032 | |||||
| (1) |
The Company’s equity interest in the project is 60% and Enbridge’s equity interest is 40%. | |
| (2) |
The Company’s membership interest in the project to 95%. Goldman Sachs Group retains a 5% membership interest, and is the tax equity partner. | |
| (3) |
The annual average net output design for the plant is 13 megawatts. The output of the Raft River Unit I plant currently is approximately 9.4 megawatts annual average. |
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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 achieved commercial operation on November 16, 2012,
and is designed as a 22 megawatt net annual average power plant. The facility
consists of three separate 12.2 megawatt (gross) modules, with each module
having a design output of 7.33 megawatts (net) annual average, based on a
specific flowrate and temperature of the geothermal brine.
For the fourth quarter of 2016, generation was 57,036 megawatt-hours with an average of 26.3 net megawatts per hour of operation and plant availability was 98.2% . For the same period in 2015, the plant generated 52,641 megawatt-hours with an average of 24.1 net megawatts per hour and plant availability was 97.6% . The total annual generation for 2016 was 179,559 megawatt-hours compared to 176,871 megawatt-hours for 2015.
All three high pressure refrigerant pumps were replaced by the manufacturer under warranty and 70% of the Air Cooled Condenser (ACC) fan motors were rebuilt under the terms of the ESA settlement agreement during the year. The remainder of the ACC motors are scheduled to be rebuilt by the end of the second quarter 2017. The Unit 3 annual maintenance outage was taken in September. Scale was cleaned out of the vaporizers, and the pump in production well NHS-8 was replaced due to declining output. With the replacement of the pump in NHS-8, brine flow was increased through the plant by 7% resulting in an increase in generation.
A third water supply well for the project was drilled in December, but due to extreme winter weather, has not been completed and tested to date. Productive water zones were intersected in the well, but a liner must be installed before the well can be flow tested. A fourth site has been selected and will be drilled once weather allows. The project currently has one well available from drilling in 2015 that can supply approximately 170 gallons per minute. The minimum amount of water needed for a hybrid cooling system is approximately 200-300 gallons per minute for each unit.
Subsequent to the end of the year, on January 5, 2017 the facility tripped off line during extreme cold weather conditions and Unit 1 suffered frozen tubes in the vaporizers. The failed and damaged tubes were plugged, and the unit was restarted on February 12, 2017. Insurance coverage is in place to cover equipment repairs with a deductible level of $50,000. Lost generation is also covered by insurance once the unit was out of service for over 30 days.
The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. It has a 25-year term, and a variable percentage annual price escalation. The 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 annual average price paid under the PPA for 2016 was $109.27 per megawatt-hour and for 2017 the price has increased to $111.83 per megawatt-hour.
San Emidio Unit I, Nevada
The Unit 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. The San
Emidio facility is a single 14.7 megawatt (gross) module, with
a design output of 9 megawatts (net) annual average based on a specific flow and
temperature of geothermal brine.
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For the fourth quarter of 2016, generation was 20,803 megawatt-hours with an average of 9.6 net megawatts per hour of operation and plant availability was 98.2% . For the same period in 2015, the plant generated 20,369 megawatt-hours with an average of 9.4 net megawatts per hour and plant availability was 98.2% . The total annual generation for 2016 was 75,049 megawatt-hours compared to 79,539 megawatt-hours for 2015.
The high pressure refrigerant pump, which had been replaced under warranty during the scheduled spring maintenance outage experienced high vibrations shorty after starting. The plant was able to operate at a reduced generation level for 19 days and required a second outage to replace the faulty pump. The plant went back on line July 1st and has run without incident since.
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 from two units. The option for the second unit expired in December 2015. The PPA has a 25-year term with a base price of $89.75 per megawatt-hour, and an annual escalation rate of 1 percent. The annual average price paid under the PPA for 2016 was $93.01 per megawatt-hour and for 2017 the price has increased to $93.94.
Raft River, Idaho
Raft River Unit I is located in
Southern Idaho, near the town of Malta, and achieved commercial operation on
January 3, 2008. The Raft River facility is a single 18 megawatt (gross) module,
with a design output of 13 megawatts (net) annual average based on a specific
flow and temperature of geothermal brine.
For the fourth quarter of 2016, generation was 20,039 megawatt-hours with an average of 9.1 net megawatts per hour of operation and plant availability was 100%. For the same period in 2015, the plant generated 21,755 megawatt-hours with an average of 9.8 net megawatt hours and plant availability was 99.9% . Total annual generation for 2016 was 71,991 megawatt-hours compared to 75,599 megawatt-hours for 2015.
The lower year over year production is primarily due to the breakdown of the production pump in well RRG-2 on February 9, 2016 and the extended length of time the well was kept out of service to allow the planned drilling of a second production leg. Due to a delay in financing, drilling of the second leg began on June 13th and was completed on July 29th to a depth of 5,605 feet. Several small zones of permeability were encountered in the new production leg. After testing the well, a new pump was installed and the well resumed production in early September. The well temperature has plateaued at approximately 277°F, down from the original production temperature of 283°F, and the well is now producing approximately 180 gallons per minute less flow than before drilling. It is believed that during drilling operations, the original production leg of the well was damaged by scale formation, which blinded off its producing fractures. Current production is believed to be coming mostly from the newly drilled production leg. Operations to recover the damaged production leg with an industry standard chemical treatment will be considered in the future. Additionally, on September 27, 2016 the pump in well RRG-1 suffered a sheared coupling and was back on line in early November.
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Additional production is now planned from well RRG-5, an idle well with significant permeability that has been used for injection in the past. Flow testing and reservoir modeling was performed during the 4th quarter of 2016 to evaluate the well for conversion to production. Flow test results showed an initial flowing temperature of over 249°F, which is expected to increase to approximately 265°F once under production. Reservoir modeling shows that RRG-5 is capable of producing up to 1,000 gpm, yielding approximately 1.5 to 2 additional net megawatts of generation from the plant. A production pump has been ordered, and is expected to be installed by the end of the first quarter 2017. Generation is expected to ramp up during the second quarter as the production wellfield is rebalanced to maximize its output. Additional sources of geothermal fluid from other wells on the project are also under study to further increase the generation level of the plant.
Well RRG-9, which has been used as part of an $11.4 million thermal stimulation grant funded primarily by the Department of Energy, has significantly increased the injection capacity to 1,200 gallons per minute from an original level of 20 gallons per minute. This increase in injection capacity can provide all of the additional volume needed to accept the flow from well RRG-5 without requiring any new drilling.
The PPA for the project was signed on September 24, 2007 with the Idaho Power Company and allows for the sale of up to 13 megawatts of electricity on an annual average basis. 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 through 2020 and then at 0.6% per year until the end of the contract in 2034. 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 annual average price paid under the PPA for 2016 was $63.30 per megawatt-hour, and for 2017 the price has increased to $64.63.
In addition to the price paid for energy by Idaho Power, Raft River Unit I currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits (“RECs”) to Holy Cross Energy, a Colorado electric cooperative. Starting in calendar year 2018, 51% of the RECs produced by the project will be owned by the Idaho Power Company and 49% by the project. For the 49% of RECs owned by the Raft River project, a new, 10 year REC contract with the Public Utility District No. 1 of Clallam County, Washington will replace the current contract, also in 2018.
Material Projects Under Development/Exploration
In addition to our projects in operation, we have projects under development and under exploration. Projects under development have at least a geothermal resource discovery or may have wells in place, but require the drilling of new or additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration do not have a geothermal resource discovery occurrence yet, but have significant thermal and other physical evidence that warrants the expenditure of capital in search of the discovery of a geothermal resource. Due to inflation and marketplace increases in the costs of labor and construction materials, estimates of property development costs may be low.
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A summary of projects under development and under exploration is as follows:
| Projects Under Development | ||||||
| Estimated | ||||||
| Target | Projected | Capital | ||||
| Development | Commercial | Required | Power | |||
| Project | Location | Ownership | (Megawatts) | Operation Date | ($million) | Purchaser |
| Raft River | Idaho | 100% | 1-3 | 1st Quarter 2017 | 4 | IDPC |
| Neal Hot Springs | Oregon | 60% | 3 | 3rd Quarter 2017 | 10 | IDPC |
| San Emidio Phase II | Nevada | 100% | 35-45 | 4th Quarter 2019* | 145 | TBD |
| WGP Geysers | California | 100% | 30 | 4th Quarter 2018* | 150 | TBD |
| El Ceibillo Phase I | Guatemala | 100% | 25 | 2nd Quarter 2019* | 140 | TBD |
| Crescent Valley Phase I | Nevada | 100% | 25 | 2nd Quarter 2020* | 130 | TBD |
|
* - Commercial operation dates are projections only. Actual dates can only be provided after power purchase agreements have been obtained. |
| Properties Under Exploration | ||||||
| Target Development | ||||||
| Project | Location | Ownership | *(Megawatts) | |||
| Gerlach | Nevada | 67.4% | 10 | |||
| Vale | Oregon | 100% | 15 | |||
| El Ceibillo Phase II | Guatemala | 100% | 25 | |||
| Neal Hot Springs II | Oregon | 100% | 10 | |||
| Raft River Phase II | Idaho | 100% | 13 | |||
| Crescent Valley Phase II | Nevada | 100% | 25 | |||
| Crescent Valley Phase III | Nevada | 100% | 25 | |||
| Lee Hot Springs | Nevada | 100% | 20 | |||
| Ruby Hot Springs Phase I | Nevada | 100% | 20 | |||
|
* - Target development sizes are predevelopment estimates of resource potential of unproven resources. The estimates are based on our evaluation of available information regarding temperature, and where available, flow. |
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| Property Details | ||||||||
| Property Size | ||||||||
| (square | ||||||||
| Property | miles) | Temperature (ºF) | Depth (Ft) | Technology | ||||
| Neal Hot Springs | 9.6 | 286-311 | 2,500-3,000 | Binary | ||||
| San Emidio | 27.9 | 289-316 | 1,500-3,000 | Binary | ||||
| Raft River | 10.8 | 275-302 | 4,500-6,000 | Binary | ||||
| Gerlach | 4.7 | 338-352 | 2,000-3,000 | Binary | ||||
| El Ceibillo | 38.6 | 410-526 | 1,800-TBD | Steam/Flash | ||||
| WGP Geysers | 6.0 | 380-598 | 6,000-10,000 | Steam | ||||
| Crescent Valley | 33.3 | 326-351 | 2,000-3,000 | Binary | ||||
| Lee Hot Springs | 4.0 | 280-320 | 1,250-5,000 | Binary | ||||
| Ruby Hot Springs | 3.3 | 315-340 | 1,670-4,500 | Binary | ||||
| Vale | 0.6 | 290-300 | 2,450-5,000 | Binary | ||||
Binary Cycle Geothermal Power Plants
In a binary
cycle geothermal power plant hot water is produced to a piping and gathering
system from wells drilled into the geothermal reservoir. The hot water flows,
with to a heat exchanger called a vaporizer where it vaporizes a secondary
working fluid, with its heat extracted, causing the original hot water to become
cool. All of the cooled water is then pumped to injection wells where it is
injected back into the reservoir to help recharge the geothermal reservoir. The
vaporized working fluid passes through a turbine which drives an electrical
generator that is tied into the electrical transmission grid. Upon discharging
the turbine the secondary working fluid is condensed before piping it back to
the vaporizer where the process is repeated.
Dry Steam Geothermal Power Plants
An example of a
vapor dominated geothermal system is at The Geysers in central California. Dry
super-heated steam is produced from wells through a piping system and run
directly through a turbine. The turbine drives an electrical generator that
delivers power to the electrical transmission grid. Steam discharges from the
turbine into a condenser where it is condensed forming water. The water is
pumped to a cooling tower where it can be used as water for the cooling process.
The cooled water from the cooling tower is recycled back to the condenser to
repeat the process. Any excess water from the cooling tower is
pumped through a piping system to injection wells where it is injected back into
the reservoir which helps to recharge the geothermal reservoir.
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Flash Geothermal Power Plants
In hot water
geothermal systems (temperatures greater than approximately 400 degrees
Fahrenheit), flash production systems are often used. The hot water is produced
from wells drilled into the geothermal reservoir. The hot water from the various
production wells is piped to a flash tank where the pressure is reduced. The
reduction in pressure in the flash tank causes part of the hot water to flash to
form steam and part to remain as water. The flash tank also acts a separator,
separating the steam from the water. The hot water separated from the steam is
pumped through a pipeline system to injection wells and injected into the
reservoir for reservoir recharge. The steam coming off the flash tank/separator
is piped directly to a turbine where the process is identical to that used for
dry steam geothermal power plants.
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El Ceibillo Phase I, 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 agreement contains a
schedule that requires the development and construction of a power plant. In
July 2015, the Guatemalan Ministry of Energy and Mines approved a modified
construction schedule that extended the development and construction period to
June 1, 2018. There are 24,710 acres (100 square kilometers) in the concession,
which is at the center of the Aqua and Pacaya twin volcano complex.
Production well EC-5 was completed to a depth of 1,450 feet (442 meters) on August 20, 2016 and intersected a high permeability zone at 1,299 feet (396 meters). EC-5 underwent a series of flow tests, with field wide monitoring, beginning on September 5th and ran until September 13th. Data was collected from three monitoring wells during the test (EC-2A, EC-3, and EC-4) to provide pressure data for the reservoir model. Fluid samples taken at the end of the flow test indicate a potential reservoir temperature of 450 to 523°F (232 to 273°C).
With the shallow, commercial resource now indicated, a deep well is planned in 2017 to test the producing structure down dip from well EC-5 to a projected depth of 1,970 to 2,300 feet (600-800 meters). A deeper intersection in the reservoir could increase the reservoir capacity and production temperature, and change the design of the power plant. Well EC-1, which was drilled in 2013 to a depth of 5,650 feet (1,722 meters) found a measured bottom-hole temperature of 526°F (274°C), but did not intersect permeability. The comparative geology between EC-5 and EC-1 suggests a fault or other structure feeding the reservoir may be located in the area between the two wells.
On January 10, 2017, the Guatemalan government, through the National Electrical Energy Commission (COMISIÓN NACIONAL DE ENERG¥A ELÉCTRICA–“CNEE”), announced that it is preparing to issue an RFP later this year for 420 megawatts of power, of which 40 megawatts is to be reserved specifically for geothermal energy. When the RFP is issued, the El Ceibillo project will be bid into the process.
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San Emidio Phase II, Nevada
The Phase II expansion
is dependent on successful development of additional production and injection
well capacity. We expect that approximately 75% of the Phase II development may
be funded by non-recourse project debt, with the remainder funded through equity
financing. We anticipate the project qualifying for the 30% Federal Investment
Tax Credit, which when monetized, can meet most of the equity financing
requirements.
The updated reservoir model (announced January 11, 2017) resulted in a significant increase in the potential size of the San Emidio Phase II reservoir of up to 47 net megawatts. Data from flow tests that took place in late 2016 from two wells were incorporated into a Probabilistic Power Density model, which estimates the Net generation potential of a reservoir. The power density model is not a Monte Carlo style “heat in place” estimate. Based on the flow rate and temperature produced by the two wells, and by measurement of pressure response both in the wells and across the wellfield, the model estimates that the Most Likely Outcome (50% probability) is 47 net megawatt of generation capacity within a 1.4 square mile area. The Minimum level of generation capacity (90% probability) occurs in a 0.18 square mile area, and has 18.8 net megawatts of generation capacity.
These two wells are approximately 1,700 feet apart, along the new structural trend identified in the Southwest Zone which is still open for expansion. Temperature gradient well data and seismic information indicate a potential strike length for the Southwest Zone of up to 2,700 feet. This compares to a strike length for the primary producing wellfield at San Emidio Phase I of 800 feet, suggesting the potential for a much larger resource in this Southwest Zone. Permits to deepen three remaining temperature gradient wells were received from the Bureau of Land Management in December 2016. These three wells will be deepened to the targeted reservoir depth to further explore the Southwest Zone when weather allows. If successful, it could extend the length of the productive reservoir by 1,000 feet.
The three power plant units that were purchased in 2016 are available to provide this project with the major, long lead equipment requirements for 35-45 net megawatts of power (depending upon cooling system used). The increased San Emidio II reservoir capacity with a 320°F+ temperature fits the design range of the equipment. These new, unused components represent approximately 70% of the equipment needed for a complete facility similar to the Company’s Neal Hot Springs operation.
Given the larger resource capacity at San Emidio II, we have cancelled our Small Generator Interconnection Agreement that was completed in 2016, and are preparing to apply for a Large Generator Interconnection Agreement in support of the higher expected output. Additionally, transmission studies that contemplate power sales into Southern California will also be conducted, since there is now a transmission path from Northern Nevada going south on the new 500KV, 800 megawatt transmission line that was completed in January 2014.
In July 2016, the Company was awarded a $1.5 million Department of Energy cost share grant under the “Development of Technologies for Sensing, Analyzing, and Utilizing Novel Subsurface Signals in Support of the Subsurface Technology and Engineering (“SubTER”) Crosscut Initiative”. The program approved under the grant includes using new subsurface technologies at both San Emidio and Crescent Valley to identify fluid flow paths in the geothermal resource. The data collection phase of the program was completed at San Emidio in December. The data is being interpreted to determine whether viable targets have been identified. Upon approval from the DOE, a second phase of the grant program is designed to confirm the findings by drilling. The total program cost is $1.9 million with the Company providing $400,000 in cost share.
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WGP Geysers, California
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. We
expect that approximately 75% of the development may be funded by non-recourse
project debt, with the remainder funded through equity financing. We anticipate
the project qualifying for the 30% Federal Investment Tax Credit, which when
monetized can meet most of the equity financing requirements.
The Conditional Use Permit from Sonoma County, which approves the construction plan for the WGP Geysers power plant, was received on December 16, 2016. Combined with the Large Generator Interconnection Agreement that was received from the California Independent System Operator and Pacific Gas & Electric, this completes the long lead permits and agreements that are needed for the project. Once final engineering design is finished, and a PPA is executed, an air quality permit and building permit will be needed before on site construction will begin.
We received the signed Large Generator Interconnection Agreement for the project on March 6, 2016 with the California Independent System Operator and Pacific Gas & Electric (PG&E). This agreement allows the project to connect to the transmission grid and deliver up to 35 megawatts of energy. The Company has paid the total interconnection cost of $1.9 million for the grid operator’s portion of the work in the substation. An additional 1.7 mile long transmission line will be required to connect from the plant to the substation. PG&E has undertaken engineering studies to determine the cost for the line.
Engineering optimization of the new, hybrid power plant design is continuing and budgetary quotes for the major equipment have been received. Our engineers and consultants are working in concert with EPC contractors to examine all aspects of the construction cycle with a focus on reducing construction costs. The hybrid design will dramatically increase the volume of water available for injection back into the reservoir, which will result in increased power generation over the life of the project. Traditional water cooled geothermal steam plants re-inject approximately 20 to 25% of the water that is extracted from the steam, while a hybrid design may re-inject 65% or more of the water. This higher injection rate will provide longer term, stable steam production, and will result in increased power generation over the life of the project.
Based on flow test data generated from well flow testing performed in mid-2015, a third party expert reported in September 2015, that the four production wells already drilled are capable of delivering an initial capacity of 28.1 MW (gross) or 25.4 MW (net) based on current power plant steam conversion rates from a detailed design for a 28.8 MW (net) power plant. These tests show the wells would initially produce a combined total of 458,000 pounds per hour. Using the average steam production rate from these wells and an assumed interference factor of 30%, the third party expert estimates that an additional two to three production wells would be needed to support the long term operation of a 28.8 MW (net) plant.
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Recent discussions have been held with a number of potential power purchasers in California for the generation from the WGP Geysers plant and are continuing. Interest has been expressed by a number of them for base load, renewable power to replace fossil fuel based power generation that is being phased out of some of their portfolios.
Crescent Valley Phase I, Nevada
The Crescent Valley
prospect consists of approximately 21,300 acres (33.3 square miles) of private
and Federal geothermal leases. It is located in Eureka County, Nevada,
approximately 15 miles south of the Beowawe geothermal power plant and about 33
miles southeast of Battle Mountain. The project was acquired as part of the
Earth Power Resources merger which was completed in December 2014.
In light of federal legislation that extended the qualification for the 30% Investment Tax Credit to projects that began construction prior to December 31, 2014, drilling of the first production/injection well CVP-001 (67-3) was initiated in December of 2014, following completion of gravity surveys, and analysis of prior temperature gradient drilling data. Well CVP-001 was completed on March 27, 2015 to a depth of 2,746 feet. The well exhibited modest permeability with a flowing temperature of 213°F, which makes the well suited for duty as an injection well. The next phase of development work is in the planning stages and is currently on hold due to market conditions.
This project is expected to benefit from the Department of Energy cost share grant awarded in July 2016. The details of this award are discussed in the San Emidio Phase II project discussion above.
Gerlach, Nevada
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 in 2010 and the hole was opened from a 6.5 inch diameter well to a
12.5 inch diameter well. Lost circulation was confirmed within 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, 2014. 18-10a is a twin well to a well originally drilled in 1994 (the 18-10 well). The upper section of the well was drilled to 826 feet deep and an 8 inch liner was cemented in place. Temperature measurements in the well have provided the highest measured temperature in the field to date at 268°F within 160 feet 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 from the original well at 1,600 and 2,800 feet deep that will be targeted when drilling is resumed.
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Drilling 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. Drilling resumed again on well 18-10a on August 14, 2014, and was completed in late November. The well was drilled to a total depth of 2,889 feet and encountered a maximum temperature of 275°F. Further work is dependent upon additional funding from the partners.
Vale, Oregon
The property consists of 368 acres of
geothermal energy and surface rights located in Malheur County, located
approximately one-half mile east of the town of Vale, Oregon. The property is
within the Vale Butte geothermal resource area and provides the opportunity to
evaluate development of a known resource. A prolific, shallow reservoir located
along the north edge of the leasehold area has been used for many years in an
agricultural drying facility and a mushroom growing operation.
An extensive database of geophysical and geological information from previous geothermal exploration in the Vale Butte area was used in the evaluation of the prospect. Geochemical analysis of samples taken from shallow hot wells results in a calculated geothermometer that indicates a potential reservoir temperature of 311°F to 320°F. Past exploration drilling near the site by Trans Pacific Geothermal and Sandia National Laboratory encountered temperatures in excess of 300°F in the basement rocks. The leases for this project were acquired in January and February 2014.
Raft River Phase II, Idaho
In 2011, the Raft River
Phase II project was awarded an $11.4 million cost-shared, thermal stimulation
program grant from the Department of Energy with the University of Utah Energy
And Geoscience Institute as the project lead. The goal of the project is to
create an Enhanced Geothermal System (“EGS”) by creating thermal fractures and
developing a corresponding increase in permeability in the low permeability
rock. Well RRG-9 was made available for the program and the first stage of
injection into the well began in June 2013.
Initially the well was only capable of receiving 20 gallons per minute (“gpm”) of water due to the low permeability of the rock. After several moderate pressure stimulations, the injection of cold power plant discharge fluid was started and has continued to date. The lower temperature fluid causes thermal fracturing within the higher temperature host rock of the reservoir. At the current plant generation level, the flow into the well has continued to increase and is now approximately 1,200 gpm.
Well RRG-9 continues to be used temporarily as an injection well as an extension of the DOE EGS program, which is expected at this time to continue through until mid-2017. The Company’s contributions for the thermal stimulation program are made in-kind by the use of the RRG-9 well, well field data provided by the Company, and through ongoing monitoring support.
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Lee Hot Springs, Nevada
Lee Hot Springs is in
Churchill County, 18 miles south of Fallon. The area was originally explored by
Occidental Geothermal Company, a subsidiary of the oil company Occidental
Petroleum Corporation. The project is comprised of 2,560 acres (four square
miles) of BLM leases. ENEL Green Energy, a subsidiary of ENEL Group, the Italian
based, multi-national power company, has completed a 15 megawatt binary plant at
Salt Wells, 6 miles to the east of Lee. The project was acquired as part of the
Earth Power Resources merger which was completed in November 2014.
Dating back to 1930, the area has had numerous water wells, thermal gradient holes, and geothermal slim hole tests. From 1977-1982 Occidental Geothermal, Inc. drilled four temperature gradient holes to depths of 500 feet, two stratigraphic test wells’ to 2,000-3,000 feet, and one large-diameter production test to 3,000 feet (well 72-33). The 3,000 foot test well flowed 280°F hot water from a zone at 1,200 ft. The A33-4 well, 1,000 feet southwest of well 72-33, was drilled to 2,400 feet and reportedly had temperatures in excess of 300°F and a steadily increasing temperature gradient.
The Great Basin Research Institute has had the leasehold mapped in detail, showing several large silica deposits. The reservoir temperature has been estimated using geochemistry as ranging from 320°F to 340°F by the US Geological Survey and other sources in the 1970s.
Ruby Hot Springs, Nevada
The property is located 30
miles southwest of Elko. EPR filed a BLM lease application for 2,140 acres in
February 2001 and the lease application was rejected by the BLM in December 2005
due to cultural issues. The decision was appealed to the Interior Board of Land
Appeals (“IBLA”) and the IBLA remanded the application back to the BLM for
further action. No further action has been taken by BLM on issuance of the lease
pending the completion of cultural and ethnographic studies that are required
for further review. The project was acquired as part of the Earth Power
Resources merger which was completed in November 2014.
The area around Ruby was first leased by Union Oil Company (now Chevron) in the late 1970s. A 3,149 foot test well was drilled and reportedly flowed at over 300°F. A second well in the area, Ruby Valley 65-10, was drilled to 1,075 feet deep and encountered lost circulation zones, but no temperature data is available. In the early 1980s, Aminoil drilled twelve 500 foot deep temperature gradient wells and two 1,000 foot stratigraphic test wells. Data from these wells have been incorporated into generalized heat-flow contour maps of the area.
Employees
At December 31, 2016, the Company had 48 full-time and one part time employees (14 administrative and project development, and 35 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.
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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 and energy credit sales. All power plants currently in operation, as well as all sites under exploration or development, are sites located in the Western United States or in the Republic of Guatemala in Central America.
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.
Unless major geological changes occur that impact the geothermal reservoirs, the condition of the existing resources is expected to remain relatively consistent over time.
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Significant Government Permits
The Company maintains all permits necessary for operating its three plants located in Idaho, Nevada and Oregon. In addition, in December 2016 the Company received the primary operating permit necessary for construction and operation of the WGP Geysers project.
Neal Hot Springs, Oregon. The Neal Hot Springs project has four primary permits governing power plant operations. The permits include:
| 1. |
Geothermal Well Permits issued by the Department of Geology. | |
| 2. |
A Right-of-Way issued by the Bureau of Land Management. | |
| 3. |
A Conditional Use Permit issued by the Malheur County Commission. | |
| 4. |
Underground Injection Control Permit issued by the Oregon Department of Environmental Quality. |
San Emidio, Nevada. The San Emidio project has five primary permits governing power plant operations. The permits include:
| 1. |
Geothermal well permits issued by the Nevada Division of Minerals. | |
| 2. |
A Special Use Permit issued by the Washoe County Board of Commissioners. | |
| 3. |
An Air Quality Permit to Operate from Washoe County. | |
| 4. |
A Surface Discharge Permit from Nevada Division of Environmental Protection. | |
| 5. |
An Underground Injection Permit from Nevada Division of Environmental Protection. |
Raft River, Idaho. The Raft River project has four primary permits governing power plant operations. The permits include:
| 1. |
Geothermal well permits issued by the Idaho Department of Water Resources. | |
| 2. |
A Conditional Use Permit issued by the Cassia County Planning and Zoning Commission. | |
| 3. |
Air Quality Permit to Construct issued by the Idaho Department of Environmental Quality. | |
| 4. |
A Wastewater Reuse Permit issued by the Idaho Department of Environmental Quality. |
WGP Geysers, California. Western GeoPower had previously been issued all necessary permits for construction and operation of up to a 38.5 megawatt geothermal power plant. The Sonoma County Conditional Use Permit administratively expired in 2015. A new Conditional Use was issued in December 2016 for an initial term of 10 years including administrative extensions of 5 years. The primary permits include:
| 1. |
Geothermal well permits for production and injection wells issued by the California Department of Oil, Gas, and Geothermal Resources. | |
| 2. |
A Conditional Use Permit that has been issued by the Sonoma County. |
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| 3. |
Air Quality Permit to Construct issued by the Northern Sonoma Air Quality Board. |
Seasonality of Business
The Company has been producing energy revenues under the terms of three PPAs. Two of these contracts specify favorable rate periods and all three plants experience changes in levels of production through the year. The Raft River Energy I LLC (Raft River, Idaho) and USG Oregon LLC (Neal Hot Springs, Oregon) contracts pay higher rates in the months of July/August and November/December. Energy production can be influenced by the seasonal temperatures. 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. The Neal Hot Springs plant, since it utilizes air cooling rather than water cooling, is impacted more in the summer (lower generation) than the Raft River or San Emidio plants. Neal Hot Springs produces higher generation in the winter. Drilling and other construction activities can 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 exploration and development operations. Once the decision is made to construct a project, high levels of working capital are committed, either directly or indirectly to the construction efforts. After a plant becomes commercially operational and the necessary operating reserves have been funded, the needs for working capital are typically low. The Company is expecting to be significantly involved in exploration and development activities for the next 5 to 10 years.
Dependence on a Few 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 are limited. The Company’s primary revenues originate from energy sales and the sale of energy credits. Currently, the Company generates energy revenues and energy credits from three sources. Idaho Power Company purchases energy generated by both Raft River Energy I LLC and USG Oregon LLC. NV Energy purchases energy from USG Nevada LLC. Energy credits earned by Raft River plant are sold to Holy Cross Energy. Under the current PPAs, energy credits that are earned by USG Oregon LLC and USG Nevada LLC plants are bundled with energy sales. Based upon current operations and expected project completions, it is expected that the Company will have a small number of direct customers that may amount to less than 10 over the next 5 to 10 years.
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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 and retail sellers of electricity to purchase a minimum percentage of their power from renewable sources. For example, RPS statutes in California require 50% by 2030, Oregon requires 50% by 2040 and Nevada requires 25% by 2015. According to the Department of Energy’s Energy Efficiency and Renewable Energy department, approximately 38 states nationwide have established renewable portfolio standards or goals encouraging the procurement of green, renewable power. 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 are currently only two commercial geothermal facilities, both operated by the Company. 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 the baseload generation profile provided by geothermal power, with access to infrastructure for deliverability, and a low "full life" cost of power will allow geothermal to successfully compete for long term PPAs.
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;
- availability of low cost natural gas as an alternate fuel source
- 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
Geothermal drilling, construction and power plant operations are subject to federal, state and local environmental requirements and construction oversight. Applicable laws may include but are not limited to the Clean Air Act, the Clean Water Act, the Emergency Planning and Community Right-to-Know Act, the Endangered Species Act, the National Environmental Policy Act, state specific geothermal drilling rules, state and federal injection well requirements and standards and local building codes.
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Prior to acquiring an existing geothermal development, USG retains an independent, licensed engineer or geologist to conduct a Site Assessment and evaluate the property and performs detailed due diligence to minimize the potention of an unrecognized financial liability from being passed to U.S. Geothermal Inc. or our subsidiaries.
Our geothermal operations involve significant quantities of geothermal brine that is returned to the local subsurface, geologic formation. We also use isopentane and R-134A refrigerant working fluids, and numerous industrial lubricants that are considered contaminants if released or spilled. We are not aware of any mismanagement of these materials and we are required to promptly report any release of specified volumes of oil, lubricants, and chemicals used in our operations.
The requisite approvals and permits for our operations have been independently reviewed and verified prior to obtaining project financing. Independent legal reviews have verified that USG and our subsidiaries are operated in accordance with applicable laws. Existing laws and regulations may be revised or reinterpreted, or new laws and regulations may become applicable to us. Under those circumstances we work with the appropriate agency or entity to ensure that our operations remain in compliance with the applicable rules. As of the date of this memorandum, all of the permits and approvals required to operate our plants have been obtained and are valid.
Neal Hot Springs, Oregon
The Neal Hot Springs
project is situated approximately 12 miles west of Vale, Oregon in an area with
two nearby residents. There are no unique plants or animal communities in the
area and no unique cultural or environmental constraints.
Because the power plant is air-cooled the only environmental reporting required is a monthly production and injection report and an annual water quality summary. Both reports are sent to the Oregon Department of Environmental Quality and Oregon Department of Geology and Mineral Industries. Semi-annual water monitoring has been conducted since 2008 and will continue throughout power plant operations. The Neal project files a quarterly energy generation report with the Federal Energy Regulatory Commission. An independent legal team has reviewed all regulatory requirements, permits and approvals for the project.
Adjoining rangelands are privately and federally managed and there are no rangeland or cropland management obligations.
The Neal project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.
San Emidio, Nevada
The San Emidio project is located
approximately 14 miles south of Gerlach Nevada. The nearest residence is over
four miles from the plant site.
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The San Emidio staff files monthly, quarterly and annual water reports with the Department of Environmental Protection and Department of Water Resources. Similar to other projects San Emidio’s monthly geothermal production and injection volumes are submitted the Division of Minerals and Division of Environmental Protection. Water quality reporting is also submitted regularly to the Division of Environmental Protection.
San Emidio is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.
Raft River, Idaho
The Raft River project is located
approximately 12 miles south of Malta, Idaho in a rural agricultural area with
the nearest residence approximately two miles from the plant site. There are no
unique plants or animal communities in the area and no unique cultural or
environmental constraints.
Wastewater reuse requires a significant level of environmental reporting and data management. Water quality data is collected a minimum of four times annually. Monthly production and injection reports are filed with the Idaho Department of Water Resources, a land application and cooling water quality reports filed with the Idaho Department of Environmental Quality and Idaho Department of Water Resources annually. The Project’s private lands are managed on an ongoing basis for weed control, water management, irrigation, and fencing infrastructure.
The Raft River project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.
WGP Geysers, California
The Geysers project is
located approximately 30 minutes north-east of the city of Healdsburg, CA. The
property encompasses a ridgetop and a north facing hillside that has been
developed and used for geothermal operations from l979 to l989. There are no
unique plant or animal communities on the project site and no unique cultural or
environmental constraints. The North Coast Regional Water Quality Board (NCRWQB)
has required, prior to new construction, that WGP submit a plan to remove or
reuse existing steam pipelines. The pipelines may contain mineral scale that has
arsenic levels that exceed 150 parts per million.
WGP’s ongoing environmental reports include a monthly well report that is filed with the California Department of Oil, Gas and Geothermal Resources and an annual water quality report that is filed with the California Regional Water Board.
The Geysers project is in compliance with all environmental permitting, monitoring and reporting requirements and has received no formal or informal notices from any local, state, or federal agency.
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Gerlach, El Ceibillo, Crescent Valley, Lee Hot Springs, Ruby
Hot Springs, and Vale
No power plant operations are being conducted on
these properties at this time. The Company is in compliance with all
environmental and regulatory requirements and has received no formal or informal
notices from any local, state, or federal agency. There are no monthly,
quarterly, or annual reporting requirements associated with these projects.
Financial Information about Geographic Areas
The Company has interests in operational power plants in three locations in the Western United States. The Raft River Energy I LLC power plant is located in the southeastern part of the State of Idaho. Raft River Unit I became operational on January 3, 2008. USG Nevada LLC constructed a new power plant located in the northwestern part of the State of Nevada in the San Emidio Desert. This power plant owned by USG Nevada LLC became commercially operational May 25, 2012. The three units owned by USG Oregon LLC became commercially operational November 16, 2012. These units are located in the Eastern part of the State of Oregon near the Idaho border. A summary of total energy and energy credit sales by location is as follows:
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| USG Oregon LLC located in Eastern Oregon | $ | 19,561,718 | $ | 18,823,799 | ||
| USG Nevada LLC located in Northwestern Nevada | 6,980,358 | 7,324,484 | ||||
| Raft River Energy I LLC located in Southeastern Idaho | 4,939,599 | 5,051,815 | ||||
| Total energy and energy credits sales | $ | 31,481,675 | $ | 31,200,098 | ||
Financial Information about Business Segments
The Company has two reporting segments: operating plants and corporate and development. For more information about the business segments, please see Note 15 to our consolidated financial statements.
Available Information
We file annual, quarterly and periodic reports, proxy statements and other information with the U.S. Securities and Exchange Commission (“SEC”). You may obtain and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580;Washington D.C. 20549. You may obtain information on the operation of the SEC’s Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and other information statements and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible via the internet at that website.
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 of 1934, as amended (the “Exchange Act”), 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.
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Governmental Approvals and Regulations
The geothermal energy industry in the United States is regulated by federal, state and local agencies and commissions. Those agencies and commissions regulate geothermal drilling, power generation activities and environmental protection through permitting, licensing and bonding requirements. The following information is a general summary of the electric utility industry and applicable regulations in the United States and is not a full statement of the law or all issues pertaining to electric industry requirements.
Regulatory oversight of the industry can be broadly divided between rules governing geothermal exploration and rules governing actual energy generation, power sales and delivery. Geothermal fluid production is regulated under federal and state rules and regulations that require permits for drilling operations, geothermal fluid production and injection, and well abandonment. Prior to drilling agencies will review plans and ensure that natural resource values such as air, water, wildlife and vegetation are protected. Geothermal energy generation is regulated under federal, state and local rules and regulations. Permits are required for power plant construction and operation and ensure that a project site is suitable and that natural resource values and community concerns, if any, are evaluated and mitigated during the planning and design phase.
Federal Electric Utility Industry Regulation. Electricity production and public utilities are regulated by both the federal government and state utility commissions. State utility commissions traditionally exercise their jurisdiction over an electric utility’s retail operations. There are two primary pieces of federal legislation that have governed public utilities since the 1930s, the Federal Power Act (“FPA”) and Public Utility Holding Company Act of 1935 (“PUHCA”). These statutes have been amended and supplemented by subsequent legislation, including Public Utility Regulatory Protection Act (“PURPA”), the Energy Policy Act of 1992, and Energy Policy Act of 2005 (“EPAct 2005”).
Federal Power Act. Pursuant to the FPA the Federal Energy Regulatory Commission (“FERC”) has exclusive jurisdiction over the rates for most wholesale sales of electricity and transmission in interstate commerce. These rates may be based on a cost of service approach or may be determined on a market basis through competitive bidding or negotiation. FERC's regulations under PURPA exempt owners of small power production Qualifying Facilities that use geothermal resources as their primary source and other Qualifying Facilities that are 30 megawatts or under in size from many provisions of the FPA.
Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no opportunity for abusive transactions involving regulated affiliates of the seller. All of the Company’s facilities are qualifying facilities and have been granted market-based rate authority to make wholesale sales of electrical energy by FERC. For the Neal Hot Springs power plant, USG Oregon files electronic quarterly reports of the contract and transaction data.
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Energy Policy Act of 2005. EPAct 2005 contains provisions to prohibit the manipulation of the electric energy and natural gas markets and increase the ability of FERC to enforce and promote compliance with the statutes, orders, rules, and regulations that FERC administers. To implement the market manipulation provision of EPAct 2005, FERC amended its regulations to prohibit a company, in connection with the purchase or sale of natural gas, electric energy, or transportation or transmission services subject to FERC’s jurisdiction, from (1) using or employing any device, scheme, or artifice to defraud, (2) declaring any untrue statement of a material fact or omitting to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) engaging in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person. The EPAct 2005 made a number of other changes to laws affecting the regulation of electricity. These include, but are not limited to, giving FERC explicit authority to proscribe and enforce rules governing market transparency, giving FERC authority to oversee and enforce electric reliability standards, requiring FERC to promulgate rules providing for incentive ratemaking to encourage investments that promote transmission reliability and reduce congestion, giving FERC certain siting authority for transmission lines in critical transmission corridors, requiring FERC to promulgate rules granting incentives for transmission owners to join Regional Transmission Organizations, authorizing FERC to require unregulated utilities to provide open access transmission, and ensuring that load serving entities can retain transmission rights necessary to serve native load requirements. EPAct 2005 promulgated PUHCA 2005, which repeals PUHCA 1935, effective as of February 8, 2006.
Public Utility Holding Company Act. Under PUHCA 2005, the books and records of a utility holding company, its affiliates, associate companies, and subsidiaries are subject to FERC and state commission review with respect to transactions that are subject to the jurisdiction of either FERC or the state commission or costs incurred by a jurisdictional utility in the same holding company system. However, if a company is a utility holding company solely with respect to Qualifying Facilities, exempt wholesale generators, or foreign utility companies, it will not be subject to review of books and records by FERC under PUHCA 2005. Qualifying Facilities that make only wholesale sales of electricity are not subject to state commissions’ rate, financial, and organizational regulations and, therefore, would not be subject to any review of their books and records by state commissions pursuant to PUHCA 2005 as long as the Qualifying Facility is not part of a holding company system that includes a utility subject to regulation in that state.
Our power plants are Qualifying Facilities that make only wholesale sales of electricity and are not subject to rate, financial and organizational regulations applicable to electric utilities in those states. The power plants each sell their electrical output under power purchase agreements to electric utilities. The utilities are regulated by their respective state public utilities commissions. Neither USG nor our subsidiaries are considered utility holding companies under FPA, FERC, the EPAct2005, or PUHCA2005 and those regulations have had no direct adverse impact on our ability to develop geothermal resources or deliver power under our contracts.
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Geothermal Development Concession in Guatemala. The following summary of certain aspects of the electric industry in Guatemala should not be considered a full statement of the laws of Guatemala or all of the issues pertaining thereto.
In Guatemala, the General Electricity Law of 1996, Decree 93-96, created a wholesale electricity market and established a new regulatory framework for the electricity sector. The law created a regulatory commission, the CNEE, and a new wholesale power market administrator, the AMM, for the regulation and administration of the sector. The AMM is a private not-for-profit entity. The CNEE functions as an independent agency under the Ministry of Energy and Mines and is in charge of regulating, supervising, and controlling compliance with the electricity law, overseeing the market and setting rates for transmission services, and distribution to medium and small customers. All distribution companies must supply electricity to such customers pursuant to long-term contracts with electricity generators. Large customers can contract directly with the distribution companies, electricity generators or power marketers, or buy energy in the spot market. Guatemala has approved a Law of Incentives for the Development of Renewable Energy Power plants, Decree 52-2003, in order to promote the development of renewable energy power plants. This law provides certain benefits to companies utilizing renewable energy, including a 10-year exemption from corporate income tax and an import tax exemption for generation equipment, transmission lines and substation equipment. In September 2008, CNEE issued a resolution which approved the Technical Norms for the Connection, Operation, Control and Commercialization of the Renewable Distributed Generation and Self-producers Users with exceeding amounts of energy. This technical norm was created to regulate all aspects of generation, connection, operation, control and commercialization of electric energy produced with renewable sources to promote and facilitate the installation of new generation plants, and to promote the connection of existing generation plants which have exceeding amounts of electric energy for commercialization. It is applicable to projects with a capacity of up to 5 megawatts.
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 the Company’s projects, these credits have been sold separately, or bundled with the electricity to provide an additional source of revenue.
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We expect the following key incentives to influence our results of operations:
Production Tax Credits and Investment Tax Credits. A PTC provides 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 as much as 25 percent per year for the first 10 years. Facilities that begin construction after December 31, 2016 will not be eligible to use this production tax credit. The federal production tax credit available for geothermal energy in 2014 was 2.3 cents per kilowatt-hour. Alternatively, certain projects under construction before the end of 2016, are eligible to elect to take a 30% ITC in lieu of the PTC. The ITC may be taken after the plant has gone into operation and may be monetized. Both PTC and ITC credits require a tax equity partner to monetize.
The WGP Geysers project, San Emidio II project, and the Crescent Valley project all began construction prior to December 31, 2014, and the Company believes all three projects currently qualify for the 30% ITC in lieu of the PTC.
Renewable Energy Credits. Renewable Energy Certificates, or RECs, are tradable environmental commodities that represent proof that one megawatt-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 one megawatt-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, the Company 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 megawatt s average over the year). Holy Cross Energy began purchasing the renewable energy credits associated with the RREI power production on October 2007, and is expected to continue purchasing through 2017. Under the revised RREI 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 RREI 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 megawatt hours of RECs annually, representing the 49% ownership in RECs retained by RREI under the Idaho Power PPA.
The PPAs for the existing San Emidio and Neal Hot Springs power plants require the bundling of power sales and RECs. Therefore, under these contracts all RECs are delivered with the net power sold to the utility.
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Item 1A. Risk Factors
Investing in our common stock involves a high degree of risk. You should carefully consider the following risk factors, as well as the other information in this 10-K filing and related financial statements, before deciding whether to invest in shares of our common stock. The occurrence of any of the following risks, or other risks that are currently unknown or unforeseen by us, or that we currently believe are not material, could harm our business, financial condition, results of operation or growth prospects. In that case, you may lose all or a portion of your investment.
We have organized the following risk factors into categories to present related risks together. As a consequence of this, it is highly recommended that you read this entire risk factor section completely. The risks we have identified have been grouped into the following categories:
- Risks Related to Our Business;
- Risks Related to Our Growth;
- Risks Related to Our Power Purchase Agreements;
- Risks Related to Our Liquidity and Capital Resources;
- Risks Related to Government Regulation;
- Risks Related to Ownership of Our Common Stock.
Risks Related to Our Business
Our geothermal power plants have numerous pieces of equipment that are subject to breakdown or failure, many beyond our control. Failure of critical equipment could have a material impact on electrical generation and associated revenues. Our financial performance depends on the successful operation of our geothermal power plants, which are subject to numerous operational risks that are outside of our control. The continued operation of our geothermal power plants involves many risks, including breakdown or failure of power generation equipment, transmission lines, pipelines, pumps or other equipment or processes, and performance below expected levels of output or efficiency. If any of these risks were to materialize, they could have a material and adverse effect on our financial condition and results of operations.
A breakdown or failure in our geothermal power plants, our power generation equipment, the transmission lines, pipelines, pumps or other equipment or processes would also mean lost revenue because such a failure or breakdown could prevent us from selling electricity to our customers. For instance, because we rely on transmission lines owned by third parties to deliver all of the power that we generate to the purchasers of our electricity, any interruption in a transmission line’s service could result in lost revenue. Any such interruption in our ability to provide electricity to our customers on a timely basis could therefore materially and adversely affect our financial condition and results of operations.
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Our geothermal reserves could decline in the future. Declines greater than those that we expect would reduce our electricity production levels, which could have a material adverse effect on our operating revenues. We currently derive all of our revenue from geothermal energy and anticipate that we will continue to generate substantially all of our revenue from our current geothermal power plants for the next several years. Electricity production from geothermal properties can decline as the water resources in the earth are used, with the rate of water or temperature decline depending on reservoir characteristics and our ability to re-inject water effectively back into the earth. Therefore, we try to minimize the decline in water and temperature of the water in the ground and maximize the resources that we use to generate electricity. For each of our geothermal power plants, we estimate the productivity of the geothermal resource and the expected decline in productivity. We base our operating plans and financial models on these estimates of resources. However, because the development and operation of geothermal energy resources are subject to substantial risks and uncertainties, the productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the electrical power capacity desired. Factors that could adversely affect our geothermal reserves and result in decline rates greater than we forecast include, among others:
- significant changes in the characteristic of the geothermal resource;
- drilling in areas in and around our facilities by third parties; and
- the total amount of recoverable reserves.
An unexpected decline in productivity of our geothermal resources would therefore reduce the amount of electricity that we can produce and, therefore, the revenue that we will be able to generate from our geothermal resources.
We cannot assure you that our estimates of future generation resources, production capacity and cash flows are accurate. Estimates of future generation resources and the corresponding future net cash flows attributable to those resources are prepared by independent engineers, geologists and geoscientists. There are numerous uncertainties inherent in estimating these resources and the potential future cash flows attributable to such resources. Reserve engineering is a subjective process of estimating underground accumulations that cannot be measured in an exact manner. The accuracy of an estimate of quantities of resources, or of cash flows attributable to such resources, is a function of the available data, assumptions regarding future electricity prices and expenditures for future development and exploitation activities, and of engineering and geological interpretation and judgment. In order to undertake these estimates and studies, independent third parties must often rely to some extent on our own estimates and data, which we believe are reasonable and accurate but which may ultimately be proved to be incorrect. Actual future production, revenue, taxes, development expenditures, operating and royalty expenses, quantities of recoverable resources and the value of cash flows from such resources may vary significantly from the assumptions and underlying information set forth herein. In addition, different reserve engineers may make different estimates of resources and cash flows based on the same available data. We cannot assure you that we will accurately estimate the quantity or productivity of our geothermal resources.
Our results are subject to quarterly and seasonal fluctuations. Our results of operations are subject to seasonal variations. This is primarily because some of our power plants receive higher energy payments during certain summer and winter months. Some of our air cooled power plants may also experience reduced generation during hot summer months due to the lower differential between the temperature of the geothermal fluid and the ambient surroundings. Such seasonal variations could materially and adversely affect our business, financial condition, and cash flow.
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If our operating results fall below the public’s or analysts’ expectations, the market price of our common stock can fall in such periods.
Operating hazards, natural disasters or other interruptions of our geothermal power plant operations could result in potential liabilities, which may not be fully covered by our insurance. The geothermal business involves certain operating hazards such as:
- well blowouts;
- casing deformation;
- casing corrosion;
- uncontrollable flows of steam and hot water;
- spills, releases, and other accidental environmental impacts; and
- induced seismic activity.
The occurrence of any one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.
In addition, all of our operations are susceptible to damage from natural disasters, such as earthquakes and fires, which involve increased risks of personal injury, property damage and service interruptions. Any of these events could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development and acquisition, or could result in a loss of our properties. Our insurance policies are subject to deductibles, limits and exclusions that are customary or reasonable given the cost of procuring insurance, current operating conditions and insurance market conditions. There can be no assurance that such insurance coverage will continue to be available to us on an economically feasible basis, nor that all events that could give rise to a loss or liability are insurable, nor that the amounts of insurance will at all times be sufficient to cover each and every loss or claim that may occur involving the operations of our assets. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we do not have liability insurance, our business, results of operations and financial condition could be materially and adversely affected.
Threats of terrorism and cyber-attacks could impact our operations and could adversely affect our business and operating revenues. We are subject to the potentially adverse operating and financial effects of terrorist acts and threats, as well as cyberattacks. Our generation and transmission facilities, information technology systems and other infrastructure facilities could be directly or indirectly affected by such activities. Terrorist acts or other similar events could harm our business by limiting our ability to generate or transmit power and by delaying the development of new generating facilities. These events could result in a material decrease in revenues and significant additional costs to repair and insure our assets. We operate in an industry that requires the continued operation of sophisticated information technology systems vulnerable to security breaches, and failures. Those breaches and events may result from acts of our employees, contractors, or third parties. If our technology systems were to be breached and we were unable to recover in a timely way, we would be unable to fulfill critical business functions, which could adversely affect our business.
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Our geothermal resource leases may terminate if not placed into production, which could require 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 originally for a fixed term but provide for continuation for so long as we extract geothermal resources in “commercial quantities” or pursuant to other terms of extension. Most of the leases have been producing in “commercial quantities” for many years. The land covered by a few of our periphery leases have yet to produce “commercial quantities” of geothermal resources. Leases covering land that remains undeveloped and does not produce geothermal resources in commercial quantities may terminate. In the event that we determine that a terminated lease is subsequently required for a project, we would need to enter into one or more new leases in order to develop and exploit these geothermal resources. It may not be possible to enter into new leases or these new leases could be on less favorable financial terms than the prior leases, which could materially and adversely affect our ability to achieve commercial success on the applicable project.
Pursuant to the terms of our leases with the BLM, we are required to conduct our operations on BLM-leased land in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all mitigating actions required by the BLM to protect the surface of and the environment surrounding the relevant land. In the event of a default under any BLM lease, or the failure to comply with such requirements, or any non-compliance with any applicable regulations governing our use of the land, the BLM may, thirty days after notice of default is provided to our relevant project subsidiary, suspend our operations until the requested action is taken or terminate the lease, either of which could materially and adversely affect our business, financial condition, operating results and cash flow.
Claims have been made that thermal fracturing and well drilling at some geothermal plants may cause seismic activity and related property damage. There are approximately two-dozen steam geothermal plants operating within a fifty-square-mile region known as “The Geysers” located near the community 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 where our current projects are located 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.
As an SEC reporting company, failure to achieve and maintain effective internal control over financial reporting could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could in turn have a material and adverse effect on our business and stock price. We are required to document and test our internal control over financial reporting so that our management can certify as to the effectiveness of our internal control over financial reporting. We cannot be certain as to the timing of completion of our evaluation, testing and remediation actions, if any, related to internal controls and other SEC rules or the impact of the same on our operations. The assessment of our internal control over financial reporting will require us to expend significant management and employee time and resources and incur significant additional expense.
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During the course of our assessment of the effectiveness of our internal control over financial reporting, we may identify material weaknesses in our internal control over financial reporting, as well as any other significant deficiencies that may exist or hereafter arise or be identified, which could harm our business and operating results, and could result in adverse publicity, regulatory scrutiny and a loss of investor confidence in the accuracy and completeness of our financial reports. In turn, this could have a materially adverse effect on our stock price, and, if such weaknesses are not properly remediated, could adversely affect our ability to report our financial results on a timely and accurate basis. Although we believe we would be able to take steps to remediate any material weaknesses we may discover, we cannot assure you that this remediation would be successful or that additional deficiencies or weaknesses in our controls and procedures would not be identified. Moreover, we expect to continue to operate at a relatively low staffing level. Our control procedures have been designed with this staffing level in mind; however, they are highly dependent on each individual’s performance of controls in the required manner. The loss of accounting personnel, particularly our chief financial officer, would adversely impact the effectiveness of our control environment and our internal controls, including our internal control over financial reporting.
Our participation in joint ventures is subject to risks relating to working with a co-venturer. We are subject to risks in working with a co-venturer that could adversely impact our current projects as well as anticipated development of expansion projects. Involving a joint venturer may result in issues related to funding challenges, control issues, and other general disputes. It’s possible that the proposed project expansions may utilize the geothermal resource within the current joint venture boundaries. Our required contribution to the joint venture could also exceed returns from the joint venture.
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.
Counterparty credit default could have an adverse effect on the Company. Our revenues are generated under contracts with various counterparties. Results of operations would be adversely affected as a result of non-performance by any of these counterparties of their contractual obligations under the various contracts. A counterparty’s default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the counterparty, or due to circumstances caused by other market participants having a direct or indirect relationship with such counterparty. We seek to mitigate the risk of default by evaluating the financial strength of potential counterparties and utilizing industry standard credit provisions in our contracts, however, despite our mitigation efforts, defaults by counterparties may occur from time to time, and this could negatively impact our results of operations, financial position and cash flows.
Environmental liabilities and compliance costs could adversely affect our financial condition.
The geothermal business is subject to environmental hazards, such as leaks, ruptures and discharges of geothermal fluids and hazardous substances, emissions of toxic gases and disposal of hazardous substances. These environmental hazards could expose us to material liabilities for property damages, personal injuries or other environmental harm, including costs of investigating and remediating contaminated properties. In addition, we also may be liable for environmental damages caused by the previous owners or operators of properties we have purchased or are currently operating.
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A variety of stringent federal, state and local laws and regulations govern the environmental aspects of our business and impose strict requirements for, among other things:
- water extraction from surface streams and lakes;
- well drilling or workover, operation and abandonment;
- waste management;
- injection well classifications;
- land reclamation;
- financial assurance, such as posting bonds; and
- controlling air, water and waste emissions.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities and could lead to a curtailment or shut down of one or more of our plants. Additionally, our compliance with these laws may result in increased costs to our operations or our exploration, acquisition and development of new plants or may result in decreased production from our existing plants. We are unable to predict the ultimate cost of complying with these regulations. Pollution and similar environmental risks generally are not fully insurable.
We use industrial lubricants and other substances at our projects that are or could become classified as hazardous substances. If any hazardous substances are found to have been released into the environment at or by the projects, we could become liable for the investigation and removal of those substances, regardless of their source or time of release. If we fail to comply with these laws, ordinances or regulations, we could be subject to civil or criminal liability, the imposition of liens or fines, and large expenditures to bring the projects into compliance. Furthermore, we can be held liable for the cleanup of releases of hazardous substances at other locations where we arranged for disposal of those substances, even if we did not cause the release at that location. The cost of any remediation activities in connection with a spill or other release of such substances could be significant.
Our geothermal facilities have been in operation for a substantial length of time, and current or future local, state and federal environmental and other laws and regulations may require substantial expenditures to remediate the properties or to otherwise comply with these laws and regulations.
We depend on our senior management, geothermal resource and other technical employees. The loss of these employees could harm our business. Our future operating results depend to a large extent upon the continued contribution of key senior managers and personnel.
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Our success depends on the skills, experience and efforts of our people, particularly our senior management, geothermal resource and other technical employees. The geothermal industry is relatively small with a limited number of individuals with the management, technical and operational expertise necessary to run and operate facilities. In addition, many of our workers have significant and unique knowledge on how to manage and operate geothermal facilities. The loss of the services of one or more members of our senior management or of numerous employees with critical skills could have a material adverse effect upon us. As of the date of this report, the Company has executed employment agreements with key senior managers, but does not have key-man insurance on any of them.
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 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.
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.
Risks Related to Our Growth
Our growth prospects depend in part on our ability to further develop or acquire geothermal or other renewable energy power generation facilities and resources, which are subject to substantial risks. Because production from geothermal properties generally declines as both water and temperature is depleted, with the rate of decline depending on reservoir characteristics, our geothermal resources will decline as we continue to produce electricity unless we conduct other successful exploration and development activities or supplement the current amounts of water that we inject into the reservoir with sufficient water from other sources, or both. The acquisition and development of geothermal power generation facilities and resources is complex, expensive, time consuming and subject to substantial risks, many of which are outside of our control. In connection with the development of geothermal power generation facilities and resources, we must:
- identify suitable locations and appropriate technology;
- secure rights to exploit the resources;
- obtain sufficient capital and revenue sources;
- obtain appropriate governmental permits;
- maintain cost controls during construction;
- identify, hire and retain a qualified work force;
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- obtaining Power Purchase Agreements; and
- negotiating engineering, construction, and procurement agreements.
We may be unsuccessful in accomplishing any of these matters or in doing so on a timely basis. In our exploration efforts, we may not find commercially productive reservoirs or, if we do, the remote location of the resource may hinder our access to markets or delay our production. In addition, project development is subject to various environmental, engineering and construction risks. Although we may attempt to minimize the financial risks in the development of a power generation facility by obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable.
In addition, community opposition could delay or prevent us from obtaining the necessary approvals The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. If we are unable to complete the development of a facility, we would most likely not recover any of our investment in the project. We cannot assure you that we will be successful in the acquisition of additional geothermal resources or development of power generation facilities in the future or that we will be able to successfully complete construction of our facilities currently in development, nor can we assure you that any of these facilities of resources will be profitable or generate consistent and reliable cash flow.
We may decide not to implement, or may not be successful in implementing, our 5 year strategic plan for the growth of the Company. There are uncertainties and risks associated with the achieving our 5 year growth target. It is possible that we may not be successful in implementing one or more elements of the plan. It is also possible that we may decide to change, or not implement, one or more elements of the plan. The growth goals are provided as a target only, as we do not have direct control over the timing associated with the solicitation for power purchase agreements, transmission interconnection agreements, or use permits allowing for the building of a new power plant. These or other factors could mean that we decide to change or even abandon, or are otherwise unable to implement, one or more elements of the plan. Early stage project development costs may not be recovered, in whole or in part, if one or more elements of the plan are not successfully implemented. These costs could materially and adversely affect our business, financial condition, and cash flow and the price at which our common stock is traded.
Our business development activities may not be successful and our projects under construction may not commence operation as scheduled. We are in the process of developing and constructing a number of new power plants. Our success in developing a particular project is contingent upon successfully obtaining Power Purchase Agreements, satisfactorily negotiating engineering, procurement, and construction agreements, obtaining required permits, and securing adequate financing. These are followed by the satisfactory completion of the power plant construction and commissioning. We may be unsuccessful in accomplishing any of these tasks on a timely basis. Though we try to minimize our expenses before we can determine whether a project is feasible, we may incur significant expense prior for preliminary engineering, permitting and legal support prior to securing financing.
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Actual costs of construction or operation of a power plant may exceed estimates used in negotiation of power purchase and power financing agreements. If the actual costs of construction or operations exceed the costs used in our economic model, 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 may provide for a priority payback to our lender or partner. If the actual costs of construction or operations exceed the anticipated costs, we may not be able to operate profitably or receive the planned share of cash flow and proceeds from the project.
Our acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions. Our growth strategy may include acquiring geothermal and other renewable energy businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully. Furthermore, acquisitions involve a number of risks and challenges, including:
- diversion of management’s attention;
- the need to integrate acquired operations;
- potential loss of key employees of the acquired companies;
- greater geographic dispersion of employees;
- the potential that we may make bad acquisitions;
- potential lack of operating experience in a geographic market of the acquired business; and
- an increase in our expenses and working capital requirements.
Any of these factors could materially and adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.
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.
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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.
Our development activities are inherently very risky. The high risks involved in the development of a geothermal resource must be emphasized. The development of geothermal resources at our projects is 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 and testing, 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 resources can result in well depths that are relatively deep with well costs typically proportionate to the depth and geology encountered. Drilling may involve unprofitable efforts, not only from dry wells, but also from wells that do not produce sufficient volumes to generate net revenues that provide 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, chemical corrosion, 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.
Our exploration and development activities may not be commercially successful. Exploration activities involve numerous risks, including the risk that no commercially productive reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
- unexpected drilling conditions; irregularities in formations; equipment failures or accidents;
- compliance with governmental regulations;
- unavailability or high cost of drilling rigs, equipment or labor;
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, results of operations and financial position.
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Development and expansion are dependent on the ability to successfully complete drilling activity. Drilling and exploration are the main methods of establishing new reserves. However, drilling and exploration may be curtailed, delayed or cancelled as a result of:
- availability of equipment, particularly drilling rigs and well casing;
- lack of acceptable prospective acreage;
- inadequate capital resources;
- weather;
- compliance with governmental regulations; and
- mechanical difficulties;
- opposition to development.
The power generation industry is characterized by intense competition, and we encounter pricing pressure from electric utilities, community choice aggregators and other power producers and power marketers, that could materially and adversely affect our growth plans. The power generation industry is characterized by intense competition. In recent years, there has been increasing competition in the sale of electricity, in part due to excess capacity in a number of U.S. markets and an emphasis on short duration contracts or “spot” market power. This increased competition has contributed to a reduction in electricity prices. We expect that power purchasers interested in long-term power purchase agreements will engage in “competitive bid” solicitations to satisfy their demands. This competition could adversely affect our ability to obtain PPAs and the price paid for electricity by the relevant power purchasers. There is also increasing competition between electric utilities, municipal power companies, and community choice aggregatorsthat is putting further pressure on power purchasers to reduce the prices at which they purchase electricity from us.
Natural gas prices and oil prices are volatile, and lower prices for these commodities could affect the electricity prices we are able to obtain in future PPA contracts. Development of our new plants depends on the prices we are able to negotiate in our long term PPAs. The prices of those PPAs in today’s market are associated with both the demand for renewable energy, as well as the prices and demand for natural gas in the United States markets and the price of oil in our Central American markets. The markets for these commodities are volatile, and modest drops in prices can affect significantlyprice levels obtainable on new PPA contracts. Prices fluctuate widely in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, such as:
- domestic and foreign supply of oil and gas;
- price and quantity of foreign imports;
- actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
- domestic and foreign governmental regulations;
- political conditions in or affecting other oil producing and gas producing countries, including conflicts in the Middle East and conditions in South America and Russia;
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- weather conditions, as evidenced by recent hurricanes;
- technological advances affecting oil and gas consumption;
- overall U.S. and global economic conditions; and
- price and availability of alternative fuels.
Further, oil and gas prices do not necessarily fluctuate in direct relationship to each other. Because our geothermal reserves are valued similar to gas reserves, our financial results are more sensitive to movements in gas prices. Lower gas prices decrease our potential revenues available from future long term PPAs, but have little impact on the actual proved reserves we can produce economically, unlike typical oil and gas fields that require extensive ongoing drilling to sustain production.
Our foreign projects expose us to risks related to the application of foreign laws, taxes, economic conditions, labor supply and relations, political conditions and policies of foreign governments, any of which risks may delay or reduce our ability to profit from such projects. We have development projects outside of the United States. For example, the El Ceibillo project is located in Guatemala. Our foreign development is subject to regulation by various foreign governments and regulatory authorities and is subject to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to our projects in the United States, which may adversely affect our ability to receive revenues or enforce our rights in connection with our foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may develop or acquire, thus limiting our ability to control the development, construction and operation of such projects. Our foreign development is also subject to significant political, economic and financial risks, which vary by country, and include:
- Changes in government policies or personnel;
- Changes in general economic conditions;
- Restrictions on currency transfer or convertibility;
- Changes in labor relations;
- Political instability and civil unrest;
- Changes in the local electricity market;
- Breach or repudiation of important contractual undertakings by governmental entities; and
- Expropriation and confiscation of assets and facilities.
We plan to obtain political risk insurance in connection with our foreign project, when appropriate, but note that such political risk insurance does not mitigate all of the above-mentioned risks. In addition, insurance proceeds received pursuant to a political risk insurance policy, where applicable, may not be adequate to cover all losses sustained as a result of any covered risks and may at times be pledged in favor of the lenders to a project as collateral. Also, insurance may not be available in the future with the scope of coverage and in amounts of coverage adequate to insure against such risks and disturbances.
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Our foreign project may expose us to risks related to fluctuations in currency rates, which may reduce our profits from such projects and operations. Risks attributable to fluctuations in currency exchange rates can arise when any foreign subsidiary borrows funds or incurs operating or other expenses in one type of currency but receive revenues in another. In such cases, an adverse change in exchange rates can reduce such subsidiary's ability to meet its debt service obligations, reduce the amount of cash and income we receive from such foreign subsidiary or increase such subsidiary's overall expenses. In addition, the imposition by foreign governments of restrictions on the transfer of foreign currency abroad or restrictions on the conversion of local currency into foreign currency would have an adverse effect on the operations of our foreign project and may limit or diminish the amount of cash and income that we receive from such foreign projects.
Changes in costs and technology may significantly impact our business by making our power plants less competitive. A basic premise of our business model is that generating baseload power at central geothermal power plants achieves economies of scale and produces electricity at a competitive price. However, gas-fired systems may under certain economic conditions produce electricity at lower average short term prices than our geothermal plants. In addition, there are other technologies that can produce electricity at competitive prices, most notably fossil fuel power systems, hydroelectric systems, wind-turbines and photovoltaic (solar) cells. Research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity is gradually declining. It is possible that advances will further reduce the cost of alternate methods of power generation to a level below that of most geothermal power generation technologies such that the competitive advantage of our projects may be significantly impaired. Intermittent renewable energy sources such as solar and wind, have already seen such cost reductions allowing them to offer their intermittent power and substantially lower prices.
Risks Related to Our Power Purchase Agreements
A force majeure event, disruption of existing transmission or a forced outage affecting a project or unexpected operating expenses could reduce our net income and materially and adversely affect our business, financial condition, future results and cash flow. If a plant experiences a force majeure event, such as a fire, earthquake or flood, we would be excused from our obligations to deliver electricity under the PPAs to which we are parties. However, the power purchasers under those PPAs may/will not be required to make any energy payments with respect to the affected project or plant so long as the force majeure event continues and, pursuant to certain of our PPAs, will have the right to prematurely terminate the PPA altogether. Additionally, to the extent that a forced outage has occurred, a power purchaser may not be required to make any energy payments to the affected project, and if as a result the project fails to attain certain performance requirements under certain of our PPAs, the purchaser may have the right to prematurely terminate the PPA altogether. As a consequence, we may not receive any net revenues from the affected project or plant other than the proceeds from any business interruption insurance that may apply to the force majeure event or forced outage after the relevant waiting period, and we may incur significant liabilities in respect of past amounts required to be refunded.
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In addition, we rely on transmission lines owned by local utilities to deliver all of the electricity that we generate to the purchasers of our electricity. If the transmission system were to experience a force majeure event or a forced outage which prevented it from transmitting the electricity from our projects to a power purchaser, the power purchaser would not be required to make energy payments for that electricity with respect to the affected project so long as such force majeure event or forced outage continues.
Any of these events could significantly increase the expenses incurred by our projects or reduce the overall generating capacity of our projects and could significantly reduce or entirely eliminate the revenues generated by one or more of our projects, which in turn would reduce our net income and could materially and adversely affect our business, financial condition, future results and cash flow.
Payments under our PPAs may be reduced if we are unable to forecast our production adequately. Under the terms of certain of our PPAs, if we do not deliver electricity output within 90% to 110% of our forecasted amount, 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 receive reduced 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 replacement power costs, depending on the prevailing power market conditions. The agreement moves the power price to the market price instead of contracted price, 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.
Our failure to supply the contracted capacity under some of our PPAs with investor-owned electric utilities in states that have renewable portfolio standards may result in the imposition of penalties. The terms of certain of our PPAs require that we make payments to the relevant power purchaser in an amount equal to such purchaser's replacement costs for renewable energy that we are required to but do not provide as required under the PPA and which such power purchaser obtains from an alternate source. In addition, we may be required to make payments to the relevant power purchaser in an amount equal to its replacement costs relating to any renewable energy credits we do not provide as required under the relevant PPA. All of which could materially and adversely affect our business, financial condition, future results and cash flow.
Industry competition may impede our growth and ability to enter into PPAs 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 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 PPAs on terms favorable to us, or at all, it would negatively impact our revenue and our decisions regarding development of additional properties.
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Additionally, the credit quality of newly formed power purchasers may negatively impact our ability to finance our power purchase projects and may negatively impact their ability to pay for the contracted power in the future.
Changes in costs and technology of other baseload renewable electricity sources may significantly impact our business by making our power plants less competitive. A basic premise of our business model is that our geothermal power plants generate baseload power at a competitive price. While there are other renewable energy technologies that can also produce baseload electricity, such as biomass, fuel cell, and hydroelectric systems, most of these alternative technologies currently produce electricity at a higher average price than our geothermal plants. However, research and development activities are ongoing to seek improvements in such alternate technologies and their cost of producing electricity may gradually decline. It is possible that advances will further reduce the cost of alternate methods of power generation to a level that is equal to or below that of most geothermal power generation technologies. If this were to happen, the competitive advantage of our power plants may be significantly impaired.
Risks Related to Our Liquidity and Capital Resources
Substantial leverage and debt service obligations may adversely affect our cash flows, liquidity and operations. We have substantial indebtedness that we may be unable to service and that restricts our activities. Our ability to meet our debt service obligations and repay, extend, or refinance our outstanding indebtedness will depend primarily upon the operational performance of our geothermal power generation, the prices that we receive for the electricity that we generate, risk management activities, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. In addition, this indebtedness has important consequences, including:
- limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, entering into other renewable energy businesses, or other purposes;
- limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;
- increasing our vulnerability to general adverse economic and industry conditions;
- limiting our ability to or increasing the costs of refinance indebtedness; and
- limiting our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can transact and the volume of those transactions.
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 expansion of and the development of our 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.
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We may be unable to obtain the financing we need to pursue our growth strategy and any future financing we receive may be less favorable to us than our current financing arrangements, either of which may adversely affect our ability to expand our operations. Our geothermal power plants generally have been financed using leveraged financing structures, consisting of non-recourse debt obligations and partnership arrangements. Each of our projects under development and those projects and businesses we may seek to acquire will require substantial capital investment. Our continued access to capital with acceptable terms is necessary for the success of our growth strategy. Our attempts to obtain future financings may not be successful or on favorable terms, and 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. Market conditions and other factors may not permit future project and acquisition financings on terms similar to those previously received. If we are not able to obtain financing for our power plants on a non-recourse basis, we may have to finance them using direct equity investments which may have a dilutive effect on our common stock. or incur additional recourse debt.
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 production and injection wells. Future expansion of power production and other opportunities 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 or expand the current ownership of existing joint venture partners. 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.
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Our debt instruments impose significant operating and financial restrictions on us; any failure to comply with these restrictions could have a material adverse effect on our liquidity and our operations. The instruments governing our outstanding debt impose significant operating and financial restrictions on our geothermal operating subsidiaries. These restrictions could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs. These restrictions limit our ability to, among other things:
- make prepayments on or purchase indebtedness in whole or in part;
- pay dividends to us or make other distributions to us thereby limiting our ability to use available cash to pay dividends to stockholders, repurchase our capital stock or make other investments in geothermal projects or other renewable energy businesses;
- make certain investments, including capital expenditures;
- enter into transactions with affiliates;
- create or incur liens to secure debt;
- consolidate or merge with another entity, or allow one of our subsidiaries to do so;
- lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
- incur dividend or other payment restrictions affecting certain subsidiaries;
- engage in certain business activities; and
- acquire facilities or other businesses
In addition, any debt facilities that we enter into in the future are likely to contain similar or additional covenants.
Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us.
If we are unable to comply with the terms of the documents governing our indebtedness, we may be required to refinance all or a portion of our indebtedness or to obtain additional financing or sell assets. However, we may be unable to refinance or obtain additional financing because of our existing levels of indebtedness and the debt incurrence restrictions under our existing indentures and other debt agreements. If our cash flow is insufficient and refinancing or additional financing is unavailable, we may be forced to default on our indebtedness. Such a default or other breach of the covenants or restrictions contained in any of our existing or future debt instruments could result in an event of default under those instruments and, due to cross-default and cross-acceleration provisions, under our other debt instruments. Upon an event of default under our debt instruments, the debt holders could elect to declare the entire debt outstanding thereunder to be due and payable and could terminate any commitments they had made to supply us with further funds. If any of these events occur, we cannot assure you that we will have sufficient funds available to repay in full the total amount of obligations that become due as a result of any such acceleration, or that we will be able to find additional or alternative financing to refinance any accelerated obligations.
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Risks Related to Government Regulation
We are subject to complex government regulation which could adversely affect our operations. Our activities are subject to complex and stringent environmental and other governmental laws and regulations. The exploration and production of geothermal energy requires numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, including state and local agencies, whose regulations typically are more stringent than in other states or localities, as well as compliance with environmental protection legislation and other regulations. While we believe that we have obtained the requisite approvals and permits for our existing operations and that our business is operated in accordance with applicable laws, we remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. Existing laws and regulations could be changed or reinterpreted, or new laws and regulations may become applicable to us that could increase our costs associated with compliance or otherwise harm our business and results of operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned due to changing requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project.
Under certain circumstances, the United States Office of Natural Resource Revenue (“ONR”) may require that our operations on federal leases be suspended or terminated. These circumstances include our failure to pay royalties or our failure to comply with safety and environmental regulations. The requirements imposed by these laws and regulations are frequently changed and subject to new interpretations, and if such were to occur, could negatively impact our results of operations and cash flows.
Rules adopted by the BLM, 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.
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In the states of Idaho, Nevada California, 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); in California by the Division of Oil, Gas, and Geothermal Resources (Public Resources Code Title 14 Chapter 4); 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, and 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 megawatts or higher.
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 or bonding requirements, will not adversely affect our business by increasing cost and the time required to explore and develop geothermal projects. In addition, because some of our project properties were previously operated by others, we may be liable for environmental damage caused by such former operators.
Changes in the legal and regulatory environment affecting our projects could significantly harm our business financial position and results of operations. Our operations are subject to extensive regulation and, therefore, changes in applicable laws or regulations, or interpretations of those laws and regulations, could result in increased compliance costs, the need for additional capital expenditures or the reduction of certain benefits currently available to our projects. The structure of federal and state energy regulation currently is, and may continue to be, subject to challenges, modifications, the imposition of additional regulatory requirements, and restructuring proposals. We may not be able to obtain all regulatory approvals that may be required in the future, or any necessary modifications to existing regulatory approvals, or maintain all required regulatory approvals. In addition, the cost of operation and maintenance and the operating performance of geothermal power plants may be adversely affected by changes in certain laws and regulations, including tax laws.
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The reduction or elimination of government incentives could adversely affect our business, financial condition, future results and cash flows. Construction and operation of our geothermal power plants have benefited, and may benefit in the future, from public policies and government incentives that support renewable energy and enhance the economic feasibility of these projects. The most important tax rule that affects our business is the Production Tax Credit (“PTC”) or Investment Tax Credit (“ITC”), which is available to encourage the development of new geothermal plants. Legislation enacted as part of the 2016 “Fiscal Cliff” efforts resulted in the extension of the 30% PTC or ITC with eligibility for projects that started construction before December 31, 2016. There is not a cash grant component to the ITC credit so there is a risk related to monetizing the credit. The loss of the PTC or ITC is a risk that could result in making the development of new projects uneconomic. Additionally, current IRS guidance states that projects that are placed into service by December 31, 2018 do not have to show continuous construction. Projects placed into service after that date could have some or all of their tax credit eligibility challenged. Additional policies and incentives include accelerated depreciation tax benefits, renewable portfolio standards, carbon trading mechanisms, and rebates. Some of these measures have been implemented at the federal level, while others have been implemented by different states. The availability and continuation of these public policies and government incentives have a significant effect on the economics and viability of our development. Any changes to such public policies, or any reduction in or elimination of such Government incentives could affect us negatively.
Risks Related to Ownership of Our Common Stock
The public market for our common stock is not that liquid which could result in purchasers being unable to liquidate their investment. The market price for shares of our common stock may be highly volatile and could be subject to wide fluctuations. Some of the factors that could negatively affect our share price include:
- actual or anticipated variations in our reserve estimates and quarterly operating results;
- changes in electricity prices;
- changes in our funds from operations or earnings estimates;
- publication of research reports about us or the exploration and production industry;
- increases in market interest rates which may increase our cost of capital;
- changes in applicable laws or regulations, court rulings and enforcement and legal actions;
- changes in market valuations of similar companies;
- adverse market reaction to any increased indebtedness we incur in the future;
- additions or departures of key management personnel;
- actions by our stockholders;
- speculation in the press or investment community;
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- large volume of sellers of our common stock pursuant to our resale registration statement with a relatively small volume of purchasers; and
- general market and economic conditions.
The market price of our common stock could be volatile, which could cause the value of your investment to decline. Securities markets worldwide experience significant price and volume fluctuations. This market volatility, as well as general economic, market or political conditions, could reduce the market price of our common stock in spite of our operating performance. In addition, our operating results could fall short of the expectations of market analysts and investors, and in response, the market price of our common stock could decrease significantly. You may be unable to resell your shares of our common stock at or above the initial offering price.
The market for our common stock is volatile. The trading price of our common stock on the NYSE MKT LLC (“NYSE MKT”) is subject to 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.
You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock. We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders. We are currently authorized to issue 250,000,000 shares of common stock. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes.
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 (“SOX”) and the 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, as applicable, which are required under Section 404 of SOX. The Company has documented and tested its internal control procedures in order to satisfy the requirements of Section 404 of SOX. SOX requires an annual assessment by management of the effectiveness of the Company’s internal control over financial reporting, as well as an attestation report by the Company’s independent auditors on internal controls over financial reporting. 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 SOX. 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.
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We do not anticipate paying any dividends on our common stock in the foreseeable future. We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to expand our business. We may enter into other borrowing arrangements in the future that restrict our ability to declare or pay cash dividends on our common stock.
A substantial percentage of our shares are held by a small group of stockholders whose interests may conflict with the interests of our other stockholders. As of December 31, 2016, our largest three shareholders consisted of JCP Investment Management, LLC beneficially owning 2,855,005 shares (15.1%), Bradley Louis Radoff beneficially owning 1,825,000 shares (9.6%), and Private Management Group, Inc. beneficially owning 1,591,847 shares (8.4%), collectively totaling approximately 33.1% of our outstanding common stock. As a result of these stockholders’ beneficial ownership of our outstanding common stock, they could exert significant influence on the election of our directors and decisions on matters submitted to a vote of our shareholders, including mergers, consolidations and the sale of all or substantially all of our assets. This concentration of ownership of our shares could delay or prevent proxy contests, mergers, tender offers, or other purchases of our shares that might otherwise give our stockholders the opportunity to realize a premium over the then-prevailing market price for our shares. This concentration of ownership may also adversely affect our stock price. Future sales of common stock by these stockholders could cause our stock price to decline.
Future sales of common stock by some of our insider stockholders could cause our stock price to decline. As of the date of this report, our directors and officers collectively held 4,614,133 shares of and options for our common stock, representing approximately 24.3% of issued and outstanding common stock. Sales of such shares in the public market, as well as shares we may issue upon exercise of outstanding options, could cause the market price of our common stock to decline.
If securities or industry equity analysts do not publish research or reports about our business, our stock price and trading volume could be adversely affected. To the extent one develops, the trading market for our common stock will depend in part on the research and reports that securities or industry equity analysts publish about us or our business. Our common stock is not currently and may never be covered by securities and industry equity analysts. If no securities or industry equity analysts commence coverage of our company, the trading price of our stock would be negatively impacted. In the event we obtain securities or industry equity analyst coverage of our common stock, if one or more of the equity analysts who covers us downgrades our stock, our stock price would likely decline. If one or more of these equity analysts ceases coverage of our company or fails to regularly publish reports on us, interest in the purchase of our stock could decrease, which could cause our stock price or trading volume to decline.
Provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. The existence of some provisions under Delaware law, our certificate of incorporation and bylaws could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. Our certificate of incorporation and bylaws prohibit our stockholders from taking action by written consent absent approval by all of our Board of Directors. Further, our stockholders will not have the power to call a special meeting of stockholders.
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The sale of our common stock under our ATM to Lincoln Park Capital (“LPC”) may cause dilution and the sale of the shares of common stock acquired by LPC could cause the price of our common stock to decline. The ATM allows for the sale of up to $10,000,000 in shares of our common stock that we may issue and sell to LPC pursuant to the terms of the Purchase Agreement, less any shares already sold under the Purchase Agreement. The number of shares ultimately offered for sale by LPC is dependent upon the number of shares purchased by LPC under the Purchase Agreement. The purchase price for the common stock to be sold to LPC pursuant to the Purchase Agreement will fluctuate based on the price of our common stock. It is anticipated that shares will be sold over a period of up to 30 months from the date of the initial purchase under the Purchase Agreement. Depending upon market liquidity at the time, a sale of shares under the offering at any given time could cause the trading price of our common stock to decline. We can elect to direct purchases in our sole discretion. After LPC has acquired such shares, it may sell all, some or none of such shares. Therefore, sales to LPC by us under the Purchase Agreement may result in substantial dilution of the percentage ownership of other holders of our common stock. The sale of a substantial number of shares of our common stock under the offering, or anticipation of such sales, could make it more difficult for us to sell equity or equity-related securities in the future at a time and at a price that we might otherwise wish to effect sales. However, we have the right to control the timing and amount of any sales of our shares to LPC and the Purchase Agreement may be terminated by us at any time at our discretion without any cost to us.
Item 1B. Unresolved Staff Comments
None.
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Item 2. Property
The Company has interests in nine different geothermal resource areas in the Western United States and one area in Guatemala, Central America. The resource areas in the United States are located in Idaho (1), Oregon (2), and Nevada (5) and California (1). The properties include the Raft River area located in southeastern Idaho, the two properties located in southeastern Oregon, and five properties in northwestern Nevada, the WGP Geysers area located in northern California at the Geysers, and the El Ceibillo area located in central Guatemala (near Guatemala City).
The Company operates three commercial power plants located in the Western United States. The Raft River Unit I, Idaho plant became commercially operational on January 3, 2008. The Neal Hot Springs, Oregon plant achieved commercial operation on November 16, 2012. The San Emidio, Nevada plant was acquired in May 2008. The acquired facility was replaced with a new power plant, located on private land that became commercially operational in May 2012.
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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 22
megawatt (net) annual average geothermal power plant was developed by USG Oregon
LLC, and is currently in operation at this site. The project has four production
wells and nine injection wells at the project.
Significant Lease/Royalty Terms
Approximately 521
acres of geothermal rights at Neal Hot Springs are owned by Cyprus Gold
Exploration Corporation (50%), JR Land and Livestock (25%), and USG Oregon LLC
(25%). Royalty for the two private leases is paid on the gross revenue from
energy sales paid by Idaho Power Company under the PPA. The JR Land &
Livestock lease has a 3% royalty for the first five years of production,
increases to 4% for years 6-15, and then to 5% for the remainder of the lease
term. The Cyprus lease establishes a 2% royalty for the first ten years and then
escalates to 3% for the remainder of the lease.
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San Emidio, Nevada
In 2008, the
Company acquired a 3.6 megawatt operating geothermal power plant and all
associated private and federal geothermal leases and certain ground water rights
in the San Emidio Valley and at Gerlach, Nevada. The San Emidio project is
located approximately 75 air miles north of Reno, Nevada. The Gerlach property
is locate immediately northwest of Gerlach Nevada. The San Emidio assets include
the geothermal power project, 17,846 (27.9 square miles) acres of geothermal
leases, and ground water rights used for cooling water. The Gerlach assets
include 2,986 acres (4.7 square miles) of BLM and private geothermal leases. The
Gerlach leases are located along a geologic structure known to host geothermal
features including the Great Boiling Spring and the Fly Ranch Geyser.
In 2012, USG completed the San Emidio Phase I repower project; a 9.0 megawatt (net) annual average facility located on private land owned by USG Nevada. Phase I repowering was completed utilizing the existing production and injection wells.
Significant Lease/Royalty Terms
A geothermal unit
was established for the operating project by the Company in 2010 with the
approval and oversight of the Bureau of Land Management. The Unit allows USG
Nevada LLC to allocate expenses among the federal and private geothermal leases
within the Unit and legally establishes the percentage of private and federal
land that contributes to geothermal production known as the Participating Area.
The Participating Area at San Emidio totals 583.68 acres and includes 336.93 acres (57.7%) of private property and 246.75
acres (42.3%) of federally managed land.
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The lease agreement with the Kosmos Company establishes a 1.75% royalty on gross electricity sales for the first 120 months of production and 3.5% royalty thereafter. The federal leases have a 10% netback royalty. The netback calculation is based on gross electricity sales less the transmission and generation cost deductions. In 2014 the equivalent federal royalty is 1.6% of gross electricity sales.
Raft River, Idaho
The Raft River
project comprises two packages of property that include the Raft River Energy I
LLC (“RREI”) leases, and leases held by the Company. RREI operates the Unit I
facility at Raft River which became commercially operational on January 3, 2008.
Leases assigned to RREI by the Company included eight private geothermal leases,
one of which is owned by the Company. The Company retains direct control over
four private leases and one federal lease outside the RREI position.
All of the leases may be extended indefinitely as long as production is maintained from the lease either individually or as a geothermal unit. The Company and RREI hold a total of 6,002 acres; 1,686 acres of federal geothermal rights and 4,316 acres of private leases.
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Significant Lease/Royalty Terms
The private leases
have 10 year primary terms with the rights of unitization and extensions.
Private leases have varying royalty rates commensurate with other federal and
private leases held by the Company and our subsidiaries. Most of the private
leases are subject to a 10% netback royalty which is based on gross electricity
sales less the transmission and generation cost deductions. In 2014, USG’s
equivalent federal netback royalty was equivalent to 1.6% of gross electricity
sales where it was applied.
The federal lease, established on August 1, 2007, is held by the Company and 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 royalty under the lease is 1.75% of gross proceeds for the first 10 years of production and 3.5% thereafter. At Raft River, royalty rates have not exceeded rental payments.
A private geothermal unit was established for the operating project in December 2015. The Unit establishes the geologic production area. A Participating Area of 1640 was established in May 2015. The Participating Areea is that area that is reasonably expected to contribute to power production. Production is allocated based on the percentage of each property in relation to the entire Participating Area.
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El Ceibillo, Republic of Guatemala
The Company successfully acquired a geothermal energy rights concession in the Republic of Guatemala, which was granted by the Guatemalan government. It consists of 24,710 acres (100 square kilometers) and is located 14 miles southwest of Guatemala City, the capital. The concession provides sub-surface geothermal rights only, and does not provide access to the surface that is owned by private landowners. The concession had an initial five year term for the development and construction of a power plant, which was extended by three years in 2015. There are no royalties due to the government for use of the geothermal resource.
The primary area of interest within the concession is the El Ceibillo project, 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 office and staff are located in Guatemala City, and 80 acres of surface land within the concession area is under lease.
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Crescent Valley and Lee Hot Springs, Nevada
On December 16, 2014, U.S. Geothermal completed the acquisition of EPR
and EPR’s lease holdings at Crescent Valley and Lee Hot Springs, Nevada.
The Crescent Valley property encompasses 21,319 acres of private and federal geothermal resources leased by EPR and 2,640 acres of geothermal resources leased by U.S. Geothermal Inc. Upon closing the acquisition the Company began drilling the projects first production well. The well is located on private surface and mineral estate in section 3, Township 28 North Range 49 East and is intended to qualify potential future power plant construction for the 30% renewable energy investment tax credit. The Crescent Valley property includes 55 independent leases ranging in size from 10 acres to 4,100 acres and an average parcel size of 314 acres. EPR’s private leases have a 15 year term with annual rent that escalates at year five and at year 10.
Significant Lease/Royalty Terms
Annual lease rental
payment obligations at Crescent Valley are approximately $109,138 and royalty
obligations during potential future power production vary for private leases
from 3% to 5% of gross sales. Royalty rates for federal geothermal leases are
1.75% of gross revenue for the first 10 years and 3.5% thereafter.
The Lee Hot Springs property encompasses 2,560 acres of federal lands located approximately 17 miles south of Fallon, NV. The federal leases are N-73679 and N-73930. The annual rental is $2,560 and a standard federal royalty is 1.75% of gross revenue for the first 10 years and 3.5% thereafter.
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WGP Geysers, California
Western
GeoPower Inc. (“WGP”) is a wholly owned subsidiary of U.S. Geothermal Inc. WGP’s
property includes surface and geothermal rights that consist of two federal
geothermal leases (CA-51000 & CA-51001), and one private geothermal lease
with no expiration. The total project acreage is 3,808 acres. The site has been
re-permitted with Sonoma County for construction and operation of up to a 38.5
megawatt geothermal power plant.
The project is located at the site of the former Pacific Gas and Electric (PG&E) Unit 15 project, which once had a 62 megawatt (gross) capacity power plant. During 10 years of operation, the PG&E plant declined in production to approximately 38 megawatts before it was shut down in l989 and all of the wells were plugged and abandoned. The project is located within the broader Geysers geothermal field which covers a total of approximately 20,000 acres in the Mayacamas Mountains in Sonoma County and Lake County, California, approximately 75 miles north of San Francisco. The Geysers geothermal resource is the largest producing geothermal field in the world, and has been generating greater than 850 megawatts of power for more than 30 years.
Significant Lease/Royalty Terms
There is no annual
rental or royalty for the 421 acre private parcel owned by WGP. The Abril Ranch
rental payment for 410 acres of surface and geothermal rights was $16,783 in
2014 and is annually adjusted by the San Francisco/San Jose CPI index. The
Filly-Brown properties include 214 acres of surface access rights and 50% of the mineral
rights owned by Western GeoPower. The Geothermal royalty payments for Abril
Ranch are being adjusted to 4.25% of gross revenue at a power price of $100/MW
or less and is consistent with market conditions.
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Vale Butte, Oregon
Vale Butte and the
Vale Butte Geothermal Resource Area is located in Eastern Oregon and borders the
east side of the City of Vale. In the first quarter of 2014, U.S. Geothermal
Inc. acquired 393 acres of geothermal energy and surface rights under six (6)
leases. The leased area is immediately adjacent to the City of Vale and includes
private surface and mineral estate, Vale City owned resources and Malheur County
owned resources. The Vale Butte resource area has been used for direct use
heating for many years. Geochemical analysis indicates a potential reservoir
temperature of 311ºF to 320ºF and historical drilling in the area has
encountered ground (rock) temperatures in excess of 300°F. Fault structures and
hydrologic characteristics have been identified that are similar to the Neal Hot
Springs site, and those geologic structures are contained within the acquired
leases.
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Significant Lease/Royalty Terms
Four private leases
and the Vale City lease are issued for a period of 10 years with renewal options
while the Malheur County lease was issued for a period of 40 years with renewal
options. The lease agreements are consistent in terms of financial and
development requirements and have a 2% royalty payment on actual energy paid for
by Idaho Power for the first 10 years of commercial production.
Boise Administration Office, Idaho
On
August 12, 2013, the Company signed a five year lease agreement for office space
and janitorial services. The lease payments are due in monthly installments
starting February 1, 2014. The monthly payments that begin February 1, 2014 have
two components which include a base rate of $3,234 that is not subject to
increase and a rate beginning at $6,418 that is adjusted annually according to
the cost of living index. The contract includes a five year extension option.
Land and Leases
The Company and its domestic subsidiaries control 65,434 acres of land in California, Idaho, Nevada, and Oregon. U.S. Geothermal owns approximately 2,536 acres of surface rights and 2,539 acres of geothermal rights while approximately 64,064 acres are controlled through geothermal development leases signed with the BLM, local governmental entities and private owners. The company’s average per acre lease rate is $9.00 per acre/year.
BLM Leases
The Company and its
subsidiaries have 26 federal geothermal leases issued in accordance with the
Geothermal Steam Act by the BLM.
BLM geothermal leases grant the lessee the right to drill for, extract, produce, remove, utilize, sell, and dispose of geothermal resources from the leased lands, along with the right to build and maintain necessary improvements on the leased land. Ownership of the geothermal resources and other minerals beneath the land is retained in the federal mineral estate. The geothermal lease grants exclusive geothermal development rights. The BLM will, through authority granted by federal regulations and planning requirements, ensure that other federal activities do not unreasonably interfere with the geothermal lessee’s uses of the same land. Most federal leases include stipulations and are governed by federal regulations, that require geothermal development to be conducted in a workmanlike manner and in accordance with all applicable laws and BLM directives and to take all actions required by the BLM to protect the surface of and the environment surrounding the land. Surface protections and environmental protection requirements include protection of water quality, cultural and archeological resources, threatened or endangered plants or animals, migratory birds, wildlife, and visual quality standards.
The BLM also authorizes geothermal lessees to enter into unit agreements on federal lands to cooperatively develop a geothermal resource. The BLM reserves the right to specify rates of development and to require the geothermal lessee to commit to a unitization agreement.
Typical BLM leases have a primary term of ten years and may be renewed as long as geothermal resources are being explored. If resources are produced or utilized in commercial quantities, the lease can be renewed for up to forty years. If at the end of the forty-year period geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease for a second forty-year term, under terms and conditions as the BLM deems appropriate. During the lease term the lessee is required to pay an annual per acre rental fee. The fee escalates according to a schedule until geothermal production begins. After production has commenced, the geothermal lessee is required to pay royalties on the amount or value of energy production, and any by-products that may be derived from geothermal production.
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BLM leases issued after August 8, 2005 (The Energy Policy Act of 2005) also have a primary term of ten years. If the geothermal lessee does not reach commercial production within the primary term, the BLM may grant two five-year extensions. If the lessee is drilling a well for the purposes of commercial production, the lease may be extended for five years and thereafter as long as steam is being produced and used in commercial quantities the lease may be extended for up to thirty-five years. If, at the end of the extended thirty-five year term, geothermal steam is still being produced or utilized in commercial quantities and the lands are not needed for other purposes, the geothermal lessee will have a preferential right to renew the lease under terms and conditions as the BLM deems appropriate.
BLM leases are issued either competitively or non-competitively. Under the Energy Policy Act of 2005 Lessees who obtain leases issued through a non-competitive process pay an annual rental fee equal to $1.00 per acre for the first ten years and $5.00 per acre each year thereafter. Lessees who obtain a lease through a competitive bid process pay a rental of $2.00 per acre for the first year, $3.00 per acre for the second through tenth year and $5.00 per acre each year thereafter. For BLM leases issued, effective, or pending on August 8, 2005, royalty rates are fixed between 1.0 -2.5% of the gross proceeds from the sale of electricity during the first ten years of production under the lease.
The royalty rate set by the BLM for geothermal resources produced for the commercial generation of electricity but not sold in an arm’s length transaction is 1.75% for the first ten years of production and 3.5% thereafter. The royalty rate for geothermal resources sold by the geothermal lessee or an affiliate in an arm’s length transaction is 10.0% of the gross proceeds from the arm’s length sale.
Private Geothermal Leases
U.S.
Geothermal and its subsidiaries hold geothermal rights through leases with 73
individuals and companies. The leases authorize geothermal development and
operations on privately owned geothermal estates. In some cases, the surface
ownership is split from the mineral or geothermal ownership.
Geothermal leases grant the exclusive right and privilege to drill for, produce, extract, take and remove water, brine, steam, steam power, minerals (other than oil), salts, chemicals, gases (other than gases associated with oil), and other products produced or extracted through geothermal development. The Company and its project subsidiaries are also granted non-exclusive rights pertaining to the construction and operation of plants, structures, and facilities on the leased land. The leases also grant the right to dispose of waste brine and other waste products as well as the right to re-inject into the leased land water, brine, steam, and gases in a well or wells for the purpose of maintaining or restoring pressure in the productive zones beneath the leased land or other land in the vicinity.
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Lessors reserve the right to conduct other activities on the leased land in a manner that does not unreasonably interfere with the geothermal lessee’s uses of the same land. Activities include agricultural use (farming or grazing), recreational use and other energy developments. Geothermal leases are typically issued for a primary term of 10 years and continue for as long as leased products are being produced or the lessee is drilling, exploring, extracting, processing, or reworking operations on the leased land.
Lease payments typically include annual rental that is based on a rate per acre under lease and royalty payments on gross revenue from the generation of electricity. Leases also include a provision for royalty payment on all revenue from geothermal by-products. Leases typically have requirements for drilling, extraction or processing operations on the leased land within the primary term or to conduct operations with reasonable diligence until lease products have been found, extracted and processed in quantities deemed “paying quantities” by the lessee. The lessee has the right at any time within the primary term to terminate the lease and surrender the relevant land. If the lessee has not commenced operations on leased land within the primary term, the annual rentals typically increase. The purpose of the increasing annual rental is to encourage development which, in some cases may generate higher payment to the lessor in the form of monthly royalty.
Our leases typically require the lessee to carry insurance, conduct operations in accordance with all local, state, and federal regulations, prevent waste, protect environmental quality, and promptly address any default by lessee. The lessor and lessee are protected from automatic lease termination through a notice requirement which must be received by the lessee by certified mail, and a 30 day period in which the lessee must make diligent efforts to correct the alleged default.
Geothermal Development Concession in Guatemala
U.S. Geothermal Guatemala S.A. has acquired a 24,700 acre geothermal
concession from the Ministry of Energy and Mines Guatemala C.A. The site is
located 12.5 miles southwest of Guatemala City and 2.5 miles west southwest of
the City of Amatitlan. The geothermal concession grants the rights for
subsurface geothermal development, and established milestones for development
and production. The Company has negotiated and acquired a surface lease from one
landowner and controls 80 acres enabling geothermal development. The lease is
similar in term and conditions to our leases with private landowners in the
United States for surface fee land.
Item 3. Legal Proceedings
As of March 9, 2017, 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.
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Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
NYSE MKT
The following table sets
forth information relating to the trading of our common stock from January 1,
2014 through December 31, 2016, as adjusted for the 1-for-6 share consolidation
described in Note 8 of the consolidated financial statements, for the
Company’s common stock trading on the NYSE MKT, under the trade symbol
“HTM”:
| Sale Prices on the NYSE MKT | ||
| High | Low | |
| Year Ended December 31, 2016 | ($) | ($) |
| First Quarter | 4.08 | 3.12 |
| Second Quarter | 5.16 | 4.08 |
| Third Quarter | 5.34 | 4.20 |
| Fourth Quarter | 4.33 | 3.72 |
| Year Ended December 31, 2015 | ||
| First Quarter | 3.06 | 2.64 |
| Second Quarter | 3.30 | 2.76 |
| Third Quarter | 4.02 | 3.06 |
| Fourth Quarter | 3.84 | 3.36 |
TSX
The Company voluntarily delisted from the
TSX effective December 31, 2015. The following table sets forth information
relating to the trading of our common stock from January 1, 2014 through
December 31, 2015, as adjusted for the 1-for-6 share consolidation described in
Note 8 of the consolidated financial statements, for the Company’s common
stock trading on the TSX under the trade symbol “GTH”:
| Sale Prices on the TSX | ||
| High | Low | |
| Year Ended December 31, 2015 | ($) | ($) |
| First Quarter | 3.78 | 3.06 |
| Second Quarter | 4.02 | 3.42 |
| Third Quarter | 5.40 | 3.78 |
| Fourth Quarter | 5.28 | 4.50 |
As of March 1, 2017, we had approximately 16,250 beneficial stockholders.
The Company has never paid and does not intend to pay dividends on its common stock in the foreseeable future. Although the Company’s certificate 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 shares of common stock are entitled to an equal share in any dividend declared and paid.
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Item 6. Selected Financial Data
| For the Years Ended
December 31, |
|||||
| 2016 | 2015 | 2014 | 2013 | 2012 | |
| Operating Revenues | $ 31,481,675 | $ 31,200,098 | $ 30,968,782 | $ 27,370,934 | $ 9,758,946 |
| Operating Expenses | 16,447,329 | 21,207,738 | 21,972,764 | 23,240,285 | 14,090,471 |
| Income (Loss) from Continuing Operations | 4,160,348 | 6,336,498 | 4,589,297 | 4,130,649 | (4,331,525) |
| Income (Loss) attributable to U.S. Geothermal Inc. | 463,331 | 1,847,229 | 11,613,711 | 1,946,579 | (2,958,567) |
| * Income (Loss) per share attributable to U.S. Geothermal Inc. | 0.02 | 0.10 | 0.67 | 0.11 | (0.20) |
| Cash dividends declared and paid per common share | - | - | - | - | - |
* - Adjusted for the 1-for-6 share consolidation described in Note 8 of the consolidated financial statements.
| As of December 31, | |||||
| 2016 | 2015 | 2014 | 2013 | 2012 | |
| Total Assets | $ 243,424,332 | $ 228,217,127 | $ 232,914,304 $ | 232,765,297 | $ 240,496,096 |
| Total Long-term Obligations | 105,350,989 | 91,091,982 | 95,776,351 | 99,247,344 | 104,318,206 |
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| * Income (loss) per share attributable to U.S. Geothermal Inc. |
Operating Revenues |
Gross Profit (Loss) |
Income (Loss) from Operations |
Net Income (Loss) Attributable to U.S. Geothermal, Inc. | |
| Year Ended December 31, 31, 2013 | |||||
| 1st Quarter | 0.08 | 7,086,990 | 4,102,509 | 2,235,079 | 1,388,523 |
| 2nd Quarter | (0.08) | 4,973,076 | 1,012,227 | (1,966,627) | (1,376,359) |
| 3rd Quarter | 0.00 | 5,760,495 | 2,461,352 | 186,198 | (28,137) |
| 4th Quarter | 0.12 | 9,550,373 | 5,635,824 | 3,675,999 | 1,962,552 |
| Year Ended December 31, 2014 | |||||
| 1st Quarter | 0.08 | 8,501,965 | 4,783,941 | 2,547,091 | 1,339,420 |
| 2nd Quarter | (0.07) | 5,845,874 | 1,571,096 | (1,308,330) | (1,152,813) |
| 3rd Quarter | 0.00 | 6,737,005 | 2,939,672 | 695,817 | 81,780 |
| 4th Quarter | 0.64 | 9,883,938 | 5,731,213 | 2,654,719 | 11,345,324 |
| Year Ended December 31, 2015 | |||||
| 1st Quarter | 0.04 | 8,473,861 | 4,615,637 | 1,763,381 | 734,135 |
| 2nd Quarter | (0.01) | 5,861,180 | 1,801,996 | (548,347) | (233,820) |
| 3rd Quarter | 0.02 | 6,929,847 | 2,819,445 | 595,079 | 280,864 |
| 4th Quarter | 0.05 | 9,935,210 | 6,090,908 | 3,140,385 | 1,066,050 |
| Year Ended December 31, 2016 | |||||
| 1st Quarter | 0.01 | 8,503,276 | 4,523,697 | 1,277,795 | 151,392 |
| 2nd Quarter | (0.03) | 5,664,280 | 1,862,436 | (684,667) | (493,717) |
| 3rd Quarter | (0.01) | 6,733,294 | 2,869,422 | 178,230 | (150,498) |
| 4th Quarter | 0.05 | 10,580,825 | 5,778,791 | 2,813,990 | 956,154 |
* - Adjusted for the 1-for-6 share consolidation described in Note 8 of the consolidated financial statements.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Historical Overview
On March 5, 2002,
U.S. Geo-Idaho entered into a letter agreement with the owner of the Raft River
project located in southeastern Idaho, pursuant to which Geo-Idaho agreed to
acquire all of the real property, personal property and permits that comprised
the owner’s interest in that project.
The Company signed a 20 year PPA with Idaho Power on December 29, 2004 to sell power from the Phase I power plant at Raft River located near Malta Idaho. Raft River Energy I LLC (“RREI”) was created on August 18, 2005 for the purpose of developing Raft River Unit I. The limited liability company is a joint venture with Raft River I Holdings, LLC, which is a subsidiary of Goldman Sachs. RREI commenced commercial operations on January 3, 2008. The plant currently operates at a reduced output of approximately 9.4 megawatt net.
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In May 2008, the Company acquired geothermal assets, including an old 3.6 net megawatt nameplate generating capacity power plant, located in Washoe County, Nevada for approximately $16.6 million, which included certain ground water rights. The upgraded, new plant became commercially operational on May 25, 2012. The plant was originally estimated to operate at 8.6 net megawatts, but has been rerated to 10.0 megawatts due to higher than expected efficiency. On February 15, 2013, USG Nevada LLC signed an agreement with SAIC as part of a settlement, for a $2,000,000 note that will be paid in quarterly installments that are scheduled through 2018. A long-term note held by Prudential Financial Group was finalized on September 26, 2013. The Prudential loan will be repaid with quarterly payments that are scheduled through 2037.
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 began on the first full size production well which was completed on May 23, 2009. In February 2009, the Company submitted a loan 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 the DOE to enter into due diligence review on a project loan. Construction of a drill pad was completed in August 2009. In September 2009, the Company began drilling its major production well. Enbridge Inc. became an equity partner in the project in April 2009. Equity ownership interest in the project has the Company owning 60%, and Enbridge owning 40%. The power plant became commercially operational on November 16, 2012.
In April 2010, the Company was granted a geothermal energy rights concession in the Republic of Guatemala located in Central America. The Company signed a Memorandum of Understanding with a broker of electricity in Central America to negotiate a PPA for the El Ceibillo Project located near Guatemala City in October 2012. The framework of the agreement outlines a 15 year term to deliver up to 50 megawatts of power at competitive prevailing energy prices in the region. Geophysics activities and the drilling of the first exploration well occurred during 2013. A 25 megawatt flash steam plant is targeted to be in operation in the first half of 2018.
On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp.’s (“Ram”) that held all interests in the WGP Geysers project located in Northern California for a total of $6.78 million. The assets acquired included four production/injection wells, restricted cash, land, geothermal water rights, and an inventory of new drill casing.
The Company completed an acquisition of Earth Power Resources Inc. (“EPR”) on December 12, 2014. Acquired assets include geothermal leases that cover 26,017 acres in the State of Nevada representing three potential projects (Crescent Valley, Lee Hot Springs and Ruby Hot Springs).
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Factors Affecting Our Results of Operations
Raft River Operating Agreement/Ownership
Original Agreement
Originally, the
Raft River Energy I LLC (“RREI”) issued two classes of member units, (Class A
and Class B). Each class of ownership gives the owner participating rights in
the business and results in equity ownership risks. The rights attached to the
different classes will vary over time, in accordance with the terms of the
Membership Admission Agreement. The agreement required RREI to track separately
the capital accounts of the members after November 24, 2006. For income tax
purposes, the Class A units received a greater proportion of the share of losses
and other income tax benefits. This includes the allocation of production tax
credits, which was distributed 99% to the Class A units and 1% to the Class B
units during the first 10 years of production.
Purchase Agreement of Member Interest
On December 16, 2015, the U.S. Geothermal Inc. (holder of all Class B
units) signed a purchase agreement with Goldman Sachs for the acquisition of 450
Class A units of the 500 Class A units held by Goldman Sachs. The terms of the
agreement specified the conversion of 450 A units to 450 C units. All of the C
units were acquired by U.S. Geothermal Inc. The remaining 50 A units held by
Goldman Sachs retain all of the benefits for income tax purposes that were held
by the original 500 A units. Effective December 16, 2015, U.S. Geothermal Inc.
will receive 95% of the available cash flow from the project for the total
purchase price of $5.1 million. The agreement includes an option for U.S.
Geothermal Inc. to purchase residual interest in RREI for fair market value in
December 2017. Allocations of profits and losses will remain 99% to Goldman
Sachs and 1% to the U.S. Geothermal Inc. until December 31, 2017, after which
the U.S. Geothermal Inc. will receive 95% of the allocation of profits and
losses and Goldman Sachs will receive 5%.
The Company’s interests in RREI as defined in the partnership agreements are summarized as follows:
| Years (2016-2017) |
Years (After 2017) | ||
| Cash Flow | RECs | 95% (1) | 95% |
| Lease Payments, O&M Services & Royalties | 100% | ||
| Distributions | 95% | 95% | |
| Tax Benefits | 1% | 95% | |
| GAAP Income | 1% | 95% | |
| (1) |
The Company allocates 95% of income and receives 95% of available cash from RECs sold to third- parties. After year 10, REC income is shared with Idaho Power Co. For additional details, see the second amended and restated operating agreements as amended. |
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Power Purchase Agreements
Prior to the construction of a geothermal project, we typically enter into a Power Purchase Agreement (“PPA”) with a utility, which fixes the price of energy produced at a project for a 20 to 30 year period. Such PPAs are typically negotiated with a utility company and approved by a state utility commission or similar regulating body, or other major retail electric service provider, or with aa large industrial consumer.
Our power purchase agreements generally provide for energy payments only and can include the “green” attributes for geothermal energy since geothermal energy is a source of renewable energy. 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 or subject to preset annual adjustments. Some PPAs provide for forfeiture of payments or payments of penalties if minimum target levels are not met.
Neal Hot Springs, Oregon
The PPA for the Neal Hot
Springs project was signed on December 11, 2009 with the Idaho Power Company.
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.
The PPA has a 25 year term with a starting price of $96 per megawatt hour. The
price escalates annually by up to 3.9% in the initial years and to as low as
1.0% during the last 10 years of the agreement. The approximate 25 year
levelized price is $117.65 per megawatt hour.
San Emidio, Nevada
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 one
percent annual escalation rate. The electrical output from both Phase I and
Phase II was to be sold under the terms of the amended and restated PPA. The PPA
required that Phase II had to be on line by December 2015, and since Phase II
was not constructed, the option expired. The PPA was approved by the Public
Utility Commission of Nevada on December 27, 2011.
Raft River Energy I LLC
Raft River Energy I LLC
currently earns revenue from a 25 year, full-output PPA with Idaho Power
Company, which allows power sales of up to 13 megawatts annual average. The PPA
was signed on September 24, 2007 and expires in January 2033 on the anniversary
of its commercial operation date. 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 (March, April, May) 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 megawatt hour. The $53.60
purchase price is escalated each year at a compound annual rate of 2.1% until
year 12 (2020). From years 13 to 25 of the contract the escalation rate will
drop to 0.6% per year.
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Operating Results
For the year ended December 31 2016, the Company reported net income attributable to U.S. Geothermal Inc. of $463,331 ($0.02 income per share) which represented a $1,383,898 decrease from net income attributable to U.S. Geothermal Inc. of $1,847,229 reported in the year ended 2015 ($0.10 income per share). Unfavorable variances were reported in corporate administration, professional and management fees, promotion, and other income/expenses. A notable favorable variance was reported for income tax expense.
Plant Operations
The Company’s energy production
revenues and related operating costs originated from its three power plants. The
Neal Hot Springs, Oregon (USG Oregon LLC) plant is located in Eastern Oregon and
began commercial operations in November 2012. The San Emidio, Nevada (USG Nevada
LLC) plant is located in the San Emidio Desert in the northwestern part of the
State of Nevada and began operations in May 2012. The Raft River, Idaho (Raft
River Energy I LLC) plant is located in South Eastern Idaho and began operations
in January of 2008.
A summary of energy sales by plant for the two years are as follows:
| For the Year Ended December 31, | ||||||||||||
| 2016 | 2015 | |||||||||||
| $ | %* | $ | %* | |||||||||
| Energy sales by plant: | ||||||||||||
| Neal Hot Spring, Oregon | 19,561,718 | 62.8 | 18,823,799 | 61.1 | ||||||||
| San Emidio, Nevada | 6,980,358 | 22.4 | 7,324,484 | 23.7 | ||||||||
| Raft River, Idaho | 4,599,936 | 14.8 | 4,693,913 | 15.2 | ||||||||
| 31,142,012 | 100.0 | 30,842,196 | 100.0 | |||||||||
%* - represents the percentage of total Company energy sales.
A quarterly summary of megawatt hours generated by each plant are as follows:
| For the Quarter Ended, | |||||||||||||||
| December 31, | March 31, | June 30, | September 30, | December 31, | |||||||||||
| 2015 | 2016 | 2016 | 2016 | 2016 | |||||||||||
| Neal Hot Springs, Oregon | 52,642 | 53,671 | 39,094 | 29,758 | 57,036 | ||||||||||
| San Emidio, Nevada | 20,369 | 20,433 | 14,139 | 19,675 | 20,803 | ||||||||||
| Raft River, Idaho | 21,751 | 19,684 | 15,647 | 16,622 | 20,039 | ||||||||||
| 94,762 | 93,788 | 68,880 | 66,055 | 97,878 | |||||||||||
Neal Hot Springs, Oregon (USG Oregon LLC) Plant
Operations
For the year ended December 31, 2016, the Neal Hot Springs
plant reported subsidiary net plant income of $10,221,842, which was an increase
of $220,833 (2.2% increase) from the net income of $10,001,009 reported in the
year ended December 31, 2015. Overall, energy sales for the year ended 2016
increased $737,919 (3.9% increase) from the year ended 2015. The contracted
rates effectively increased 2.4% during the year. During the current year the
plant produced 179,558 megawatts of power which was an increase of 2,687
megawatts (1.5% increase) from the prior year. Production hours lost due to both
planned and unplanned outages decreased 9.2% from the prior year. In January and
May of 2015, approximately 218 hours were lost due to plugged vaporizers in
Units 2 and 3.
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Plant operating costs, excluding depreciation, increased $588,143, which was a 15.2% increase from the prior year. The largest increases were related to taxes and field maintenance costs. For the current year, the plant incurred County Property taxes of $352,110. These taxes were abated during the initial years of plant operations. The abatement period ended in 2015. Increases in field maintenance expenses were partially offset by decreases in chemical and lubricant costs. Field and maintenance costs for the current year increased $98,374 (13.9% increase) from 2015. In the current year, the Company incurred costs that exceeded $233,000 for production pump repairs.
Summarized statements of operations for the Neal Hot Springs, Oregon plant are as follows:
| Year Ended December 31, | ||||||||||||||||||
| 2016 | 2015 | Variance | ||||||||||||||||
| $ | %* | $ | % | $ | %** | |||||||||||||
| Plant revenues: | ||||||||||||||||||
| Energy sales | 19,561,718 | 100.0 | 18,823,799 | 100.0 | 737,919 | 3.9 | ||||||||||||
| Plant expenses: | ||||||||||||||||||
| Operations | 4,466,905 | 22.8 | 3,878,762 | 20.6 | (588,143 | ) | (15.2 | ) | ||||||||||
| Depreciation and amortization | 3,281,787 | 16.8 | 3,278,114 | 17.4 | (3,673 | ) | (0.1 | ) | ||||||||||
| 7,748,692 | 39.6 | 7,156,876 | 38.0 | (591,816 | ) | (8.3 | ) | |||||||||||
| Operating income | 11,813,026 | 60.4 | 11,666,923 | 62.0 | 146,103 | 1.3 | ||||||||||||
| Other income (expense): | ||||||||||||||||||
| Interest expense | (1,597,980 | ) | (8.1 | ) | (1,674,411 | ) | (8.9 | ) | 76,431 | 4.6 | ||||||||
| Interest income/other | 6,796 | 0.0 | 8,497 | 0.0 | (1,701 | ) | (20.0 | ) | ||||||||||
| (1,591,184 | ) | (8.1 | ) | (1,665,914 | ) | (8.9 | ) | 74,730 | 4.5 | |||||||||
| Subsidiary net income | 10,221,842 | 52.3 | 10,001,009 | 53.1 | 220,833 | 2.2 | ||||||||||||
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2015 to 2016. 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 and corporate support are not incorporated into the presentation of the subsidiary’s net operating income/loss.
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Key quarterly production data for the Neal Hot Springs, Oregon plant is summarized as follows:
| Mega- | Ave. Rate | Depreciation | |||||||||||||
| watt | Energy | per | Subsidiary | & | |||||||||||
| Hours | Sales | Megawatt | Net Income* | Amortization | |||||||||||
| Quarter Ended: | Produced | ($) | Hour ($) | ($) | ($) | ||||||||||
| December 31, 2014 | 54,472 | 6,377,488 | 117.1 | 4,147,356 | 819,924 | ||||||||||
| March 31, 2015 | 53,500 | 5,207,350 | 97.3 | 3,010,263 | 819,708 | ||||||||||
| June 30, 2015 | 37,232 | 3,188,091 | 85.6 | 1,027,928 | 819,785 | ||||||||||
| September 30, 2015 | 33,498 | 4,004,715 | 119.3 | 1,651,029 | 819,450 | ||||||||||
| December 31, 2015 | 52,642 | 6,423,643 | 122.0 | 4,311,789 | 819,171 | ||||||||||
| March 31, 2016 | 53,671 | 5,366,004 | 100.0 | 3,226,740 | 818,062 | ||||||||||
| June 30, 2016 | 39,094 | 3,445,321 | 88.2 | 1,243,706 | 820,063 | ||||||||||
| September 30, 2016 | 29,758 | 3,651,073 | 122.4 | 1,279,527 | 820,546 | ||||||||||
| December 31, 2016 | 57,036 | 7,099,320 | 124.5 | 4,471,869 | 823,116 |
* - The intercompany elimination adjustments for management fees and corporate support are not incorporated into the presentation of the subsidiary’s net income.
San Emidio, Nevada (USG Nevada LLC) Plant Operations
For the year ended December 31, 2016, the San Emidio plant reported
subsidiary net income of $1,042,266 which was a decrease of $442,931 (29.8%
decrease) from the subsidiary net income of $1,485,197 reported for the year
ended 2015.
The contracted rates effectively increased 1.0% during the year. During the current year the plant produced 20,803 megawatts of power which was a decrease of 4,489 megawatts (5.6% decrease) from the prior year. Production decreases were primarily due to higher levels of down time in the current year. In April 2016, approximately 107 hours were needed to repair a vaporizer bypass valve. In June 2016, approximately 155 hours were needed to replace a refrigerant pump. Efficiencies gained by the new refrigerant pump have increased production that was realized in the current third quarter and fourth quarters.
For the current year, the total operating costs, excluding depreciation, decreased $63,653 (2.4% decrease) from the prior year. Significant decreases in administration and corporate support were partily offset by increases in field maintenance and taxes. Corporate support and administrative costs decreased $322,337 (61.6% decrease) from 2015. For the current year, the Parent Company elected to forgo its collection of management fees and corporate support costs. In 2015, USG Nevada LLC incurred $206,398 and $117,997 in management fees and corporate support; repectively. Field maintenance costs increased $186,671 (74.2% increase) from the prior year. In the current year, costs that exceeded $147,700 were incurred for production pump repairs and repairs to the condensate/feed system. For the current year, taxes and permit costs increased $51,183 (15.1% increase) from 2015. The mineral proceeds tax for the State of Nevada were significantly lower in 2015 due to an overpayment in 2014 and lower budgeted allowable expenses for 2015. In the second quarter 2016, additional minerals proceeds tax assessment was made for $30,425 after an examination by the State of Nevada.
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Summarized statements of operations for the San Emidio, Nevada plant are as follows:
| Year Ended December 31, | ||||||||||||||||||
| 2016 | 2015 | Variance | ||||||||||||||||
| $ | %* | $ | % | $ | %** | |||||||||||||
| Plant revenues: | ||||||||||||||||||
| Energy sales | 6,980,358 | 100.0 | 7,324,484 | 100.0 | (344,126 | ) | (4.7 | ) | ||||||||||
| Plant expenses: | ||||||||||||||||||
| Operations | 2,668,145 | 38.2 | 2,604,492 | 35.6 | (63,653 | ) | (2.4 | ) | ||||||||||
| Depreciation and amortization | 1,280,671 | 18.3 | 1,263,401 | 17.2 | (17,270 | ) | (1.4 | ) | ||||||||||
| 3,948,816 | 56.6 | 3,867,893 | 52.8 | (80,923 | ) | (2.1 | ) | |||||||||||
| Operating income (loss) | 3,031,542 | 43.4 | 3,456,591 | 47.2 | (425,049 | ) | (12.3 | ) | ||||||||||
| Other income (expense): | ||||||||||||||||||
| Interest expense | (1,999,932 | ) | (28.7 | ) | (2,032,776 | ) | (27.7 | ) | 32,844 | 1.6 | ||||||||
| Interest income/other income | 10,656 | 0.2 | 61,382 | 0.8 | (50,726 | ) | (82.6 | ) | ||||||||||
| (1,989,276 | ) | (28.5 | ) | (1,971,394 | ) | (26.9 | ) | (17,882 | ) | (0.9 | ) | |||||||
| Subsidiary net income | 1,042,266 | 14.9 | 1,485,197 | 20.3 | (442,931 | ) | (29.8 | ) | ||||||||||
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2015 to 2016. 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.
# - variance percentage that is extremely high or undefined.
The intercompany elimination adjustments for management fees and corporate support are not incorporated into the presentation of the subsidiary’s net operating income/loss.
Key quarterly production data for the San Emidio, Nevada plant is summarized as follows:
| Mega- | Ave. Rate | Subsidiary | Depreciation | ||||||||||||
| watt | Energy | per | Net Income | & | |||||||||||
| Hours | Sales | Megawatt | (Loss)* | Amortization | |||||||||||
| Quarter Ended: | Produced | ($) | Hour ($) | ($) | ($) | ||||||||||
| December 31, 2014 | 21,745 | 1,982,709 | 91.2 | 158,352 | 315,609 | ||||||||||
| March 31, 2015 | 21,754 | 2,003,346 | 92.1 | 556,301 | 316,346 | ||||||||||
| June 30, 2015 | 18,492 | 1,702,633 | 92.1 | 264,410 | 315,846 | ||||||||||
| September 30, 2015 | 18,924 | 1,742,750 | 92.1 | 386,033 | 314,940 | ||||||||||
| December 31, 2015 | 20,369 | 1,875,755 | 92.1 | 278,453 | 316,269 | ||||||||||
| March 31, 2016 | 20,433 | 1,900,467 | 93.0 | 425,447 | 318,214 | ||||||||||
| June 30, 2016 | 14,139 | 1,315,049 | 93.0 | (142,273) | 319,756 | ||||||||||
| September 30, 2016 | 19,675 | 1,829,996 | 93.0 | 384,018 | 321,479 | ||||||||||
| December 31, 2016 | 20,803 | 1,934,846 | 93.0 | 375,074 | 321,222 |
* - The intercompany elimination adjustments for management fees and corporate support charges are not incorporated into the presentation of the subsidiary’s net income/loss.
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Raft River, Idaho (Raft River Energy I LLC) Plant
Operations
The subsidiary net loss from Raft River Energy I LLC (“RREI”)
operations of $638,222 for the year ended December 31, 2016 increased $1,530
(0.2% increase) from the loss of $636,692 reported for the year ended 2015.
Energy sales decreased $93,977 (2.0% decrease) from the prior year. Decreases in
production were partially offset by contracted rate increases. The contracted
rates effectively increased 2.9% during the year. During the current year the
plant produced 20,039 megawatts of power which was a decrease of 3,604 megawatts
(4.8% decrease) from the prior year. From February through September 2016, the
plant lost one of its production wells partially due to the drilling of the new
leg on a production well. Also, another well was out of operation from late
September through November of the current year.
Plant operating costs, excluding depreciation, decreased $275,519 for the year ended December 31, 2016, which was a 7.0% decrease from the year ended 2015. The decreases were primarily due to field maintenance costs. Field maintenance costs decreased 12.0% from 2015. In the prior year, costs that exceeded $294,700 were incurred for a scheduled turbine overhaul.
The summarized statements of operations for RREI are as follows:
| Year Ended December 31, | ||||||||||||||||||
| 2016 | 2015 | Variance | ||||||||||||||||
| $ | %* | $ | %* | $ | %** | |||||||||||||
| Plant revenues: | ||||||||||||||||||
| Energy sales | 4,599,936 | 93.1 | 4,693,913 | 92.9 | (93,977 | ) | (2.0 | ) | ||||||||||
| Energy credit sales | 339,663 | 6.9 | 357,902 | 7.1 | (18,239 | ) | (5.1 | ) | ||||||||||
| 4,939,599 | 100.0 | 5,051,815 | 100.0 | (112,216 | ) | (2.2 | ) | |||||||||||
| Plant expenses: | ||||||||||||||||||
| General operations | 3,638,498 | 73.7 | 3,914,017 | 77.5 | 275,519 | 7.0 | ||||||||||||
| Depreciation and amortization | 1,814,937 | 36.7 | 1,757,891 | 34.8 | (57,046 | ) | (3.2 | ) | ||||||||||
| 5,453,435 | 110.4 | 5,671,908 | 112.3 | 218,473 | 3.9 | |||||||||||||
| Operating loss | (513,836 | ) | (10.4 | ) | (620,093 | ) | (12.3 | ) | 106,257 | 17.1 | ||||||||
| Other income (expense): | ||||||||||||||||||
| Interest expense | (198 | ) | (0.0 | ) | (39,064 | ) | (0.8 | ) | 38,866 | 99.5 | ||||||||
| Other and interest income | (124,188 | ) | (2.5 | ) | 22,465 | 0.5 | (146,653 | ) | (652.8 | ) | ||||||||
| (124,386 | ) | (2.5 | ) | (16,599 | ) | (0.3 | ) | (107,787 | ) | (649.4 | ) | |||||||
| Subsidiary net loss | (638,222 | ) | (12.9 | ) | (636,692 | ) | (12.6 | ) | (1,530 | ) | 0.2 | |||||||
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2015 to 2016. 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.
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Key quarterly production data for RREI is summarized as follows:
| Mega- | Ave. Rate | Subsidiary | Depreciation | ||||||||||||
| watt | Energy | per | Net Income | & | |||||||||||
| Hours | Sales | Megawatt | (Loss)* | Amortization | |||||||||||
| Quarter Ended: | Produced | ($) | Hour ($) | ($) | ($) | ||||||||||
| December 31, 2014 | 20,614 | 1,425,811 | 69.9 | 203,414 | 431,214 | ||||||||||
| March 31, 2015 | 20,672 | 1,165,050 | 56.4 | (96,930 | ) | 431,959 | |||||||||
| June 30, 2015 | 17,223 | 888,599 | 51.6 | (668,764 | ) | 438,955 | |||||||||
| September 30, 2015 | 15,950 | 1,106,643 | 69.4 | (296,743 | ) | 443,233 | |||||||||
| December 31, 2015 | 21,751 | 1,533,621 | 70.5 | 425,745 | 443,744 | ||||||||||
| March 31, 2016 | 19,684 | 1,144,351 | 58.2 | (158,497 | ) | 444,587 | |||||||||
| June 30, 2016 | 15,647 | 829,554 | 52.1 | (321,895 | ) | 444,608 | |||||||||
| September 30, 2016 | 16,622 | 1,173,294 | 71.5 | (288,634 | ) | 444,878 | |||||||||
| December 31, 2016 | 20,039 | 1,452,737 | 72.5 | 130,804 | 480,864 |
* - Subsidiary net income (loss) does not include intercompany elimination adjustments for interest expense, management fees and lease costs.
Corporate Administration
For the year ended December
31, 2016, the Company reported $1,313,524 in corporate and administrative
expense which was an increase of $225,849 (20.8% increase) from $1,087,675
reported for the year ended 2015. For the year ended December 31, 2016, rental
expenses increased $158,278 (134.9% increase) from the year ended 2015. During
the current year, additional rental/storage costs of $152,433 were incurred for
storage of power plant components acquired in the fourth quarter 2015. The
majority of the power plant components have been moved to a storage facility
owned by the Company in the fourth quarter of 2016; therefore, these rental
costs will not be incurred in future periods. Director fees increased $49,900
(42.2% increase) from the prior year. In addition to routine rate increases, two
additional independent board members were added during the current year.
Professional and Management Fees
For the year ended
December 31, 2016, the Company reported $1,615,770 in professional and
management fees which was an increase of $547,831 (51.3% increase) from
$1,067,939 reported in the year ended 2015. In August of 2015, the Company
formed a Special Committee of the Board of Directors to thoroughly explore
strategic options to maximize shareholder value. The Company ended this process
and ended the contract with the primary consultant that was engaged in the
examination in March 2016. For the first quarter of 2016, the consultant’s fees
associated with this examination totaled approximately $544,000. During the
current year, the Company incurred additional fees of $100,000 for services
provided by a new financial advisor.
Promotion
For the year ended December 31, 2016, the
Company reported $376,426 in promotion costs which was an increase of $160,835
(74.6% increase) from $215,591 reported in the year ended 2015. During first
quarter 2016, the Company incurred additional travel costs related to the
process of exploring strategic options to maximize shareholder value and to
attend investment conferences. During second quarter 2016, the Company
implemented a new marketing program that included radio spots and regular news article coverage.
The costs of the marketing program for the second quarter totaled $117,650. The
Company continued a contract with an outside investor relations firm for $6,000
per month. This contract ended in June 2016. In the third and fourth quarters of
2016, promotion costs were, primarily, incurred for professional memberships
fees and investor conferences.
-80-
Other Income/Expenses
For the year ended December 31,
2016, the Company reported a net loss of $68,946 for other income/expenses which
was a decrease of $210,239 from the net gain of $141,293 reported the year ended
2015. In September 2016, a production pump was replaced at the Raft River Energy
I LLC plant. The book value of the pump was $124,930 ($175,000 cost, less
$50,070 accumulated depreication) at the time of disposal.
Income Tax Benefit/Expense
For the year ended
December 31, 2016, the Company reported net income tax expense of $575,000 which
was a decrease of $811,000 (58.5% decrease) from $1,386,000 of net income tax
expense recognized in the prior year. Net income attributable to U.S. Geothermal
Inc. before income taxes decreased $2,194,898 (67.9% decrease) from the year
ended 2015. The decrease was due to the decline in income, which was primarily a
result of increases in corporate administration, professional and management
fees, and promotion costs as discussed above.
Non-Controlling Interests
The following is a summarized presentation of select financial line items from the statement of operations by project and the impact of the related non-controlling interests for the year ended December 31, 2016:
| Exploration | |||||||||||||||
| Neal Hot | San | Activities and | Consolid- | ||||||||||||
| Statement of Operations | Springs | Emidio | Raft River | Corporate | ated | ||||||||||
| Element | $ | $ | $ | $ | $ | ||||||||||
| Net income from plant operations | 11,813,026 | 3,031,541 | (513,835 | ) | 703,614 | 15,034,346 | |||||||||
| Expenses/(income) | 1,613,452 | 1,989,276 | 124,386 | (4)7,146,884 | 10,873,998 | ||||||||||
| Net income (loss) | 10,199,574 | 1,042,265 | (638,221 | ) | (6,443,270 | ) | 4,160,348 | ||||||||
| Income taxes | (2,296,000 | ) | (391,000 | ) | (117,000 | ) | 2,228,000 | (575,000 | ) | ||||||
| Non-controlling interests | (1)(4,079,830 | ) | - | (2)951,149 | (3)6,664 | (3,122,017 | ) | ||||||||
| Net income attributable to U.S. Geothermal | 3,824,744 | 651,265 | 195,928 | (4,208,606 | ) | 463,331 |
| (1) |
The non-controlling interest for Neal Hot Springs represents a 40% interest for our joint venture partner, Enbridge. Neal Hot Springs includes the operations of both Oregon USG Holdings LLC and USG Oregon LLC. | |
| (2) |
The non-controlling interest for Raft River represents 30% of REC income and 99% of all other income/expenses for Raft River I Holdings, a subsidiary of Goldman Sachs Group. | |
| (3) |
The non-controlling interest for our exploration activities represents a 31.1% interest for our joint venture partner at Gerlach, GGE Development. |
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| (4) |
Major costs included in Exploration Activities and Corporate for the year ended December 31, 2016 include: |
| • | Employee compensation | $ 3,035,074 | ||
| • | Corporate administration | 1,313,524 | ||
| • | Professional fees | 1,615,770 | ||
| • | Promotion | 376,426 | ||
| • | Exploration costs | 39,091 |
These costs are the responsibility of U.S. Geothermal Inc. (the Parent Company) and cannot be allocated to projects. Once a project has been classified as developmental (resource verified, PPA off-taker identified), the costs associated with a project will be capitalized.
Selected balance sheet items affected by non-controlling interests as of December 31, 2016 are detailed as follows:
| Non- | U.S. | ||||||||
| Controlling | Geothermal | ||||||||
| Consolidated | Interests | Inc. | |||||||
| Balance Sheet Items | $ | $ | $ | ||||||
| Unrestricted cash and cash equivalents | 15,287,144 | 1,795,527 | 13,491,617 | ||||||
| Restricted cash and security bonds: | |||||||||
| Current | 8,527,462 | 967,680 | 7,559,702 | ||||||
| Long-term | 20,111,350 | 5,919,014 | 14,192,336 | ||||||
| Notes payable: | |||||||||
| Current | 4,259,595 | 1,199,407 | 3,060,188 | ||||||
| Long-term | 104,873,959 | 22,869,102 | 82,004,857 |
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The loans held by the Company at December 31, 2016 are detailed as follows:
| U.S. Geothermal Inc. | ||||||||||||||||||
| Consolidated | Contracted | Loan | ||||||||||||||||
| Total Loan | Remaining | Loan | Interest | Balance | Loan | |||||||||||||
| Balances | Months to | Maturity | Rate | Portions | Balances | |||||||||||||
| Descriptions | $ | Term | End Date | % | % | $ | ||||||||||||
| Department of Energy – USG Oregon LLC | 60,171,274 | 218 | 2/12/35 | 2.598 | 60.0 | 36,102,764 | ||||||||||||
| Prudential Group – USG Nevada LLC | 29,041,531 | 252 | 12/31/37 | 6.750 | 100.0 | 29,041,531 | ||||||||||||
| Prudential Group – Idaho USG Holdings LLC | 19,915,115 | 75 | 3/31/23 | 5.800 | 100.0 | 19,915,115 | ||||||||||||
| Chrysler Auto Loan – U.S. Geothermal Services | 5,634 | 19 | 7/27/18 | 6.740 | 100.0 | 5,634 | ||||||||||||
| Totals | 109,133,554 | 85,065,044 | ||||||||||||||||
| Weighted Average | ||||||||||||||||||
| Term (Months) | 201 | |||||||||||||||||
| Weighted Average | ||||||||||||||||||
| Interest Rate | 4.287 | |||||||||||||||||
Liquidity and Capital Resources
During the quarter ended December 31, 2016, the operating projects of U.S. Geothermal continued to generate significant available cash (after debt service and reserves) to fund our development activities and corporate costs. In addition, exercise of options and warrants generated $175,472 during the quarter. We believe our cash and liquid investments at December 31, 2016 are adequate to fund our general operating activities through December 31, 2017.
Development of our projects under development and under exploration 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 Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels.
Idaho Power Company and Sierra Pacific Power (NV Energy), continue to pay for their power in a timely manner. This power is sold under long-term contracts at fixed prices. The status of the credit and equity markets could delay our project development activities while we seek to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities.
On May 19, 2016, the Company closed on a $20 million debt facility from Prudential Capital Group. Under terms of the financing agreement, the Company has the option, without obligation, to issue additional debt, up to $50 million in aggregate within the next two years. The initial $20 million loan has a fixed interest rate of 5.8% per annum. The loan principal amortizes over twenty years, with a seven-year term. Principal and interest payments are made semi-annually. The loan is collateralized with the Company’s ownership interest in the Neal Hot Springs and Raft River projects and by virtue of a pledge by the Company’s wholly owned subsidiary, U.S. Geothermal Inc., an Idaho corporation, and sole member of Idaho USG Holdings, the equity interests in Idaho USG Holdings. The 22 MW Neal Hot Springs project is owned 60% by the Company and 40% by Enbridge. The 13 MW Raft River project is owned 95% by the Company and 5% by Goldman Sachs.
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On January 25, 2016, management determined it would be prudent to enter into a new Lincoln Park Capital (“LPC”) facility. The Company’s first Purchase Agreement with LPC, was entered into on May 21, 2012 and expired in 2015. Under the new Purchase Agreement, at the company’s sole discretion, the Company has the right to sell and LPC has the obligation to purchase up to $10 million of equity capital over a 30-month period subject to the conditions in the Purchase Agreement. The agreement provided for an initial sale of $650,000 of shares of common stock upon closing. Net proceeds from LPC’s investments were used to cover a portion of the cost of the recent acquisition of the Goldman Sachs ownership interest of the Raft River project, development of our geothermal projects and for general corporate purposes. During the quarter ended March 31, 2016 an additional $571,650 was raised under the At the Market (“ATM”) subsequent to the initial sale. No additional funds were raised over the last three quarters.
On December 14, 2015, the Company acquired from Goldman Sachs the majority of their cash flow interest in and ownership of the Raft River geothermal project. The Company will receive 95% of the cash flow from the project on a going forward basis, along with all increased cash flow from any project improvements. Allocations of profits and losses will remain 99% to Goldman Sachs and 1% to the Company until December 31, 2017, after which the Company will receive 95% of the allocation of profits and losses and Goldman Sachs will receive 5%. The purchase price was $5.1 million for the 95% interest, with an option to purchase the balance of Goldman’s interest for Fair Market Value at the end of 2017. The purchase price consisted of a $3.5 million cash payment plus a promissory note of $1.6 million that bears interest at 8%. Under the promissory note agreement, $1 million of the note could be satisfied with shares of U.S. Geothermal common stock priced at the 10 day weighted average closing price of the common stock at time of conversion if not otherwise paid in cash by March 31, 2016. Since the Company paid off this note in cash on March 31, 2016, the Company has now withdrawn its resale registration statement covering the shares to be issued in satisfaction of the promissory note.
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.
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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.
Revenue Recognition
Energy sales revenue are
recognized when the electrical power generated by the Company’s power plants is
delivered to the customer who is reasonably assured to be able to pay under the
terms defined by the Power Purchase Agreements (“PPAs”). Renewable Energy
Credits (“RECs”) are earned for each megawatt hour produced from the geothermal
power plants. Revenues from RECs sales are recognized when the Company has met
the terms and conditions of certain energy sales agreements with a financially
capable buyer. At San Emidio and Neal Hot Springs, the RECs are owned by our
customer and are bundled with energy sales.
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, geothermal water rights and construction in
progress. 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 the first years 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.
-85-
Stock-Based Compensation
The Company awards stock
options to employees for services provide to the Company. 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 shares, the expected life of the options, and the volatility of the
stock price. Generally, 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. To date, all costs associated with the stock options
have been charged to operations and no costs have been allocated to the
construction of property and equipment.
Contractual Obligations
As of December 31, 2016, 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 (1) | $ 8,115,799 | $ 743,050 | $ 1,119,618 | $ 889,218 | $ 5,363,914 |
| Plant Loan(2) | 29,041,531 | 638,949 | 1,280,586 | 1,980,417 | 25,141,579 |
| Project Loan (3) | 19,915,115 | 618,640 | 1,000,231 | 1,529,082 | 16,767,162 |
| Plant Loan, DOE(4) | 60,171,274 | 2,998,517 | 5,997,034 | 5,997,034 | 45,178,689 |
| Auto Loan | 5,634 | 3,488 | 2,146 | - | - |
| (1) |
Operating leases does not include costs from royalty based lease contracts. | |
| (2) |
Plant loan with Prudential Capital Group scheduled for to be repaid over the next 23 years. | |
| (3) |
Project loan with Prudential Capital Group scheduled to be repaid March 2023. | |
| (4) |
Plant loan with the Department of Energy scheduled to be repaid over the next 20 years. |
Off Balance Sheet Arrangements
As of December 31, 2016, the Company does not have any off balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Not Applicable
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 Income and Comprehensive Income 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 transition 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 transition report.
-86-
U.S. GEOTHERMAL INC.
________
Consolidated Financial Statements
and
Reports of
Independent Registered Public Accountants
December 31, 2015 and 2016
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
U.S. Geothermal
Inc.
We have audited the accompanying consolidated balance sheets of U.S. Geothermal Inc. (the Company) as of December 31, 2016 and 2015, and the related consolidated statements of income, cash flows, and changes in stockholders’ equity for each of the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of U.S. Geothermal Inc. as of December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the internal control over financial reporting of U.S. Geothermal Inc. as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2017, expressed an unqualified opinion thereon.
/s/ Moss Adams LLP
Seattle, Washington
March 9, 2017
U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS
| December 31, | ||||||
| 2016 | 2015 | |||||
| ASSETS | ||||||
| Current: | ||||||
| Cash and cash equivalents | $ | 15,287,144 | $ | 8,654,375 | ||
| Restricted cash and security bonds | 8,527,462 | 4,696,007 | ||||
| Trade accounts receivable | 4,102,018 | 3,766,517 | ||||
| Other current assets | 1,664,866 | 1,680,819 | ||||
| Total current assets | 29,581,490 | 18,797,718 | ||||
| Restricted cash and security bond reserves | 20,111,350 | 17,495,789 | ||||
| Property, plant and equipment, net | 170,301,349 | 167,736,792 | ||||
| Intangible assets, net | 15,084,143 | 15,265,828 | ||||
| Net deferred income tax asset | 8,346,000 | 8,921,000 | ||||
| Total assets | $ | 243,424,332 | $ | 228,217,127 | ||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||
| Current Liabilities: | ||||||
| Accounts payable and accrued liabilities | $ | 2,255,710 | $ | 2,703,226 | ||
| Convertible promissory note | - | 1,597,000 | ||||
| Current portion of notes payable | 4,259,595 | 4,412,012 | ||||
| Total current liabilities | 6,515,305 | 8,712,238 | ||||
| Long-term Liabilities: | ||||||
| Asset retirement obligations | 1,219,903 | 1,204,930 | ||||
| Notes payable, less current portion | 104,131,086 | 89,887,052 | ||||
| Total long-term liabilities | 105,350,989 | 91,091,982 | ||||
| Total liabilities | 111,866,294 | 99,804,220 | ||||
| Commitments and Contingencies (note 12) | ||||||
| STOCKHOLDERS’ EQUITY | ||||||
| Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at December 31, 2016 and 2015 were: 18,970,445 and 17,933,570; respectively) | 18,970 | 17,933 | ||||
| Additional paid-in capital | 121,933,378 | 118,220,681 | ||||
| Accumulated deficit | (16,974,300 | ) | (17,437,631 | ) | ||
| 104,978,048 | 100,800,983 | |||||
| Non-controlling interests | 26,579,990 | 27,611,924 | ||||
| Total stockholders’ equity | 131,558,038 | 128,412,907 | ||||
| Total liabilities and stockholders’ equity | $ | 243,424,332 | $ | 228,217,127 | ||
The accompanying notes are an integral part of these
consolidated financial statements.
-F-1-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF INCOME
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| Plant Revenues: | ||||||
| Energy sales | $ | 31,142,012 | $ | 30,842,196 | ||
| Energy credit sales | 339,663 | 357,902 | ||||
| Total plant operating revenues | 31,481,675 | 31,200,098 | ||||
| Plant Expenses: | ||||||
| Plant production expenses | 10,069,933 | 9,572,707 | ||||
| Depreciation and amortization | 6,377,396 | 6,299,405 | ||||
| Total plant operating expenses | 16,447,329 | 15,872,112 | ||||
| Gross Profit | 15,034,346 | 15,327,986 | ||||
| Operating Expenses: | ||||||
| Corporate administration | 1,313,524 | 1,087,675 | ||||
| Professional and management fees | 1,615,770 | 1,067,939 | ||||
| Employee compensation | 3,035,074 | 2,882,105 | ||||
| Promotion | 376,426 | 215,591 | ||||
| Exploration | 39,091 | 82,316 | ||||
| Operating Income | 8,654,461 | 9,992,360 | ||||
| Other (income) expenses: | ||||||
| Interest expense | 4,425,167 | 3,797,155 | ||||
| Other (income) expense | 68,946 | (141,293 | ) | |||
| Income Before Income Tax Expense | 4,160,348 | 6,336,498 | ||||
| Income tax expense | (575,000 | ) | (1,386,000 | ) | ||
| Net Income | 3,585,348 | 4,950,498 | ||||
| Net income attributable to the non-controlling interests | (3,122,017 | ) | (3,103,269 | ) | ||
| Net Income Attributable to U.S. Geothermal Inc. | $ | 463,331 | $ | 1,847,229 | ||
| Net Earnings Per Share Attributable to U.S. Geothermal Inc.: | ||||||
| Basic | $ | 0.02 | $ | 0.10 | ||
| Diluted | 0.02 | 0.10 | ||||
| Weighted average number of shares used in the calculation of income per share: | ||||||
| Basic | 18,665,808 | 17,828,469 | ||||
| Diluted | 19,255,891 | 18,052,267 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
-F-2-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| Operating Activities: | ||||||
| Net Income | $ | 3,585,348 | $ | 4,950,498 | ||
| Adjustments to reconcile net income to total cash provided by operating activities: | ||||||
| Depreciation and amortization | 6,544,287 | 6,409,818 | ||||
| Stock based compensation | 1,053,782 | 1,107,828 | ||||
| Loss on disposal of equipment | 124,930 | - | ||||
| Change in deferred income taxes | 575,000 | 1,386,000 | ||||
| Net changes in: | ||||||
| Trade accounts receivable | (335,501 | ) | 7,616 | |||
| Accounts payable and accrued liabilities | 2,826 | 59,510 | ||||
| Prepaid expenses and other | 15,952 | (130,460 | ) | |||
| Total cash provided by operating activities | 11,566,624 | 13,790,810 | ||||
| Investing Activities: | ||||||
| Purchases of property, plant and equipment | (9,409,260 | ) | (6,602,974 | ) | ||
| Acquisition of additional interests in subsidiaries | - | (3,500,000 | ) | |||
| Net funding of restricted cash reserves and bonds | (6,447,016 | ) | (180,919 | ) | ||
| Total cash used by investing activities | (15,856,276 | ) | (10,283,893 | ) | ||
| Financing Activities: | ||||||
| Issuance of common stock | 2,659,952 | 49,549 | ||||
| Proceeds from note payable, net of issuance costs | 19,185,986 | - | ||||
| Distributions to non-controlling interest | (4,153,951 | ) | (3,462,589 | ) | ||
| Principal payments on notes payable and other obligations | (6,769,566 | ) | (4,413,558 | ) | ||
| Principal payments on capital leases | - | (20,919 | ) | |||
| Total cash provided (used) by financing activities | 10,922,421 | (7,847,517 | ) | |||
| Increase (Decrease) in Cash and Cash Equivalents | 6,632,769 | (4,340,600 | ) | |||
| Cash and Cash Equivalents, Beginning of Year | 8,654,375 | 12,994,975 | ||||
| Cash and Cash Equivalents, End of Year | $ | 15,287,144 | $ | 8,654,375 | ||
| Supplemental Disclosures: | ||||||
| Non-cash investing and financing activities: | ||||||
| Accrual for purchases of property and equipment | $ | 450,342 | $ | 8,230 | ||
| Convertible promissory note issued for additional subsidiary interest | - | 1,597,000 | ||||
| Non-cash distributions to non-controlling interest | - | 24,000 | ||||
| Other Items: | ||||||
| Interest paid | 4,106,537 | 3,819,585 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
-F-3-
U.S. GEOTHERMALINC.
CONSOLIDATED STATEMENTS OF CHANGES
IN STOCKHOLDERS’ EQUITY
For the Years
Ended December 31, 2016 and 2015
| Additional | Non- | |||||||||||||||||
| Number of | Common | Paid- | Accumulated | controlling | ||||||||||||||
| Shares | Shares | In Capital | Deficit | Interest | Totals | |||||||||||||
| Balance at January 1, 2015 | 17,836,338 | $ | 17,836 | $ | 103,758,553 | $ | (19,284,860 | ) | $ | 46,397,092 | $ | 130,888,621 | ||||||
| Distributions to non-controlling interest entities | - | - | - | - | (3,486,589 | ) | (3,486,589 | ) | ||||||||||
| Acquisition of additional interest in subsidiary | - | - | 13,304,848 | - | (18,401,848 | ) | (5,097,000 | ) | ||||||||||
| Stock issued by the exercise of employee stock options | 25,833 | 26 | 49,524 | - | - | 49,550 | ||||||||||||
| Stock compensation | 71,399 | 71 | 1,107,756 | - | - | 1,107,827 | ||||||||||||
| Net income | - | - | - | 1,847,229 | 3,103,269 | 4,950,498 | ||||||||||||
| Balance at December 31, 2015 | 17,933,570 | 17,933 | 118,220,681 | (17,437,631 | ) | 27,611,924 | 128,412,907 | |||||||||||
| Distributions to non-controlling interest entities | - | - | - | - | (4,153,951 | ) | (4,153,951 | ) | ||||||||||
| Stock issued under At Market Issuance Purchase Agreement net of commitment shares valued at $225,000 | 410,635 | 410 | 1,188,224 | - | - | 1,188,634 | ||||||||||||
| Stock issued by the exercise of employee stock options | 342,082 | 342 | 882,961 | - | - | 883,303 | ||||||||||||
| Stock issued by the exercise of broker and stock purchase warrants | 209,240 | 209 | 587,806 | 588,015 | ||||||||||||||
| Stock compensation | 74,918 | 76 | 1,053,706 | - | - | 1,053,782 | ||||||||||||
| Net income | - | - | - | 463,331 | 3,122,017 | 3,585,348 | ||||||||||||
| Balance at December 31, 2016 | 18,970,445 | $ | 18,970 | $ | 121,933,378 | $ | (16,974,300 | ) | $ | 26,579,990 | $ | 131,558,038 |
The accompanying notes are an integral part of these
consolidated financial statements.
-F-4-
U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2016
NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS
U.S. Geothermal Inc. (“the Company”) was incorporated on March 10, 2000 in the State of Delaware. U.S. Geothermal Inc. – Idaho was formed in February 2002, and is the primary subsidiary through which the Company conducts its operations. The Company constructs, owns, manages and operates power plants that utilize geothermal resources to produce renewable energy. The Company’s operations have been, primarily, focused in the United States and Central America.
Basis of Presentation
The Company consolidates subsidiaries that it controls (more-than-50% owned) and entities over which control is achieved through means other than voting rights. These consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, as well as three controlling interests. The accounts of the following companies are consolidated in these financial statements:
| i) |
U.S. Geothermal Inc. (incorporated in the State of Delaware); | |
| ii) |
U.S. Geothermal Inc. (incorporated in the State of Idaho); | |
| iii) |
U.S. Geothermal Services, LLC (organized in the State of Delaware); | |
| iv) |
Nevada USG Holdings, LLC (organized in the State of Delaware); | |
| v) |
USG Nevada LLC (organized in the State of Delaware); | |
| vi) |
Nevada North USG Holdings, LLC (organized in the State of Delaware); | |
| vii) |
USG Nevada North, LLC (organized in the State of Delaware); | |
| viii) |
Oregon USG Holdings, LLC (organized in the State of Delaware); | |
| ix) |
USG Oregon LLC (organized in the State of Delaware); | |
| x) |
Raft River Energy I LLC (organized in the State of Delaware); | |
| xi) |
Gerlach Geothermal LLC (organized in the State of Delaware); | |
| xii) |
USG Gerlach LLC (organized in the State of Delaware); | |
| xiii) |
U.S. Geothermal Guatemala, S.A. (organized in Guatemala); | |
| xiv) |
Geysers USG Holdings Inc. (incorporated in the State of Delaware); | |
| xv) |
Western GeoPower, Inc. (incorporated in the State of California); | |
| xvi) |
USG Mayacamas Inc. (incorporated in the State of Delaware)); | |
| xvii) |
Mayacamas Energy LLC (organized in the State of California); | |
| xviii) |
Skyline Geothermal LLC (organized in the State of Delaware); | |
| xix) |
Skyline Geothermal Holding, Inc. (incorporated in the State of Delaware); | |
| xx) |
Earth Power Resources Inc. (incorporated in Delaware); and | |
| xxi) |
Idaho USG Holdings LLC (organized in the State of Delaware). |
All intercompany transactions are eliminated upon consolidation.
In cases where the Company owns a majority interest in an entity but does not own 100% of the interest in the entity, it recognizes a non-controlling interest attributed to the interest controlled by outside third parties. The Company will recognize 100% of the assets and liabilities of the entity, and disclose the non-controlling interest. The consolidated statements of income and comprehensive income will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.
-F-5-
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The Company’s consolidated financial statements have been prepared accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of U.S. Geothermal and its consolidated subsidiaries.
Share Consolidation (“Reverse Stock Split”)
On November 9, 2016, the Company effected a 1-for-6 share consolidation of its outstanding common stock. All share and per share amounts for all periods presented in these consolidated financial statements and notes have been adjusted retrospectively, where applicable, to reflect this share consolidation.
Use of Estimates
The preparation of consolidated financial statements in accordance with U.S. GAAP requires estimates and assumptions that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements as well as reported amounts of revenues and expenses during the reporting periods. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company’s consolidated financial statements; accordingly, actual results could differ from these estimates.
Cash and Cash Equivalents
The Company considers all unrestricted cash and short-term deposits, with original maturities of no more than ninety days when acquired to be cash and cash equivalents.
Trade Accounts Receivable Allowance for Doubtful Accounts
Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of December 31, 2016 and 2015, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.
Concentration of Credit Risk
The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity. At December 31, 2016, the Company’s total cash balance, excluding money market funds, was $5,105,461 and bank deposits amounted to $5,506,836. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $4,016,662 was not covered by or was in excess of FDIC insurance guaranteed limits. At December 31, 2016, the Company’s money market funds invested, primarily, in government backed securities totaled $37,347,897 and were not subject to deposit insurance. A contracted power purchaser held a security bond for the Company that totaled $1,468,898 at December 31, 2016.
-F-6-
Property, Plant and Equipment
Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized in the period of acquisition. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. A primary factor in determining whether to capitalize construction type costs is the stage of the potential project’s development. Once a project is determined to be commercially viable, all costs directly associated with the development and construction of the project are capitalized. Until that time, all development costs are expensed. A commercially viable project will typically have, among other factors, a reservoir discovery well or other significant geothermal surface anomaly, a power transmission path that is identified and available, and an electricity off-taker identified. A valid reservoir discovery is generally defined when a test well has been substantially completed that indicates the presence of a geothermal reservoir that has a high probability of possessing the necessary temperatures, permeability, and flow rates. After a valid discovery has been made, the project enters the development stage. Generally, all costs incurred during the development stage are capitalized and tracked on an individual project basis and are included in construction in progress until the project has been placed into service. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.
Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects is expensed when incurred. Employee training time is expensed when incurred.
Depreciation is calculated on a straight-line basis over the estimated useful life of the asset. Where appropriate, terms of property rights and revenue contracts can influence the determination of estimated useful lives. Estimated useful lives in years by major asset categories are summarized as follows:
| Estimated Useful | ||
| Asset Categories | Lives in Years | |
| Furniture, vehicle and other equipment | 3 to 5 | |
| Power plant, buildings and improvements | 3 to 30 | |
| Wells | 30 | |
| Well pumps and components | 5 to 15 | |
| Pipelines | 30 | |
| Transmission lines | 30 |
Intangible Assets
All costs directly associated with the acquisition of geothermal and surface water rights are capitalized as intangible assets. These costs are amortized over their estimated utilization period. There are several factors that influence the estimated utilization periods as well as underlying fair value that include, but are not limited to, the following:
| - | contractual expiration terms of the right, | |
| - | contractual terms of an associated revenue contract (i.e., PPAs), | |
| - | compliance with utilization and other requirements, and | |
| - | hierarchy of other right holders who share the same resource. |
-F-7-
Currently, amortization expense is being calculated on a straight-line basis over an estimated utilization period of 30 years for assets placed in service. If an intangible water or geothermal right is forfeited or otherwise lost, the remaining unamortized costs are expensed in the period of forfeiture. An impaired right is reduced to its estimated fair market value in the year the impairment is realized. Costs incurred that extend the term of an intangible right are capitalized and amortized over the new estimated period of utilization.
Impairment of Long-Lived Assets
The Company evaluates the carrying value of its long-lived assets for impairment when factors and circumstances indicate that the carrying values may not be recoverable. Factors which could trigger an impairment include, among others, significant underperformance relative to historical or projected future operating results, significant changes in the Company’s use of assets or its overall business strategy, negative industry or economic trends, a determination that a project will not support commercial operations, a determination that a suspended project is not likely to be completed, a significant increase in costs necessary to complete a project, legal factors relating to its business or when it concludes that it is more likely than not that an asset will be disposed of or sold. The Company tests its long-lived assets for impairment at the operating plants or site location. Recoverability of assets held and used is determined by comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered impaired, the impairment recognized is measured by the amount in which the carrying amount of the assets exceeds their fair value. The estimate of future cash flows required significant judgments of factors that include future sales, gross profit and operating expenses.
Stock Compensation
The Company accounts for stock based compensation by recording the estimated fair value of stock-based awards granted as compensation expense over the vesting period, net of estimated forfeitures. The fair value of restricted stock awards is determined based on the number of shares granted and the quoted price of the Company’s common stock on the date of grant. The fair value of stock option awards is estimated at the grant date as calculated by the Black-Scholes-Merton option pricing model. Stock-based compensation expense is attributed to earnings for stock options and restricted stock on the straight-line method. The Company estimates forfeitures of stock-based awards based on historical experience and expected future activity.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. Using this method, deferred tax assets and liabilities are recorded based on the differences between the financial reporting and tax basis of assets and liabilities. The deferred tax assets and liabilities are calculated using the enacted tax rates and laws that are expected to be in effect when the differences are expected to reverse. The Company routinely evaluates the likelihood of realizing the benefit of its deferred tax assets and may record a valuation allowance if, based on all available evidence, it is determined that it is more likely than not that all or some portion of the deferred tax benefit will not to be realized.
The Company regularly evaluates the likelihood of realizing the benefit for income tax positions in various federal, state and foreign filings by considering all relevant facts, circumstances and information available. If the Company believes it is more likely than not that its positions will be sustained, a benefit is recognized at the largest amount that is cumulatively greater than 50% likely to be realized. Interest and penalties related to income tax matters are classified as a component of income tax expense. Unrecognized tax benefits are recorded in other liabilities and long-term debt and other liabilities on the consolidated balance sheets.
-F-8-
Earnings Per Share
Basic income or loss per share is computed using the weighted average number of common shares outstanding during the period, and excludes any dilutive effects of common stock equivalent shares, such as options and restricted stock awards. Restricted stock awards (“RSAs”) are considered outstanding and included in the computation of basic income or loss per share when underlying restrictions expire and the awards are no longer forfeitable. Diluted income per share is computed using the weighted average number of common shares outstanding and common stock equivalent shares outstanding during the period using the treasury stock method. Common stock equivalent shares are excluded from the computation if their effect is anti-dilutive.
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, trade account and other receivables, refundable tax credits, and accounts payable and accrued liabilities. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted
Foreign Currency Translation
The Company’s functional currency is the U.S. dollar. Monetary items are converted into U.S. dollars at the rate prevailing at the consolidated balance sheet date. Foreign currency transactions are translated into U.S. dollars at the exchange rate in effect at the transaction date. Exchange gains and losses arising from transactions denominated in a currency other than the functional currency are included in other (income) expense.
Revenue
Revenue Recognition
Energy Sales
The energy sales revenue is recognized
when the electrical power generated by the Company’s power plants is delivered
to the customer who is reasonably assured to be able to pay under the terms
defined by the Power Purchase Agreements (“PPAs”).
Renewable Energy Credits (“RECs”)
Currently, the
Company operates three plants that produce renewable energy that creates a right
to a REC. The Company earns one REC for each megawatt hour produced from the
geothermal power plant. The Company considers the RECs to be outputs that are an
economic benefit obtained directly through the operation of the plants. The
Company does not currently hold any RECs for our own use. Revenues from RECs
sales are recognized when the Company has met the terms and conditions of
certain energy sales agreements with a financially capable buyer. At Raft River
Energy I LLC, each REC is certified by the Western Electric Coordinating Council
and sold under a REC Purchase and Sales Agreement to Holy Cross Energy. At San
Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled
with energy sales. At all three plants, title for the RECs pass during the same
month as energy sales. As a result, costs associated with the sale of RECs are
not segregated on the consolidated statement of income and comprehensive income
(loss).
Revenue Source
All of the Company’s operating revenues (energy sales and renewable energy credit sales) originate from energy production from its interests in three geothermal power plants located in the states of Idaho, Oregon and Nevada. The plants located in Oregon and Idaho sell their energy to the same electric power utility that primarily serves Idaho and eastern Oregon. For the years ended December 31, 2016 and 2015, the percentage of operating revenues from the major customer to total operating revenues was 76.7% and 75.4%; respectively. At December 31, 2016 and 2015, the percentage of trade accounts receivable balance from the major customer was 82.1% and 80.7%; respectively.
-F-9-
Asset Retirement Obligations
The Company records the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets in the period incurred or acquired. AROs are legal obligations to settle under existing or enacted law, statue, or contract. The value of these obligations are originally based upon discounted cash flow estimates and are accreted to full value over time through charges to operations. Costs associated with future conditions are recognized as AROs in the period the condition occurs or is known to the Company. Generally, costs associated with AROs are earthwork, revegetation, well capping, and structure removal necessary to return the sites to their original conditions.
Recent Accounting Pronouncements
Management has considered all recent accounting pronouncements. The following pronouncements were deemed applicable to our financial statements:
Statement of Cash Flows
In August
2016, FASB issued Accounting Standards Update No. 2016-15 (“Update 2016-15”),
Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and
Cash Payments. In November 2016, FASB issued Accounting Standards Update No.
2016-18 (“Update 2016-18”), Statement of Cash Flows (Topic 230),
Restricted Cash. Update 2016-15 provides guidance on how certain cash
receipts and cash payments are presented and classified in the statement of cash
flows. Update 2016-18 provides guidance on how to classify and present changes
in restricted cash or restricted cash equivalents that occur when there are
direct cash receipts into restricted cash or restricted cash equivalents or
direct cash payments made from restricted cash or restricted cash equivalents.
These Updates are effective for annual periods beginning after December 15,
2017, and interim periods within those fiscal years. Early adoption is
permitted, including adoption in an interim period. It is likely that some of
the provisions of Update 2016-15 will apply to certain transactions our Company
may engage in. The Company holds restricted cash and restricted cash equivalents
that are addressed in Update 2016-18. Management is currently evaluating the
possible impact these Updates may have on the presentation of the Company’s
consolidated statements of cash flows.
Revenue Recognition
In May 2014, FASB
issued Accounting Standards Update No. 2014-09 (“Update 2014-09”), Revenue
from Contracts with Customers (Topic 606). Update 2014-09 amends the revenue
recognition guidance and requires more detailed disclosures to enable financial
statement users to understand the nature, amount, timing and uncertainties of
revenue and cash flows arising from contracts with customers. In April
2016, FASB issued Accounting Standards Update No. 2016-10 (“Update 2016-10”),
Revenue from Contracts with Customers (Topic 606), Identify Performance
Obligations and Licensing. In March 2016, FASB issued Accounting Standards
Update No. 2016-08 (“Update 2016-08”), Revenue from Contracts with Customers
(Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross
versus Net). In May 2016, FASB issued Accounting Standards Update No.
2016-12 (“Updated 2016-12”), Revenue from Contracts with Customers (Topic
606), Narrow-Scope Improvements and Practical Expedients. Both Update
2016-10 and 2016-08 provide additional guidance on how an entity should
recognize revenue when depicting the transfer of promised goods or services.
These Updates provide more guidance on identifying performance obligations and
licensing. Update 2016-12 provides additional clarification to the steps an
entity should follow to achieve the core principle of Topic 606. The guidance,
as amended, is effective for annual and interim reporting periods beginning
after December 15, 2017, with early adoption permitted for public companies
effective from annual and interim reporting periods beginning after December 31,
2016. Management has reviewed the essential provisions of all of our major
revenue contracts and our revenue recognition practices. As a result of this
review, Management does not expect a material impact on the consolidated statement
of income. Management does not plan on early adoption if the guidance in defined
in these Updates.
-F-10-
Stock Compensation
In March 2016, FASB
issued Accounting Standards Update No. 2016-09 (“Update 2016-09”), Compensation-Stock Compensation (Topic 718), Improvements to Employee
Share-Based Payment Accounting. Update 2016-09 provides guidance designed to
simplify of the accounting treatment of certain matters surrounding share-based
compensation. Update 2016-09 is effective for annual periods beginning after
December 15, 2016, and interim periods within those annual periods. Changes
related to the timing of when excess tax benefits are recognized, minimum
statutory withholding requirements, forfeitures, and intrinsic value should be
applied using a modified retrospective transition method by means of
cumulative-effect adjustment to equity as of the beginning of the period in
which the guidance is adopted. It is likely that some of the guidance in Update
2016-09, related to public entities, will apply to our Company. Management is
currently evaluating the possible impact this Update may have on the financial
presentation of the Company’s consolidated financial statements.
Leases
In February 2016, the Financial
Accounting Standards Board (“FASB”) issued Accounting Standards Update No.
2016-02 (“Update 2016-02”), Leases (Topic 842). Update 2016-02 recognizes
lease assets and lease liabilities on the balance sheet and requires disclosing
key information about leasing arrangements. Under previous standards, assets and
liabilities were only recognized for leases that met the definition of a capital
lease. Our preliminary review indicates that certain of the Company’s lease
contracts would be subject to the reporting requirements defined by Update
2016-02. The Update is effective for public companies with fiscal years
beginning after December 15, 2018, including interim periods within those fiscal
years. Early adoption is permitted. In transition, the Company would be required
to recognize and measure leases at the beginning of the earliest period being
presented using a modified retrospective approach. Management is still
evaluating the possible impact this Update may have on the financial
presentation of the Company’s consolidated financial statements.
-F-11-
NOTE 3 – RESTRICTED CASH AND BOND RESERVES
Under the terms of the loan agreements with the Department of Energy and Prudential Capital Group, various bond and cash reserves are required to provide assurances that the power plants will have the necessary funds to maintain expected operations and meet loan payment obligations. Restricted cash balances and bond reserves are summarized as follows:
Current restricted cash and bond reserves:
| December 31, | |||||||
| Restricting Entities/Purpose | 2016 | 2015 | |||||
| Idaho Department of Water Resources, Geothermal Well Bond | $ | 260,000 | $ | 260,000 | |||
| Bureau of Land Management, Geothermal Lease Bond- Gerlach | 10,000 | 10,000 | |||||
| State of Nevada Division of Minerals, Statewide Drilling Bond | 50,000 | 50,000 | |||||
| Bureau of Land Management, Geothermal Lease Bonds- USG Nevada | 150,000 | 150,000 | |||||
| Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program | 400,000 | 400,000 | |||||
| Prudential Capital Group, Cash Reserves | 284,621 | 2,259 | |||||
| Prudential Capital Group, Debt Service Reserves (USG Nevada LLC) | 1,600,597 | 1,595,555 | |||||
| Bureau of Land Management , Geothermal Rights Lease Bond | 10,000 | 10,000 | |||||
| U.S. Department of Energy, Debt Service Reserve | 2,011,445 | 2,118,193 | |||||
| State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond | 100,000 | 100,000 | |||||
| Prudential Capital Group, Debt Service Reserves (Idaho USG Holdings LLC) | 1,755,776 | - | |||||
| CAISO, Transmission Interconnection Escrow Deposits | 1,895,023 | - | |||||
| $ | 8,527,462 | $ | 4,696,007 | ||||
-F-12-
Long-term restricted cash and bond reserves:
| December 31, | |||||||
| Restricting Entities/Purpose | 2016 | 2015 | |||||
| Nevada Energy, PPA Security Bond | $ | 1,468,898 | $ | 1,468,898 | |||
| Prudential Capital Group, Maintenance Reserves (USG Nevada LLC) | 1,081,744 | 708,300 | |||||
| Prudential Capital Group, Well Reserves (USG Nevada LLC) | 951,486 | 314,590 | |||||
| Prudential Capital Group, Maintenance Reserves (Idaho USG Holdings LLC) | 1,807,890 | - | |||||
| Prudential Capital Group, Capital Expenditure Reserves (Raft River Energy I LLC) | 3,796 | - | |||||
| U.S. Department of Energy, Operations Reserves | 270,000 | 270,000 | |||||
| U.S. Department of Energy, Debt Service Reserves | 2,413,951 | 2,542,058 | |||||
| U.S. Department of Energy, Short Term Well Field Reserves | 4,508,650 | 4,507,110 | |||||
| U.S. Department of Energy, Long-Term Well Field Reserves | 5,175,777 | 4,966,543 | |||||
| U.S. Department of Energy, Capital Expenditure Reserves | 2,429,158 | 2,718,290 | |||||
| $ | 20,111,350 | $ | 17,495,789 | ||||
The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance (see note 2 for details). The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at December 31, 2016 and 2015.
NOTE 4 - PROPERTY, PLANT AND EQUIPMENT
During the year ended December 31, 2016, the Company focused development activities on the Raft River Energy I, San Emidio Phase II, Guatemala and the WGP Geysers projects. At Raft River, a new well production leg was completed in September 2016. The well construction and related costs totaled approximately $3,894,000. Drilling and testing costs of approximately $950,000 were capitalized for the San Emidio Phase II project. Drilling and reservoir analysis costs that exceeded $1,448,000 were capitalized in Guatemala. Costs were capitalized at WGP Geysers for permitting and an interconnection study that totaled approximately $1,174,000.
During the year ended December 31, 2015, the Company focused development activities on the San Emidio Phase II; Guatemala, Crescent Valley and WGP Geysers projects. Drilling and testing costs of approximately $665,000 were incurred on the San Emidio Phase II. Drilling costs exceeded $1,526,000 in Guatemala. Drilling costs of approximately $1,096,000 were incurred on the first production well at Crescent Valley. Costs were incurred at WGP Geysers for site preparation, an interconnection study and well field testing that totaled approximately $1,551,000. In September 2015, the Company disposed of the fully depreciated old power plant located in San Emidio, Nevada at its historical cost of $2,275,475. In November 2015, the Company purchased all of the long lead equipment for the construction of three binary geothermal power plants for $1.5 million.
-F-13-
Property, plant and equipment, at cost, are summarized as follows:
| December 31, | ||||||
| 2016 | 2015 | |||||
| Land | $ | 3,116,262 | $ | 3,074,052 | ||
| Power production plant | 159,876,162 | 159,800,893 | ||||
| Grant proceeds for power plants | (52,965,236 | ) | (52,965,236 | ) | ||
| Wells | 71,340,305 | 67,621,167 | ||||
| Grant proceeds for wells | (3,464,555 | ) | (3,464,555 | ) | ||
| Furniture and equipment | 4,491,058 | 3,668,984 | ||||
| 182,393,996 | 177,735,305 | |||||
| Less: accumulated depreciation | (37,216,385 | ) | (31,021,494 | ) | ||
| 145,177,611 | 146,713,811 | |||||
| Construction in progress | 25,123,738 | 21,022,981 | ||||
| $ | 170,301,349 | $ | 167,736,792 | |||
Depreciation expense charged to plant operations and administrative costs for the years ended December 31, 2016 and 2015, was $6,284,405 and $6,228,133; respectively.
Changes in construction in progress are summarized as follows:
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| Beginning balances | $ | 21,022,981 | $ | 15,652,722 | ||
| Development/construction | 8,116,725 | 5,370,259 | ||||
| Placed into operation | (4,015,968 | ) | - | |||
| Ending balances | $ | 25,123,738 | $ | 21,022,981 | ||
-F-14-
Constructions in Progress, at cost, consisting of the following projects/assets by location are as follows:
| December 31, | |||||||
| 2016 | 2015 | ||||||
| Raft River, Idaho: | |||||||
| Unit I, well improvements | $ | 5,377 | $ | 105,160 | |||
| Unit I, plant improvements | 108,555 | - | |||||
| Unit II, power plant, substation and transmission lines | 751,618 | 750,493 | |||||
| Unit II, well construction | 2,149,835 | 2,146,531 | |||||
| 3,015,385 | 3,002,184 | ||||||
| San Emidio, Nevada: | |||||||
| Unit II, power plant, substation and transmission lines | 426,941 | 426,942 | |||||
| Unit II, well construction | 4,748,924 | 3,798,563 | |||||
| 5,175,865 | 4,225,505 | ||||||
| Neal Hot Springs, Oregon: | |||||||
| Power plant and facilities | 73,761 | 50,297 | |||||
| Well construction | 378,098 | 314,360 | |||||
| 451,859 | 364,657 | ||||||
| WGP Geysers, California: | |||||||
| Power plant and facilities | 325,989 | 325,989 | |||||
| Well construction | 8,865,093 | 7,690,748 | |||||
| 9,191,082 | 8,016,737 | ||||||
| Crescent Valley, Nevada: | |||||||
| Well construction | 1,655,653 | 1,228,888 | |||||
| El Ceibillo, Republic of Guatemala: | |||||||
| Well construction | 5,625,394 | 4,176,510 | |||||
| Plant and facilities | 8,500 | 8,500 | |||||
| 5,633,894 | 4,185,010 | ||||||
| $ | 25,123,738 | $ | 21,022,981 | ||||
-F-15-
NOTE 5 – INTANGIBLE ASSETS
Intangible assets, at cost, are summarized by project location as follows:
| December 31, | |||||||
| 2016 | 2015 | ||||||
| In operation: | |||||||
| Neal Hot Springs, Oregon: | |||||||
| Geothermal water and mineral rights | $ | 625,337 | $ | 625,337 | |||
| San Emidio, Nevada: | |||||||
| Geothermal water and mineral rights | 4,825,220 | 4,825,220 | |||||
| Less: accumulated amortization | (1,480,804 | ) | (1,299,119 | ) | |||
| 3,969,753 | 4,151,438 | ||||||
| Inactive: | |||||||
| Raft River, Idaho: | |||||||
| Surface water rights | 146,342 | 146,342 | |||||
| Geothermal water and mineral rights | 1,281,540 | 1,281,540 | |||||
| Guatemala City, Guatemala: | |||||||
| Geothermal water and mineral rights | 625,000 | 625,000 | |||||
| Gerlach, Nevada: | |||||||
| Geothermal water and mineral rights | 997,000 | 997,000 | |||||
| Crescent Valley, Nevada: | |||||||
| Geothermal water and mineral rights | 451,608 | 451,608 | |||||
| The Geysers, California: | |||||||
| Geothermal water rights | 278,872 | 278,872 | |||||
| San Emidio, Nevada: | |||||||
| Surface water rights | 4,323,520 | 4,323,520 | |||||
| Geothermal water and mineral rights | 3,440,580 | 3,440,580 | |||||
| Less: prior accumulated amortization | (430,072 | ) | (430,072 | ) | |||
| 11,114,390 | 11,114,390 | ||||||
| $ | 15,084,143 | $ | 15,265,828 | ||||
Amortization expense was charged to plant operations for the years ended December 31, 2016 and 2015 that amounted to $181,685 and $181,685; respectively.
-F-16-
NOTE 6 – INCOME TAXES
The significant components of the deferred income taxes are:
| December 31, | |||||||
| 2016 | 2015 | ||||||
| Long-term deferred tax assets: | |||||||
| Net operating loss carry forward | $ | 35,893,000 | $ | 33,716,000 | |||
| Stock based compensation | 1,052,000 | 1,432,000 | |||||
| Tax credit carryforward and other | 156,000 | - | |||||
| Long-term deferred tax liabilities: | |||||||
| Depreciation and amortization | (28,755,000 | ) | (26,227,000 | ) | |||
| Total deferred tax assets | 8,346,000 | 8,921,000 | |||||
| Less: valuation allowance | - | - | |||||
| Net deferred income tax assets | $ | 8,346,000 | $ | 8,921,000 | |||
Income before income taxes consists of the following:
| For the Year ended December 31, | |||||||
| 2016 | 2015 | ||||||
| United States | $ | 4,335,369 | $ | 6,543,299 | |||
| Foreign | (175,021 | ) | (206,801 | ) | |||
| 4,160,348 | 6,336,498 | ||||||
| Income attributable to non-controlling interests | (3,122,017 | ) | (3,103,269 | ) | |||
| Income attributable to U.S. Geothermal Inc. | $ | 1,038,331 | $ | 3,233,229 | |||
The Company’s estimated effective income tax rates are as follows:
| For the Year Ended December 31, | |||||||
| 2016 | 2015 | ||||||
| U.S. Federal statutory rate | 34.0% | 34.0% | |||||
| Average State and foreign income tax, net of federal tax effect | 1.2 | 3.5 | |||||
| Impact of state deferred rate decrease | (3.0 | ) | - | ||||
| Stock based compensation | 7.8 | - | |||||
| Other | (0.6 | ) | - | ||||
| Consolidated tax rate before non-controlling interest | 39.4 | 37.5 | |||||
| Tax effect of non-controlling interests | (25.5 | ) | (18.4 | ) | |||
| Net effective tax rate | 13.9% | 19.1% | |||||
-F-17-
The provision (benefit) for income taxes consists of the following:
| For the Year Ended December 31, | |||||||
| 2016 | 2015 | ||||||
| Current: | |||||||
| United States | $ | - | $ | - | |||
| Foreign | - | - | |||||
| - | - | ||||||
| Deferred: | |||||||
| United States | 575,000 | 1,386,000 | |||||
| Foreign | - | - | |||||
| Provision from income taxes | $ | 575,000 | $ | 1,386,000 | |||
The provision for income taxes reflects an estimated effective income tax rate attributable to U.S. Geothermal Inc.’s share of income. Our provision for income taxes for the year ended December 31, 2016, reflects a reported effective tax rate of 13.9%, which differs from the statutory federal income tax rate of 34.0% primarily due to the impact of the non-controlling interest, stock compensation and state income taxes.
At December 31, 2016, the Company had net income tax operating loss carry forwards of approximately $102,000,000, which expire in the years 2023 through 2036. Approximately $97,000,000 of the operating losses were generated by the Company, the residual originated from acquired subsidiaries.
In 2014, the Company purchased a group of companies. Federal and applicable state net operating losses that totalled approximately $5.8 million were included in the acquisition. These NOLs are scheduled to expire in the years ending 2024 through 2034. The use of these net operating losses is restricted by the Company’s basis (acquisition price) and the “applicable federal rate” as defined by Section 382 of federal tax law. The estimated available net operating losses from the acquired companies were approximately $4,950,000 at December 31, 2016.
Accounting for Income Tax Uncertainties and Related
Matters
The Company files income tax returns in the U.S.
federal jurisdiction and in the States of Idaho, California and Oregon. These
filings are generally subject to a three year statute of limitations, but do
remain open to Internal Revenue Service adjustments for net operating loss
carryforward. No filings are currently under examination.
The Company currently does not have any uncertain tax positions to disclose. In the event that the Company is assessed interest or penalties on uncertain tax positions at some point in the future, it will be classified in the financial statements as tax expense.
NOTE 7 – LONG TERM NOTES PAYABLE
Prudential Capital Group – Idaho USG Holdings
LLC
In May 2016, the Company’s wholly owned subsidiary (Idaho USG
Holdings LLC) entered into a loan agreement with the Prudential Capital Group to
finance the Company’s development activities. The original principal totaled $20
million and included the option to issue additional debt up to $50 million
within the next two years. The original $20 million loan amount bears interest
at a fixed interest rate of 5.8% per annum. The principal and interest payments
are due semi-annually at amounts based upon a 20-year amortization period and
the scheduled remaining balance of $16,009,495 is due in full at the end of the
7 year term. The loan is secured by the Company’s ownership interests in the
Neal Hot Springs (Oregon USG Holdings LLC and USG Oregon LLC) and the Raft River
(Raft River Energy I LLC) projects. At December 31, 2016, the balance of the loan was
$19,915,115 (current portion $618,640) and the net unamortized debt issuance
costs associated with this loan totaled $742,873 ($821,070, less amortized costs
of $78,197).
-F-18-
U.S. Department of Energy – USG Oregon LLC
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the
Company, completed the first funding drawdown associated with the U.S.
Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to
construct its power plant at Neal Hot Springs in Eastern Oregon (the “Project”).
All loan advances covered by the Loan Guarantee have been made under the Future
Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the
occurrence and continuation of an event of default under the transaction
documents, all amounts payable under the Note may e accelerated. In connection
with the Loan Guarantee, the DOE has been granted a security interest in all of
the equity interests of USG Oregon, as well as in the assets of USG Oregon,
including a mortgage on real property interests relating to the Project site. No
additional advances are allowed under the terms of the loan. A total of 13 draws
were taken and each individual draw or tranche is considered to be a separate
loan. The loan principal is scheduled to be paid over 21.5 years from the first
scheduled payment date with semi-annual installments including interest
calculated at an aggregate fixed interest rate of 2.598%. The principal payment
amounts are calculated on a straight-line basis according to the life of the
loans and the original loan principal amounts. The principal portion of the
aggregate loan payment is adjusted as individual tranches are extinguished. The
principal payments started at $1,709,963 on February 10, 2014 and are scheduled
to be reduced to $1,499,259 on February 10, 2017 and continue through February
12, 2035. The loan balance at December 31, 2016 totaled $60,171,274 (current
portion $2,998,518).
Loan advances/tranches and effective annual interest rates are details as follows:
| Annual Interest | |||||||
| Description | Amount | Rate % | |||||
| Advances by date: | |||||||
| August 31, 2011* | $ | 2,328,422 | 2.997 | ||||
| September 28, 2011 | 10,043,467 | 2.755 | |||||
| October 27, 2011 | 3,600,026 | 2.918 | |||||
| December 2, 2011 | 4,377,079 | 2.795 | |||||
| December 21, 2011 | 2,313,322 | 2.608 | |||||
| January 25, 2012 | 8,968,019 | 2.772 | |||||
| April 26, 2012 | 13,029,325 | 2.695 | |||||
| May 30, 2012 | 19,497,204 | 2.408 | |||||
| August 27, 2012 | 7,709,454 | 2.360 | |||||
| December 28, 2012 | 2,567,121 | 2.396 | |||||
| June 10, 2013 | 2,355,316 | 2.830 | |||||
| July 3, 2013* | 2,242,628 | 3.073 | |||||
| July 31, 2013* | 4,026,582 | 3.214 | |||||
| 83,057,965 | |||||||
| Principal paid through December 31, 2016 | (22,886,691 | ) | |||||
| Loan balance at December 31, 2016 | $ | 60,171,274 |
* - Individual tranches have been fully extinguished.
Prudential Capital Group – USG Nevada LLC
On
September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC)
entered into a note purchase agreement with the Prudential Capital Group to
finance the Phase I San Emidio geothermal project located in northwest Nevada.
The term of the note is approximately 24 years, and bears interest at fixed rate
of 6.75% per annum. Interest payments are due quarterly. Principal payments are
due quarterly based upon minimum debt service coverage ratios established
according to projected operating results made at the loan origination date and
available cash balances. The loan agreement is secured by USG Nevada LLC’s
right, title and interest in and to its real and personal property, including
the San Emidio project and the equity interests in USG Nevada LLC. At December
31, 2016, the balance of the loan was $29,041,531 (current portion
$638,949).
-F-19-
Auto Loan
On July 28, 2016, the Company’s
wholly owned subsidiary (U.S. Geothermal Services) purchased a truck with down
payments that totaled $39,496 and a loan agreement with Chrysler Capital. The
loan requires total monthly payments of $313, including interest at an average
rate of 6.74% per annum until July 2018. The note is secured by the vehicle. At
December 31, 2016, the loan balance totaled $5,634 (current portion $3,488).
Based upon the terms of the notes payable and expected conditions that may impact some of those terms, the total estimated annual principal payments were calculated as follows:
| For the Year Ended | Principal | |||
| December 31, | Payments | |||
| 2017 | $ | 4,259,595 | ||
| 2018 | 3,978,248 | |||
| 2019 | 4,301,749 | |||
| 2020 | 4,585,944 | |||
| 2021 | 4,920,589 | |||
| Thereafter | 87,087,429 | |||
| $ | 109,133,554 |
NOTE 8 – COMMON STOCK
Stock Purchase Agreement
On
January 25, 2016, the Company entered into a Purchase Agreement with Lincoln
Park Capital (“LPC”). Under the Purchase Agreement, the Company has the right to
sell and LPC has the obligation to purchase up to $10 million of equity capital
over a 30-month period. During the quarter ended March 31, 2016, the Company
issued 2,463,810 (410,635 adjusted for share consolidation) shares of common
stock at prices between $0.58 and $0.61 ($3.48 and $3.66 adjusted for share
consolidation) per share under the Purchase Agreement.
Share Consolidation (Reverse Stock Split)
On November 9, 2016, the Company effected a 1-for-6 share
consolidation of its outstanding common stock. All share and per share amounts
for all periods presented in these consolidated financial statements and notes
have been adjusted retrospectively, where applicable, to reflect this share
consolidation.
To reflect the reverse stock split on shareholder’s equity, we reclassified an amount equal to the par value of the reduced shares from the common stock par value to additional paid in capital, which had no net impact to shareholders’ equity on our consolidated balance sheet. All per share information in our consolidated financial statements and applicable disclosures have been retroactively adjusted to reflect the reverse stock split. Proportional adjustments were, also, be made to all shares of common stock issuable under the Company’s stock incentive plans and common stock purchase warrants.
-F-20-
NOTE 9 - STOCK BASED COMPENSATION
The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing the interests of the Company. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of December 31, 2016, the Company can issue stock option grants totaling up to 2,845,567 shares. Options are typically granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options.
The following table reflects the summary of stock options outstanding at January 1, 2015 and changes for the years ended December 31, 2015 and 2016:
| Weighted | |||||||||
| Average | |||||||||
| Number of | Exercise | Aggregate | |||||||
| shares under | Price Per | Intrinsic | |||||||
| options | Share | Value | |||||||
| Balance outstanding, January 1, 2015 | 1,968,083 | $ | 3.72 | $ | 4,273,243 | ||||
| Forfeited/Expired | (258,333 | ) | 5.16 | - | |||||
| Exercised | (25,833 | ) | 1.92 | - | |||||
| Granted | 418,333 | 4.44 | - | ||||||
| Balance outstanding, December 31, 2015 | 2,102,250 | 3.42 | 3,940,061 | ||||||
| Forfeited/Expired | (398,790 | ) | 4.95 | - | |||||
| Exercised | (342,129 | ) | 2.54 | - | |||||
| Granted | 463,333 | 4.04 | - | ||||||
| Balance outstanding, December 31, 2016 | 1,824,664 | $ | 3.38 | $ | 3,186,265 | ||||
| Vested and expected to vest at December 31, 2016 | 1,806,417 | $ | 3.38 | $ | 3,154,402 |
The fair value of the stock options granted was estimated using the Black-Scholes-Merton option-pricing model and is amortized over the vesting period of the underlying options. The assumptions used to calculate the fair value are as follows:
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| Dividend yield | 0 | 0 | ||||
| Expected volatility | 65% | 65% | ||||
| Risk free interest rate | 0.58% | 0.58% | ||||
| Expected life (years) | 3.26 | 3.26 | ||||
-F-21-
Changes in the subjective input assumptions can materially affect the fair value estimate and, therefore, the existing models do not necessarily provide a reliable measure of the fair value of the Company’s stock options.
The following table summarizes information about the stock options outstanding at December 31, 2016:
| OPTIONS OUTSTANDING | ||||||||||||||
| REMAINING | NUMBER OF | |||||||||||||
| EXERCISE | NUMBER OF | CONTRACTUAL | OPTIONS | |||||||||||
| PRICE | OPTIONS | LIFE (YEARS) | EXERCISABLE | INTRINSIC VALUE | ||||||||||
| $ | 1.86 | 114,164 | 0.65 | 114,164 | $ | 106,559 | ||||||||
| 2.76 | 221,655 | 1.56 | 221,655 | 323,055 | ||||||||||
| 2.10 | 208,333 | 6.30 | 208,333 | 337,977 | ||||||||||
| 2.46 | 2,500 | 1.67 | 2,500 | 3,012 | ||||||||||
| 4.44 | 431,989 | 2.25 | 431,989 | 1,047,282 | ||||||||||
| 2.88 | 314,785 | 3.37 | 314,785 | 386,646 | ||||||||||
| 3.18 | 75,000 | 3.48 | 75,000 | 114,522 | ||||||||||
| 3.78 | 144,575 | 4.22 | 72,288 | 114,277 | ||||||||||
| 4.02 | 149,998 | 4.25 | 74,999 | 134,805 | ||||||||||
| 4.26 | 103,333 | 4.28 | 51,666 | 97,346 | ||||||||||
| 4.50 | 25,000 | 4.66 | 6,250 | 10,192 | ||||||||||
| 4.32 | 33,332 | 4.75 | 8,333 | 14,716 | ||||||||||
| 1,824,664 | 3.28 | 1,581,962 | $ | 2,690,389 | ||||||||||
At December 31, 2016, total compensation cost related to stock options granted under the Stock Plan but not yet recognized was $294,990 net of estimated forfeitures.
Common Stock Compensation Plan (Restricted Shares)
Restricted shares are issued to the recipients when granted and held by the Company until vested. The recipients meet the vesting requirements by maintaining employment and good standing with the Company through the vesting period. After vesting, there are no restrictions on the shares.
The following table summarizes restricted stock activity under the Stock Plan for 2016 and 2015:
| Shares | Issue Price | |||||
| Unvested at January 1, 2015 | 93,187 | $ | 2.88 | |||
| Granted | 71,399 | 3.02 | ||||
| Vested | (93,187 | ) | 2.88 | |||
| Unvested at December 31, 2016 | 71,399 | 3.02 | ||||
| Granted | 60,833 | 4.07 | ||||
| Vested | (71,399 | ) | 3.02 | |||
| Unvested December 31, 2016 | 60,833 | $ | 4.07 | |||
| Expected to vest after December 31, 2016 | 60,833 | $ | 4.07 |
At December 31, 2016, total compensation cost related to restricted stock granted under the Stock Plan but not yet recognized was $63,800 net of estimated forfeitures. This cost will be amortized on the straight-line method over a period of approximately 0.5 years.
-F-22-
Stock Purchase Warrants
At December 31, 2016, the outstanding share purchase warrants totaled 385,139 with a warrant exercise price of $3.00 per warrant and expire December 26, 2017.
During the quarter ended December 31, 2016, broker warrants that totaled 42,618 were exercised by a broker at the exercise price of $2.62.
During the quarter ended June 30, 2016, stock purchase warrants that totaled 166,667 were exercised by an investor at the exercise price of $3.00.
NOTE 10 – FAIR VALUE MEASUREMENT
U.S. generally accepted accounting principles establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).
The three levels of the fair value hierarchy are as
follows:
Level 1 – Quoted prices are available in active markets for identical assets or
liabilities.
Level 2 – Directly or indirectly market based inputs or observable inputs used
in models or other valuation
methodologies.
Level 3 – Unobservable inputs that are not corroborated by market data. The
inputs require significant
management
judgement or estimation.
The following table discloses, by level within the fair value hierarchy, the Company’s assets and liabilities measured and reported on its Consolidated Balance Sheet at fair value on a recurring basis:
At December 31, 2016:
| Total | Level 1 | Level 2 | Level 3 | |||||||||
| Assets: | ||||||||||||
| Money market accounts * | $ | 37,347,897 | $ | 37,347,897 | $ | - | $ | - |
At December 31, 2015:
| Total | Level 1 | Level 2 | Level 3 | |||||||||
| Assets: | ||||||||||||
| Money market accounts * | $ | 27,921,666 | $ | 27,921,666 | $ | - | $ | - |
* - Money market accounts include both restricted and unrestricted funds.
NOTE 11 – POWER PURCHASE AGREEMENTS
Raft River Energy I LLC
The Company signed a power
purchase agreement with Idaho Power Company for the sale of power generated from
its joint venture Raft River Energy I LLC. The Company also signed a
transmission agreement with Bonneville Power Administration for transmission of
electricity from this plant to Idaho Power. These agreements will govern the
operational revenues for the initial phases of the Company’s operating
activities. The contract allows power sales up to 13 megawatts annual average.
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 (March, April,
May) 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 megawatt 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.
-F-23-
USG Nevada LLC
As a part of the purchase of the
assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition
(“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power
Company was assigned to the Company. The contract had a stated expected output
of 3,250 kilowatts maximum per hour and extended through 2017. During the year
ended March 31, 2012, the power purchase agreement was replaced by a new amended
and restated 25 year contract signed in December of 2011 that sets the new rate
at $89.75 per megawatt hour with a 1% annual escalation rate. The new contract
currently allows for a maximum of 73,444 megawatt hours annually that will be
paid for at the full contract price. Upon declaration of commercial operation
under the PPA, an Operating Security Deposit is required to be maintained at NV
Energy for the full term of the PPA. As of December 31, 2016, the Company had
funded a security deposit of $1,468,898.
USG Oregon LLC
In December of 2009, the Company’s
subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power
Company for the sale of power generated by the Neal Hot Springs, Oregon project.
The agreement has a term of 25 years and provides for the purchase of power up
to 25 megawatts (22 megawatt planned annual average output level). Beginning
2012, the flat energy price is $96.00 per megawatt hour. The price escalates
annually by 3.9% in the initial years and by 1.0% during the latter years of the
agreement.
NOTE 12 - COMMITMENTS AND CONTINGENCIES
Operating Lease Agreements
The Company incurred total geothermal and mineral operating lease expenses for the years ended December 31, 2016 and 2015 of $722,499 and $523,658; respectively. Included in the total lease expense are minimum lease payments of $323,714 and $164,405 and royalty based contingent lease expense of $398,785 and $359,253 for the years ended December 31, 2016 and 2015; respectively.
BLM Lease Agreements
Idaho
On August 1, 2007, the Company signed a
geothermal resources lease agreement with the United States Department of the
Interior Bureau of Land Management (“BLM”). The contract requires an annual
payment of $3,502 including processing fees. The primary term of the agreement
is 10 years. After the primary term, the Company has the right to extend the
contract. BLM has the right to terminate the contract upon written notice if the
Company does not comply with the terms of the agreement.
San Emidio
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 40 years if the BLM does not need the land for
any other purpose and the lessee is maintaining production at commercial
quantities. The leases require the lessee to conduct operations in a manner that
minimizes adverse impacts to the environment.
-F-24-
Gerlach
The Gerlach Geothermal LLC assets are
comprised of two BLM geothermal leases and one private lease totaling 2,986
acres. Both BLM leases have a royalty rate which is based upon 10% of the value
of the resource at the wellhead. The amounts are calculated according to a
formula established by Minerals Management Service (“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.
Other Lease Agreements
Neal Hot Springs, Oregon
The Company holds 3 lease
contracts for approximately 7,429 acres of geothermal water rights located in
the Neal Hot Springs area near Vale, Oregon. The contracts have stated terms of
10 years with expiration dates that range from May 2015 to November 2019. The
two major contracts are royalty based. One of the agreements 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. The second agreement defines a royalty rate based upon 2%
of the actual revenue for the first 10 years of commercial production and 3%
thereafter. As of January 2013, USG Oregon LLC began paying monthly royalties
under both royalty based contracts based on electricity delivery under the Idaho
Power Purchase Agreement.
Raft River Energy I LLC
The Company has entered into
several lease contracts for approximately 5,144 acres of land and geothermal
water rights located in the Raft River area located in Southern Idaho. Two
contracts renew automatically upon receipt of annual payment, the residual have
expiration terms from 5 to 30 years with expiration dates that range from
January 2016 to December 2034. Six contracts have a royalty rate provision of
10% of net income calculated with specified depreciation methods.
The Geysers, California
On April 22, 2014, the
Company acquired companies that held five significant lease contracts for
approximately 3,809 acres (6.0 square miles) of land and geothermal water rights
in The Geysers area located in Northern California. The contracts have stated
expiration dates, expiring from February 2017 to October 2019. The remaining
contracts renew indefinitely with payments made within contracted terms (held by
payment).
Crescent Valley, Nevada
On December 12, 2014, the
Company acquired Earth Power Resources Inc. that held 63 lease contracts for
approximately 26,017 acres located in the central area of the State of Nevada.
The contracts have stated terms of 10 to 40 years with expiration dates that
range from February 2015 to June 2054.
Office Lease
On August 12, 2013, the Company signed
a 5 year lease agreement for office space and janitorial services. The lease
payments are due in monthly installments starting February 1, 2014. The monthly
payments that began February 1, 2014 have two components which include a base
rate of $3,234 that is not subject to increase and a rate beginning at $6,418
that is adjusted annually according to the cost of living index. The contract
includes a 5 year extension option. For the years ended December 31, 2016 and
2015, the office lease costs totaled $115,830 and $106,178; respectively.
-F-25-
The following is the total remaining contracted lease operating obligations (operating leases, BLM lease agreements and office leases) for the next five years and thereafter:
| Years Ending | ||||
| December 31, | Amount | |||
| 2017 | $ | 1,109,686 | ||
| 2018 | 1,015,397 | |||
| 2019 | 901,791 | |||
| 2020 | 881,712 | |||
| 2021 | 810,726 | |||
| Thereafter | 12,714,238 |
Parental Guaranty Agreement
Under the
terms of PPA, Raft River Energy I, LLC (“RREI”) is required to provide a
Seller’s Performance Assurance. On April 29, 2011, U.S. Geothermal Inc.
(“Guarantor”) signed a Parental Guaranty Agreement with RREI’s energy purchaser
(“Beneficiary”) that extends credit to RREI (“Debtor”). The agreement provides
for assurances related to possible obligations related to purchases, exchanges,
sales or transportation of energy from contacts entered into by the Beneficiary
and Debtor. The agreement insures the Beneficiary for damages up to a maximum of
$750,000.
401(k) Plan
The Company offers a
defined contribution plan qualified under section 401(k) of the Internal Revenue
Code to all its eligible employees. All employees are eligible at the beginning
of the quarter after completing 3 months of service. The Company matches 50% of
the employee’s contribution up to 6%. Employees may contribute up to the maximum
allowed by the Internal Revenue Code. The Company made matching contributions to
the plan that totaled $101,992 and $100,872 for the years ended December 31,
2016 and 2015, respectively.
NOTE 13 – ASSET RETIRMENT OBLIGATIONS
The Geysers, California
On April 22, 2014, the
Company completed the acquisition of a group of companies owned by Ram Power
Corp.’s (“Ram”) Geysers Project located in Northern California. Two of the
acquired companies (Western GeoPower, Inc. and Etoile Holdings, Inc.) contained
asset retirement obligations that, primarily, originate with the environmental
regulations defined by the laws of the State of California. The liabilities
related to the removal and disposal of arsenic impacted soil and existing steam
conveyance pipelines are estimated to total $598,930. Obligations related to
decommissioning four existing wells were estimated to total $606,000. These
obligations are initially estimated based upon discounted cash flows estimates
and are accreted to full value over time. At December 31, 2016, the Company has
not considered it necessary to specifically fund these obligations. During the
year ended December 31, 2015, the Company engaged in activities that reduced the
estimated liability related to the site’s impacted soil. Since the Company is
still evaluating the development plan for this project that could eliminate or
significantly reduce the remaining obligations, no charges directly associated
the asset retirement obligations have been charged to operations. All of the
obligations were considered to be long-term at December 31, 2016 and 2015.
-F-26-
Raft River Energy I LLC, USG Nevada LLC, and USG Oregon
LLC
These Companies operate in Idaho, Nevada and Oregon and
are subject to environmental laws and regulations of these states. The plants,
wells, pipelines and transmission lines are expected to have long useful lives.
Generally, these assets will require funds for retirement or reclamation.
However, these estimated obligations are believed to be less than the assets’
estimated salvage values. Therefore, as of December 31, 2016 and 2015, no
retirement obligations have been recognized.
| For the Year Ended December 31, | ||||||
| 2016 | 2015 | |||||
| Beginning balance | $ | 1,204,930 | $ | 1,400,000 | ||
| Soil remediation | - | (209,070 | ) | |||
| Accretion | 14,973 | 14,000 | ||||
| Ending balance | $ | 1,219,903 | $ | 1,204,930 | ||
NOTE 14 – JOINT VENTURES/NON-CONTROLLING INTERESTS
Non-controlling interests included on the consolidated balance sheets of the Company are detailed as follows:
| December 31, | ||||||
| 2016 | 2015 | |||||
| Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC | $ | 207,217 | $ | 213,882 | ||
| Oregon USG Holdings LLC interest held by Enbridge Inc. | 25,361,410 | 25,353,058 | ||||
| Raft River Energy I LLC interest held by Goldman Sachs | 1,011,363 | 2,044,984 | ||||
| $ | 26,579,990 | $ | 27,611,924 | |||
Gerlach Geothermal LLC
On April 28,
2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our
partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint
venture is the exploration of the Gerlach geothermal system, which is located in
northwestern Nevada, near the town of Gerlach. Based upon the terms of the
members’ agreement, the Company owned a 60% interest and GGE owned a 40%
interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to
maintain its 40% ownership interest as additional capital contributions are
required. If GGE dilutes to below a 10% interest, their ownership position in
the joint venture would be converted to a 10% net profits interest. The Company
has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral
rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights
and exploration data. During the years ended December 31, 2014 and 2015, the
Company contributed $496,000 for the project’s drilling costs that were not
proportionally matched by GGE. These contributions effectively reduced GGE’s
ownership interest to 31.34%, and increased the Company’s interest to 68.73% as
of December 31, 2015. During the year ended December 31, 2016, the Company
contributed $19,042 to support the project’s operations that were not
proportionally matched by GGE. These contributions effectively further reduced
GGE’s ownership interest to 31.01%, and increased the Company’s interest to
68.99%.
The consolidated financial statements reflect 100% of the assets and liabilities of Gerlach, and report the current non-controlling interest of GGE. The full results of Gerlach’s operations are reflected in the statement of income and comprehensive income with the elimination of the non-controlling interest identified.
-F-27-
Oregon USG Holdings LLC
In September
2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”),
signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to
participate in the Company’s Neal Hot Springs project located in Malheur County,
Oregon. On February 20, 2014, a new determination under the existing agreement
was reached with Enbridge that established their ownership interest percentage
at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has
a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of
$32,801,000, including the debt conversion, to Oregon Holdings in exchange for a
direct ownership interest. During the years ended December 31, 2016 and 2015,
distributions were made to the Company that totaled $6,107,217 and $5,193,883;
respectively. During the years ended December 31, 2016 and 2015, distributions
were made to Enbridge that totaled $4,071,478 and $3,462,588.
The consolidated financial statements reflect 100% of the assets and liabilities of Oregon Holdings and USG Oregon LLC, and report the current non-controlling interest of Enbridge. The full results of Oregon Holdings and USG Oregon LLC’s operations are reflected in the statement of income and comprehensive income with the elimination of the non-controlling interest identified.
Raft River Energy I LLC (“RREI”)
Raft River
Energy I is a joint venture between the Company and Goldman Sachs. An Operating
Agreement governs the rights and responsibilities of both parties. At December
31, 2016, the Company had contributed approximately $17.9 million in cash and
property, and Goldman Sachs has contributed approximately $34.1 million in cash.
Profits and losses are allocated to the members based upon contractual terms.
The initial contracted terms stated that the Company would be allocated 70% of
energy credit sales and 1% of the residual income/loss excluding energy credit
sales. Under the terms of the amended agreement that became effective December
16, 2015, the Company will receive a 95% interest in RREI’s cash flows. Under
the terms of both agreements, Goldman Sachs receives a greater proportion of the
share of profit or losses for income tax purposes/benefits. This includes the
allocation of profits and losses as well as production tax credits, which will
be distributed 99% to Goldman Sachs and 1% to the Company during the first 10
years of production, which ends December 31, 2017. During the year ended
December 31, 2016, RREI distributed funds to the Company and Goldman Sachs of
$1,203,349 and $82,473; respectively. During the year ended December 31, 2016,
the Company made contributions of $3,349,087 to RREI to support well
construction.
The consolidated financial statements reflect 100% of the assets and liabilities of RREI, and report the current non-controlling interest of Goldman Sachs. The full results of RREI’s operations are reflected in the statement of income and comprehensive income with the elimination of the non-controlling interest identified.
Additional Interest in Raft River Energy I LLC/Promissory
Note
On December 16, 2015, the Company signed a purchase
agreement with Goldman Sachs for the acquisition of the majority of the cash
flow interest in Raft River Energy I LLC (“RREI”) for the total purchase price
of $5.1 million. The purchase consisted of a $3.5 million cash payment plus a
promissory note of $1.6 million that was paid in full on March 31, 2016.
-F-28-
NOTE 15 – BUSINESS SEGMENTS
The Company has two reportable segments: Operating Plants, and Corporate and Development. These segments are managed and reported separately due to dissimilar economic characteristics. Operating plants are engaged in the sale of electricity from the power plants pursuant to long-tern PPAs. Corporate and development costs are intended to produce additional revenue generating projects. A summary of financial information concerning the Company’s reportable segments is shown in the following table:
| Operating | Corporate & | |||||||||
| Plants | Development | Consolidated | ||||||||
| Total Assets: | ||||||||||
| December 31, 2016 | $ | 188,682,162 | $ | 54,742,170 | $ | 243,424,332 | ||||
| December 31, 2015 | 186,989,224 | 41,227,903 | 228,217,127 | |||||||
| For the Year Ended December 31, | ||||||||||
| 2016: | ||||||||||
| Operating Revenues | $ | 31,481,675 | $ | - | $ | 31,481,675 | ||||
| Net Income (Loss) | 10,625,887 | (7,040,539 | ) | 3,585,348 | ||||||
| 2015: | ||||||||||
| Operating Revenues | 31,200,098 | - | 31,200,098 | |||||||
| Net Income (Loss) | 10,849,514 | (5,899,016 | ) | 4,950,498 |
-F-29-
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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 Exchange Act 1934 as of December 31, 2016. 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 December 31, 2016.
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
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- 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 December 31, 2016. 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 – 2013). Based on its assessment, management concluded that, as of December 31, 2016, the Company’s internal control over financial reporting is effective based on those criteria.
Our independent registered public accounting firm, Moss Adams LLP, independently assessed the effectiveness of the company’s internal control over financial reporting, as stated in the firm’s attestation report, which is included within Part II, Item 8 of this Form 10-K.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no changes in internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) during the year ended December 31, 2016, that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
U.S. Geothermal
Inc.
We have audited U.S. Geothermal Inc.’s (the Company) internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with 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 (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, U.S. Geothermal Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of U.S. Geothermal Inc. as of December 31, 2016 and December 31, 2015, and the consolidated statements of income, changes in stockholders’ equity, and cash flows for each of the years then ended, and our report dated March 9, 2017, expressed an unqualified opinion on those consolidated financial statements.
/s/ Moss Adams LLP
Seattle, Washington
March 9, 2017
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Item 9B. Other Information
None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Directors and Executive Officers
The Board of Directors (the “Board”) of the Company is currently composed of eight directors: Dennis J. Gilles, Douglas J. Glaspey, Ali G. Hedayat, Randolph J. Hill, Paul A. Larkin, Leland L. Mink, James C. Pappas and John H. Walker. The majority of the Board, made up of Mr. Hedayat, Mr. Hill, Mr. Larkin, Dr. Mink, Mr. Pappas and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT LLC (“NYSE MKT”), and National Instrument 58-101, Disclosure of Corporate Governance Practices and Multilateral Instrument 52-110, Audit Committees. Mr. Gilles and Mr. Glaspey do not satisfy such independence requirements based on their employment as executive officers of the Company. The Board has one class of members that is elected at each annual shareholders meeting to hold office until the next annual shareholders meeting or until their successors have been duly elected and qualified.
Dennis J. Gilles: Age 58, has served as the Chief Executive Officer since April 2013 and a director of the Company since September 2011. Mr. Gilles also currently serves as a Director and Executive Board Officer of the Geothermal Resource Council. Mr. Gilles is a senior executive with 30 years of experience in the management, operations, maintenance, engineering, construction and administration of power and petrochemical plants and their related facilities. Mr. Gilles’ primary activities have included the identification, evaluation and acquisition of existing renewable projects or portfolios, as well as heading development of new green-field opportunities. During his 23 year career with Calpine Corporation as Senior Vice President, Mr. Gilles managed the Company’s geothermal portfolio of 750 megawatts at the Geysers geothermal field where he was instrumental in consolidating the majority of the ownership interests into a single entity. Mr. Gilles was part of the expansion and growth of Calpine Corporation from the very first megawatt to what is now the largest independent power producer in the United States. Mr. Gilles holds a Masters of Business Administration and a Bachelor of Science in Mechanical Engineering. Mr. Gilles’ qualifications to serve as a director of the Company include his over 35 years of experience in the energy industry and his many years of senior management and director experience.
Douglas J. Glaspey: Age 64, is the co-founder, President and Chief Operating Officer and a director of the Company. He has served as a director of the Company since March 2000, President of the Company since September 2011, and Chief Operating Officer of the Company since December 2003. Mr. Glaspey served from March 2000 until December 2004 as the President and Chief Executive Officer for the TSX Venture Exchange (“TSX-V”) listed U.S. Cobalt Inc. until the acquisition of Geo-Idaho in December 2003. He also served as a director and the Chief Executive Officer of Geo-Idaho from February 2002 until the acquisition of Geo-Idaho in December 2003. During his career in the mining industry, he has held operating positions with ASARCO, Earth Resources Company, Asamera Minerals, Atlanta Gold Corporation and Twin Gold Corporation. Mr. Glaspey has 38 years of operating and management experience. He holds a Bachelor of Science in Mineral Processing Engineering and an Associate of Science in Engineering Science. His experience includes public company financing and administration, production management, planning and directing resource exploration programs, preparing feasibility studies and environmental permitting. He has formed and served as an executive officer of several private resource development companies in the United States, including Drumlummon Gold Mines Corporation and Black Diamond Corporation. He is currently a director of TSX-V listed Thunder Mountain Gold, Inc., which is also quoted on the OTC Bulletin Board. Mr. Glaspey’s qualifications to serve as a director of the Company include his over 38 years of experience in the natural resource industry and his many years of senior management and director experience.
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Ali G. Hedayat: Age 41, serves as a director of the Company effective February 1, 2017. Mr. Hedayat is the founder and Managing Director of Maryana Capital in Toronto, Canada. He previously co-founded Edoma Capital in London, was a Partner at Indus Capital in London, and worked for the Goldman Sachs Group in New York and London as a Managing Director and Co-head of Americas Principal Strategies. Mr. Hedayat currently serves as a Director for Restaurant Brands International Inc., and has previously served as a Director for companies in the cable, pharmaceutical and media industries. Mr. Hedayat holds a Bachelor of Commerce degree, with honors, earning a double major in Finance and Economics from McGill University. His qualifications to serve as a Director of the Company include over 20 years of investment banking experience with an emphasis in power, utilities, and distressed debt and equity in European, North American and Latin American markets.
Randolph J. Hill: Age 61, serves as a director of the Company effective September 30, 2016. Mr. Hill is a corporate lawyer with Stoel Rives with significant experience in corporate governance, mergers and acquisitions, energy and infrastructure development, project financing, and EPC, design-build and management and operations contracting, and also serves as Chair of the Idaho Energy Resources Authority and a member of the Board of Governors of the Andrus Center for Public Policy at Boise State University. He has previously worked as Chief Legal Officer for a major division of AECOM (previously Washington Group International and then URS through successive mergers), as General Counsel and then President and CEO for Ida-West Energy, and as a corporate lawyer at a premier Wall Street law firm. He has previously served as a director for the Boise Metro Chamber of Commerce (one year as Chair), the Idaho Association of Commerce and Industry, and the Women’s and Children’s Alliance (four years as President). Mr. Hill holds a law degree from Georgetown University Law Center and a bachelor’s degree from George Washington University. Mr. Hill’s qualifications to serve as a director of the Company include his many years of senior management, legal and energy industry experience.
Paul Larkin: Age 66, serves as a director of the Company, a position he has held since March 2000. He served as Secretary of the Company from March 2000 until December 2003, and has served as Chairman of the Audit Committee from 2003 to present. He also served as a director and the Secretary-Treasurer of Geo-Idaho from February 2002 until its acquisition in December 2003. Since 1983, Mr. Larkin has also been the President of the New Dawn Group, an investment and financial consulting firm located in Vancouver, British Columbia, and a director and officer of various TSX-V listed companies. New Dawn is primarily involved in corporate finance, merchant banking and administrative management of public companies. Mr. Larkin held various accounting and banking positions for over a decade before founding New Dawn in 1983, and currently serves on the boards of the following companies which are listed on the TSX-V: Esrey Energy Ltd., Condor Resources Ltd., Tyner Resources Ltd. Gstaad Capital Corp., Westbridge Energy Corp., and Velocity Minerals Ltd. Mr. Larkin’s qualifications to serve as a director of the Company include his many years of senior leadership and management experience in corporate finance, merchant banking and administrative management of public companies.
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Dr. Leland “Roy” Mink: Age 76, serves as a director of the Company, a position he has held since November 2006. Dr. Mink holds a PhD in Geology from the University of Idaho and is currently self-employed as President of Mink GeoHydro Inc conducting consulting activities in hydrogeology and geothermal resource evaluations. He served as Program Director for the Geothermal Technologies Program at the U.S. Department of Energy (DOE) from February 2003 to October 2006. Prior to working for the DOE, Dr. Mink was the Vice President of Exploration for the Company from June 2002 to February 2003. He has also worked for Morrison-Knudsen Corporation, Idaho Bureau of Mines and Geology and Idaho Water Resources Research Institute. Dr. Mink serves on the Geothermal Resources Board of Directors and is a member of the Geothermal Energy Association. His qualifications to serve as a director of the Company include his many years of senior leadership and management experience in the geothermal energy industry.
James C. Pappas: Age 35, serves as a director of the Company effective September 30, 2016. Mr. Pappas founded JCP Investment Management in Houston in June 2009 and is the Managing Member and owner of the Firm. Since January 2015, Mr. Pappas has served as a director of Jamba, Inc., a leading health and wellness brand and the leading retailer of freshly squeezed juice, where he is also a member of each of the Nominating and Corporate Governance Committee and the Audit Committee. Mr. Pappas also currently serves as a director of Tandy Leather Factory, Inc., a specialty retailer and wholesale distributor of leather and leather related products. Previously, Mr. Pappas served on the Board of Directors of The Pantry, Inc., has also served as Chairman of the Board of Directors of Morgan’s Foods, and has also served as a director of Samex Mining Corp. From 2005 until 2007, Mr. Pappas worked for The Goldman Sachs Group, Inc. in their Investment Banking / Leveraged Finance Division. As part of the Goldman Sachs Leveraged Finance Group, Mr. Pappas advised private equity groups and corporations on appropriate leveraged buyout, recapitalization and refinancing alternatives. Prior to Goldman Sachs, Mr. Pappas worked at Banc of America Securities, the investment banking arm of Bank of America, where he focused on Consumer and Retail Investment Banking, providing advice on a wide range of transactions including mergers and acquisitions, financings, restructurings and buy-side engagements. Mr. Pappas received a BBA in Information Technology, and a Masters in Finance from Texas A&M University. His qualifications to serve as a director of the Company includes his years of investment banking and director experience.
John H. Walker: Age 67, is a director and the Chairman of the Board of Directors of the Company. He has held that position since December 2003. He is also a Managing Director of Kensington Capital Partners Ltd and a National Director of Trout Unlimited Canada. Mr. Walker has a 38 year history in urban planning, energy security and power plant development in Ontario and internationally as well as experience on both public and private sector boards. Mr. Walker was a founding director of the Greater Toronto Airports Authority in 1992 and chaired the first Planning and Development Committee of the Board which provided oversight in the construction of CDN$4.4 billion terminal complex at Toronto Pearson Airport completed in 2004. He was instrumental in the development of a 117 megawatt cogeneration power plant at Toronto Pearson Airport which commenced operations in 2005. Additionally, he was a founding Director of the Borealis Infrastructure Fund which is now owned by Ontario Municipal Employee Retirement System (OMERS). Mr. Walker has worked in the financial services community as an investment banker with Loewen Ondaatje McCutcheon and has served on the Board of Directors of Sheridan College Institute of Technology and Advanced Learning. His background includes 10 years at Ontario Hydro where he was responsible for site selection, alternative energy and international market development. Mr. Walker has also acted as a senior advisor to Falconbridge on the Koniambo project, a CDN$3 billion nickel smelter, mine, power plant and port project in New Caledonia. Mr. Walker advises corporations on matters related to infrastructure and energy development and acts as a developer of power plants. Mr. Walker is a Registered Professional Planner in the Province of Ontario and a member of the Canadian Institute of Planners. Mr. Walker has a BSc. from Springfield College and a Masters of Environmental Studies (Urban and Regional Planning) from York University. Mr. Walker’s qualifications to serve as a director of the Company include his many years of senior leadership and management experience in international business development.
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Additional Executive Officers Who are Not Directors
Kerry D. Hawkley: Age 63, serves as the Chief Financial Officer and Corporate Secretary of the Company. He has served as the Company’s controller since July 2003, and became CFO as of January 1, 2005. From July 2003 to December 2004, he also provided consulting services to Triumph Gold Corp. From 1998 to June 2003, Mr. Hawkley served as controller, director and treasurer of LB Industries. Mr. Hawkley has over 39 years of experience in all areas of accounting, finance and administration. He holds Bachelor of Business Administration degrees in Accounting and Finance. He started his career as an internal auditor with Union Pacific Corporation and has held various accounting management positions in the oil and gas, truck leasing, mining and energy industries.
Jonathan Zurkoff: Age 60, serves as the Treasurer and Executive Vice President of the Company, a position he has held since September 2011. From January 2009 to May 2009, Mr. Zurkoff served as a financial consultant to the Company. He then served as the Vice President Finance of the Company from June 2009 until September 2011. Mr. Zurkoff served as CFO of Tamarack Resorts from 2004 to 2008. Mr. Zurkoff has over 25 years of experience in engineering, construction, and all phases of project development with an emphasis on project and corporate finance. Mr. Zurkoff holds a Masters of Business Administration, a Masters of Science in Groundwater Hydrology, and a Bachelor of Science in Geology. Mr. Zurkoff has held positions in Tamarack Resort (CFO), Process Technologies (CFO & COO), and Morrison Knudsen Corporation (now URS).
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our executive officers and directors, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of ownership and reports of changes in ownership of our securities with the SEC. Executive officers, directors and greater than 10% shareholders are required to furnish us with copies of these reports. Based solely on our review of the Section 16(a) reports furnished to us with respect to the year ended December 31, 2016 and written representations from our executive officers, directors and greater than 10% shareholders, we believe that all Section 16(a) filing requirements applicable to our executive officers, directors and greater than 10% shareholders were satisfied. A Form 4 for Randolph Hill was filed one day late due to a delay in the issuance in his EDGAR codes by the SEC.
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Code of Ethics
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 http://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 on our
website. 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 on our website. No waivers were granted during the year ended December
31, 2016. 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.
Audit Committee and Audit Committee Financial Expert
Our Board of Directors 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 Randolph J. Hill, Ali G. Hedayat, Paul A. Larkin, Leland L. Mink and John H. Walker. 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.
Item 11. Executive Compensation
Our compensation philosophy is to structure compensation awards to members of our executive management that directly align their personal interests with those of our shareholders. Our executive compensation program is intended to attract, motivate, reward and retain the management talent required to achieve our corporate objectives and increase shareholder value, while at the same time making the most efficient use of shareholder resources. This compensation philosophy puts a strong emphasis on pay for performance, and uses equity awards as a significant component in order to correlate the long-term growth of shareholder value with management’s most significant compensation opportunities.
The three primary components of total direct compensation for our senior executives are:
- base salary;
- annual cash incentive bonus opportunity; and
- stock options and restricted stock.
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The relative weighting of the three components of compensation is designed to strongly reward long-term performance, by heavily emphasizing the proportion of long-term equity compensation.
The Compensation and Benefits Committee is appointed annually by the Board of Directors to discharge the Board’s responsibilities relating to compensation and benefits of the executive officers of our Company. The goals of the committee are to attract, retain and motivate our executive officers by providing appropriate levels of compensation and benefits while taking into consideration, among such other factors as it may deem relevant, our Company’s performance, shareholder returns, the value of similar incentive awards to executive officers at comparable companies and the awards given to the executive officers in past years. The main categories of compensation available to the committee are base salary, discretionary annual performance bonuses, stock option grants, stock awards, and insurance reimbursements.
We compete with a variety of companies for our executive-level employees. The Compensation and Benefits Committee uses base salary to compensate the executive officers for services rendered. Base salaries are intended to be competitive for companies of similar size and purpose, also taking into consideration individual factors such as experience, tenure, institutional knowledge and qualifications. An informal review of several public junior resource development companies was completed to provide the committee with comparative compensation information. The committee looked at Alterra, Calpine, Ormat, Chesapeake, Algonquin Power, Boralex, Caribbean Utilities, Maxim Power, Etrion, and Atlantic Power, who are involved in either geothermal development, mineral exploration, electrical power generators or other similar activities. Base salaries are reviewed annually to determine whether they are consistent with our overall compensation objectives. In considering increases in base salary, the Compensation and Benefits Committee reviews individual and corporate performance, market and industry conditions, and our overall financial health.
While the Company does not attach a weighting to the various components of executive compensation, the Compensation and Benefits Committee attempts to pay a competitive salary (retention) to its executives while providing long-term incentive to the executives through equity awards (ownership/reward) in order to align their interest with the long-term progression of the Company as a whole. Our Chief Executive Officer and Compensation and Benefits Committee perform an informal annual review of compensation practices of similar sized companies to educate themselves of the general parameters (levels and types of compensation) for executive compensation. They do not, however, benchmark the various components of pay. The review highlights areas of our executive pay package that may not be consistent with compensation practices at similar sized companies and provides the committee with knowledge of the compensation landscape for its executives.
The Compensation and Benefits Committee may grant annual performance bonuses as a reward for achievement of individual and corporate short-term goals. Any grant of an annual performance bonus is discretionary and the amount is determined after a recommendation from the CEO with input from other executive officers. Bonus amounts are dependent upon our financial and operational performance as well as the completion of specific milestone events by the individual executive officer.
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Generally, the Compensation and Benefits Committee grants stock options to all employees, including executive officers, for motivation and retention purposes annually after completion of our annual financial reports. Stock options are granted with an exercise price equal to the market value of our common stock on the date of the grant, and typically with a term of five years. The timing of the stock option grant is not coordinated with the release of material non-public information and is typically occurs during the second fiscal quarter. The options typically vest 25% on the date of grant, and another 25% each six months thereafter. During the fiscal year ended December 31, 2016, stock option grants to executive officers represented approximately 45% of the total stock option grants to all employees. During the year ended December 31, 2015, stock option grants to executive officers represented approximately 47% of the total stock option grants to all employees. We do not have a formal procedure for determining factors to consider when making grants. The committee uses an informal review of similar sized companies engaged in natural resource development to assist in determining the appropriate levels of stock option. In 2015, the percentage of votes cast “For” our advisory “say on pay” resolution to approve our executive compensation was 88.4% . The Board and the Compensation and Benefits Committee considered the results of the advisory vote and no significant changes have been made to the executive compensation programs based on the 2015 “say on pay” results.
Our executive officers do not normally receive any material incremental benefits that are not otherwise available to all of our employees. Our health and dental insurance plans are the same for all employees.
Gilles Employment Agreement
Effective April 19,
2013, Dennis J. Gilles entered into an employment agreement as the Company’s new
Chief Executive Officer. The initial term of employment will be from April 19,
2013 until the earlier of April 18, 2015 or termination of employment in
accordance with the terms of the employment agreement. The employment agreement
will automatically renew at the end of the initial term, and at the end of each
subsequent term, for an additional one year term unless either the Company or
Mr. Gilles gives written notice of non-renewal to the other party at least 90
days prior to expiration of the then-current term. Effective January 9, 2017,
the Company and Dennis Gilles, the Company’s Chief Executive Officer, entered
into an amendment (the “Amendment”) to Mr. Gilles’ employment agreement (the
“Agreement”) to extend the current term of the Agreement by three months. The
initial term of the Agreement was from April 19, 2013 until the earlier of April
18, 2015 or termination of employment in accordance with the terms of the
Employment Agreement.
The Agreement automatically renewed at the end of the initial term, and at the end of each subsequent term, for an additional one year term unless either the Company or Mr. Gilles gives written notice of non-renewal to the other party at least 90 days prior to expiration of the then-current term. The current term of the Agreement ends on April 18, 2017 (the “Current Term”). The Amendment extends the Current Term by three (3) months, such that the Current Term of the Agreement now ends on July 18, 2017. As a result of the extension of the Current Term, any notice of non-renewal delivered pursuant to the Agreement must now be delivered no later than April 19, 2017, which is ninety (90) days prior to the expiration of the Current Term. If a notice of non-renewal is not delivered in accordance with the Agreement, the Agreement shall automatically renew at the end of the Current Term on July 18, 2017, for an additional one (1) year term. No other terms of the Agreement were amended.
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The Company has agreed to pay to Mr. Gilles an annual base salary of $375,000, which increased to $410,000 on April 19, 2014 and will remain in place as a minimum annual base salary during all successive periods under the employment agreement. In addition, Mr. Gilles received a signing bonus of $100,000 payable in the Company’s common stock and cash to cover the tax impact of the stock bonus. Mr. Gilles was also granted 50,000 restricted shares of the Company’s common stock, and a non-qualified stock option to acquire a total of 208,333 shares of the Company’s common stock at a price of $2.10 per share with a term of 10 years. Until the earlier of expiration or termination of the employment agreement, the Company has agreed to provide Mr. Gilles, at the Company’s expense, a $1,000,000 life insurance policy that names the Gilles Family Trust as the beneficiary in the event of the death of Mr. Gilles. Mr. Gilles will be eligible to earn annual bonuses with the target amount being 100% of his annual base salary payable in a combination of cash and restricted shares of the Company’s common stock, provided that no more than one-half of the annual bonus will be paid in the form of restricted shares. The actual bonus amount will be subject to the discretion of the Company’s board of directors and its Compensation and Benefits Committee. On April 18, 2014, Mr. Gilles was granted 66,667 stock options to acquire shares of the Company’s common stock at an exercise price of $4.44, a cash bonus of $150,000 and 54,167 shares of restricted stock with a one-year vesting period. On June 26, 2015, Mr. Gilles was granted 75,000 stock options to acquire shares of the Company’s common stock at an exercise price of $3.18, a cash bonus of $102,500 and 32,233 shares of restricted stock with a one-year vesting period. On April 18, 2016, Mr. Gilles was granted 103,333 stock options at an exercise price of $4.26, a cash bonus of $75,000, unrestricted common shares valued at $60,000, and 30,833 restricted shares with a one-year vesting period. On subsequent annual anniversaries, Mr. Gilles will be eligible to receive stock option awards at a similar level with the actual amount determined by the Company’s board of directors. Mr. Gilles and his immediate family will be eligible to participate in the Company’s employee health insurance, dental insurance, retirement plan 401(k) and any other employee benefit plans in accordance with the terms and conditions of such plans. Mr. Gilles is entitled to five weeks of vacation within each 12-month period under the employment agreement. Subject to certain limitations and conditions, the Company will also reimburse Mr. Gilles for all reasonable expenses incurred in connection with his employment and the cost of travel between the Company’s office in Boise, Idaho and his home. In addition, Mr. Gilles has received cost reimbursement for a single relocation for costs of $35,000.
The Company may terminate Mr. Gilles’ employment at any time for “cause” upon at least 15 days’ notice. In such event, Mr. Gilles will only be entitled to compensation through the date of termination. Mr. Gilles may terminate his employment at any time without “good reason” (which is defined in the employment agreement) upon 60 days’ notice. Mr. Gilles will be paid his salary through the date designated in the notice, plus payment for unused vacation days granted or accrued and reimbursement for expenses incurred through the date of termination.
In the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason”, Mr. Gilles will be entitled to receive a lump sum payment equal to one and one-half (1.5) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Mr. Gilles also will receive a lump sum cash payment equal to 24 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.
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In the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason” within 12 months following a “change of control” (which is defined in the employment agreement) or a “change of control” occurs within 12 months following such termination, Mr. Gilles will receive total severance payments equal to three (3) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within 18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Any vested stock options held by Mr. Gilles will remain exercisable until the expiration of the original term of such option. If such termination occurs within 12 months following a “change of control”, Mr. Gilles will receive a lump sum cash payment equal to 36 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.
The Company has agreed to defend and indemnify Mr. Gilles in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Gilles with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Gilles with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach,
Glaspey Employment Agreement
The Company has entered
into an employment agreement with Douglas J. Glaspey as the Company’s President
and Chief Operating Officer. The initial term of employment will be from July 1,
2013 until the earlier of June 30, 2015 or termination of employment in
accordance with the terms of the employment agreement. The employment agreement
will automatically renew at the end of the initial term, and at the end of each
subsequent term, for an additional one year term unless either the Company or
Mr. Glaspey gives written notice of non-renewal to the other party at least 60
days prior to expiration of the then-current term.
The Company has agreed to pay to Mr. Glaspey compensation of $224,180 per annum, to grant to Mr. Glaspey cash or stock bonus and/or stock options in such amount and under such conditions as may be determined by the Company’s board of directors, to provide to Mr. Glaspey (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company, to provide to Mr. Glaspey reasonable life insurance and accidental death coverage (with the proceeds payable to Mr. Glaspey’s estate or specified family member), and to provide to Mr. Glaspey such 401(k) retirement benefit as is available to other employees of the Company. In addition, the Company will reimburse Mr. Glaspey for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Glaspey is entitled to a paid vacation of five weeks within each 12 month period under the terms of the employment agreement.
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The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, the Company may terminate the employment agreement upon one month’s written notice and Mr. Glaspey may terminate the employment agreement upon 60 days’ written notice.
In the event that Mr. Glaspey’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Glaspey, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Glaspey is entitled to receive compensation equal to 24 monthly installments of his normal compensation on the 30th day after the date of termination (which sum would be currently $448,360). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.
The Company has agreed to defend and indemnify Mr. Glaspey in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Glaspey with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Glaspey with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach.
Hawkley Employment Agreement
The Company has entered
into an employment agreement with Kerry D. Hawkley as the Company’s Chief
Financial Officer. The initial term of employment will be from July 1, 2013
until the earlier of June 30, 2015 or termination of employment in accordance
with the terms of the employment agreement. The employment agreement will
automatically renew at the end of the initial term, and at the end of each
subsequent term, for an additional one year term unless either the Company or
Mr. Hawkley gives written notice of non-renewal to the other party at least 60
days prior to expiration of the then-current term.
The Company has agreed to pay to Mr. Hawkley compensation of $182,962 per annum, to grant to Mr. Hawkley cash or stock bonus and/or stock options in such amount and under such conditions as may be determined by the Company’s board of directors, to provide to Mr. Hawkley (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company, and to provide to Mr. Hawkley such 401(k) retirement benefit as is available to other employees of the Company. In addition, the Company will reimburse Mr. Hawkley for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Hawkley is entitled to a paid vacation of five weeks within each 12 month period under the terms of the employment agreement.
The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, the Company may terminate the employment agreement upon one month’s written notice and Mr. Hawkley may terminate the employment agreement upon 60 days’ written notice.
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In the event that Mr. Hawkley’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Hawkley, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Hawkley is entitled to receive compensation equal to 18 monthly installments of his normal compensation on the 30th day after the date of termination (which sum would be currently $274,443). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.
The Company has agreed to defend and indemnify Mr. Hawkley in connection with legal claims, lawsuits, cause of action or liabilities asserted against him arising out of or related to his employment with the Company and to provide Mr. Hawkley with an advance for any expenses in connection with such defense and/or indemnification. The employment agreement also includes covenants by Mr. Hawkley with respect to the treatment of confidential information, non-competition and non-solicitation, and provides for equitable relief in the event of breach.
Zurkoff Employment Agreement
The Company has entered
into an amendment to the employment agreement with Jonathan Zurkoff as the
Company’s Executive Vice President, Finance. The employment agreement, as
amended five times, is effective December 31, 2010, and will remain in effect
until March 31, 2018 unless earlier terminated in accordance with its terms.
The Company has agreed to pay to Mr. Zurkoff compensation of $160,000 per annum pursuant to the employment agreement. This salary may be adjusted annually on the anniversary date of the employment agreement and is currently $195,840 per annum. The Company has also agreed to provide to Mr. Zurkoff such 401(k) retirement benefit as is available to other employees of the Company, and to provide to Mr. Zurkoff (and his immediate family) such medical, dental and related benefits as are available to other employees of the Company. In addition, the Company will reimburse Mr. Zurkoff for reasonable expenses incurred in connection with the performance of his duties under the employment agreement. Mr. Zurkoff is entitled to a paid vacation of 20 days within each 12 month period under the terms of the employment agreement.
The employment agreement may be terminated by the Company without notice, payment in lieu of notice, severance payments, benefits, damages or other sums for causes which include failure to perform his duties in a competent and professional manner, appropriation of corporate opportunities or failure to disclose a material conflict of interest, a plea of guilty to, or conviction of, an indictable offense which may not be further appealed, fraud, dishonesty, illegality or gross incompetence, failure to disclose material facts concerning business interests or other employment that are relevant to his employment with the Company, refusal to follow reasonable and lawful directions of the Company, breach of fiduciary duty, and material breach under, or gross negligence in connection with his employment under, the employment agreement. Otherwise, either party may terminate the employment agreement upon one month’s written notice.
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In the event that Mr. Zurkoff’s employment is terminated without “cause” by the Company or for “good reason” by Mr. Zurkoff, and in the event that a “change of control” has occurred within the 12 months prior to the termination, Mr. Zurkoff is entitled to receive compensation equal to 18 monthly installments of his normal compensation on the 30th day after the date of termination (which sum would be currently $293,760). The terms “cause”, “good reason” and “change of control” are defined in the employment agreement.
The employment agreement also includes covenants by Mr. Zurkoff with respect to the treatment of confidential information and non-competition, and provides for equitable relief in the event of breach.
Summary Compensation Table
The following table shows the compensation for the last two years awarded to or earned by our Chief Executive Officer and each of our three other most highly compensated executive officers (collectively, our “Named Executive Officers”).
Name and principal position(s) |
Year Ended |
Salary (1) ($) |
Bonus (2) ($) |
Option Awards (3) ($) |
Stock Awards (4) ($) |
All other compensation (5) ($) |
Total ($) |
| Dennis J. Gilles, Chief Executive Officer (effective 4/19/13) |
12/31/15 | 410,000 | 102,500 | 114,524 | 156,000 | 2,750 | 785,774 |
| 12/31/16 | 398,961 | 75,000 | 194,679 | 162,500 | 2,110 | 833,250 | |
| Douglas J. Glaspey, President and Chief Operating Officer |
12/31/15 | 220,000 | 0 | 85,113 | 14,000 | 1,035 | 320,148 |
| 12/31/16 | 202,441 | 9,000 | 77,888 | 0 | 1,035 | 290,364 | |
| Kerry D. Hawkley, Chief Financial Officer |
12/31/15 | 179,375 | 8,969 | 40,317 | 11,351 | 0 | 240,012 |
| 12/31/16 | 182,065 | 10,000 | 53,923 | 19,200 | 0 | 265,188 | |
| Jonathan Zurkoff, Treasurer and Executive Vice President |
12/31/15 | 192,000 | 9,600 | 32,754 | 12,973 | 0 | 247,327 |
| 12/31/16 | 194,880 | 8,000 | 47,821 | 16,800 | 0 | 267,501 | |
| (1) |
Dollar value of base salary (cash and non-cash) earned by the Named Executive Officer during the fiscal year. |
| (2) |
Dollar value of bonus (cash and non-cash) earned by the Named Executive Officer during the fiscal year. Bonuses are eligible to all employees and submitted and approved by the Board annually. |
| (3) |
Stock options are valued at the grant date in accordance with FASB ASC Topic 718. |
| (4) |
Stock awards (restricted shares) are valued at grant date. |
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| (5) |
Other compensation consists of all other compensation not disclosed in another category. |
Outstanding Equity Awards at Fiscal Year-End
The following table shows the unexercised stock options, unvested restricted stock, and other equity incentive plan awards held at the year ended December 31, 2016 by our Named Executive Officers.
| Option Awards | Stock Awards | ||||||||||||
| Number of | Number of | ||||||||||||
| Securities | Securities | Number of | Market Value of | ||||||||||
| Underlying | Underlying | Shares or Units | Shares or Units of | ||||||||||
| Unexercised | Unexercised | Option | Option | of Stock That | Stock That Have | ||||||||
| Options | Options (1) | Exercise Price | Expiration | Have Not Vested | Not Vested | ||||||||
| Name | (#) Exercisable | (#) Unexercisable | ($) | Date | (#) | ($) | |||||||
| Dennis J. Gilles | 16,666 | 0 | 1.86 | 8/24/17 | 0 | 0 | |||||||
| Douglas J. Glaspey | 15,000 | 0 | 1.86 | 8/24/17 | 0 | 0 | |||||||
| Dennis J. Gilles | 208,333 | 0 | 2.10 | 4/19/23 | 0 | 0 | |||||||
| Douglas J. Glaspey | 25,000 | 0 | 2.76 | 7/22/18 | 0 | 0 | |||||||
| Kerry D. Hawkley | 20,833 | 0 | 2.76 | 7/22/18 | 0 | 0 | |||||||
| Jonathan Zurkoff | 20,833 | 0 | 2.76 | 7/22/18 | 0 | 0 | |||||||
| Dennis J. Gilles | 66,666 | 0 | 4.44 | 4/2/19 | 0 | 0 | |||||||
| Douglas J. Glaspey | 36,666 | 0 | 4.44 | 4/2/19 | 0 | 0 | |||||||
| Kerry D. Hawkley | 29,166 | 0 | 4.44 | 4/2/19 | 0 | 0 | |||||||
| Jonathan Zurkoff | 29,166 | 0 | 4.44 | 4/2/19 | 0 | 0 | |||||||
| Douglas J. Glaspey | 63,333 | 0 | 2.88 | 5/15/20 | 0 | 0 | |||||||
| Kerry D. Hawkley | 30,000 | 0 | 2.88 | 5/15/20 | 0 | 0 | |||||||
| Jonathan Zurkoff | 26,666 | 0 | 2.88 | 5/15/20 | 0 | 0 | |||||||
| Dennis J. Gilles | 75,000 | 0 | 3.18 | 6/26/20 | 0 | 0 | |||||||
| Douglas J. Glaspey | 21,667 | 21,666 | 4.02 | 3/31/21 | 4,166 | 16,750 | |||||||
| Kerry D. Hawkley | 15,000 | 15,000 | 4.02 | 3/31/21 | 3,888 | 15,633 | |||||||
| Jonathan Zurkoff | 15,000 | 15,000 | 4.02 | 3/31/21 | 3,333 | 13,400 | |||||||
| Dennis J. Gilles | 51,667 | 51,666 | 4.26 | 4/11/21 | 30,833 | 131,350 | |||||||
| (1) | The $4.02 options unexercisable at December 31, 2016 will fully vest on September 30, 2017. |
| The $4.26 options unexercisable at December 31, 2016 will fully vest on October 11, 2017. |
Potential Payments Upon Termination or Change-in-Control
Except as discussed below under “Potential Payments Upon Change-in-Control,” or as noted under the employment agreement for Mr. Gilles, if the employment of any of our Named Executive Officers is voluntarily or involuntarily terminated, no additional payments or benefits will accrue or be paid to him, other than what the officer has accrued and is vested in under the benefit plans. A voluntary or involuntary termination will not trigger an acceleration of the vesting of any outstanding stock options or shares of restricted stock.
Potential Payments Upon Change-in-Control. We have entered into employment agreements with Messrs. Gilles, Glaspey, Hawkley and Zurkoff which provide for change-in-control payments.
Mr. Gilles employment agreement provided that in the event Mr. Gilles’ employment is terminated by the Company without “cause” or by Mr. Gilles for “good reason” within 12 months following a “change of control” (which is defined in the employment agreement) or a “change of control” occurs within 12 months following such termination, Mr. Gilles will receive total severance payments equal to three (3) times the sum of his second year base salary ($410,000) plus annual target bonus. In addition, any unvested stock options to acquire shares of the Company’s common stock and any unvested restricted shares of the Company’s common stock held by Mr. Gilles as of the termination date that would have vested within 18 months following such termination date had Mr. Gilles’ employment continued will become fully vested. Any vested stock options held by Mr. Gilles will remain exercisable until the expiration of the original term of such option. If such termination occurs within 12 months following a “change of control”, Mr. Gilles will receive a lump sum cash payment equal to 36 times the Company’s contribution to the monthly cost of the medical and dental benefits provided to Mr. Gilles under the employment agreement.
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Mr. Glaspey’s employment agreement provides that if within twelve months following a “change of control” Mr. Glaspey’s employment is terminated either by the Company without “cause”, or by Mr. Glaspey for “good reason”, then Mr. Glaspey will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 24 times his monthly base salary at termination, and (c) employee medical and dental coverage for 24 months or until Mr. Glaspey commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-incontrol” are defined in the agreements.
Mr. Hawkley’s employment agreement provides that if within twelve months following a “change of control” Mr. Hawkley’s employment is terminated either by the Company without “cause”, or by Mr. Hawkley for “good reason”, then Mr. Hawkley will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 18 times his monthly base salary at termination, and (c) employee medical and dental coverage for 18 months or until Mr. Hawkley commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-in-control” are defined in the agreements.
Mr. Zurkoff’s employment agreement provides that if within twelve months following a “change of control” Mr. Zurkoff’s employment is terminated either by the Company without “cause”, or by Mr. Zurkoff for “good reason”, then Mr. Zurkoff will be entitled to a lump-sum payment consisting of (a) his prorated base salary through the date of termination, (b) a payment equal to 18 times his monthly base salary at termination, and (c) employee medical and dental coverage for 18 months or until Mr. Zurkoff commences alternate employment, whichever comes first, subject to certain limitations and conditions. The terms “cause,” “good reason” and “change-incontrol” are defined in the agreements.
Name |
Change of Control Salary ($) |
Change of Control Benefits ($) |
Change of Control Total ($) |
| Dennis J. Gilles | 2,460,000 | 31,121 | 2,491,121 |
| Douglas J. Glaspey | 448,360 | 24,257 | 472,617 |
| Kerry D. Hawkley | 274,443 | 17,913 | 292,356 |
| Jonathan Zurkoff | 293,760 | 16,527 | 310,287 |
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Director Compensation
The following table summarizes the compensation paid to our directors during the year ended December 31, 2016.
Name |
Fees earned or paid in cash ($) |
Stock awards ($) |
Option awards (1) ($) |
Non- equity incentive plan compens- ation ($) |
Nonqualified deferred compensa- tion earnings ($) |
All other compensa- tion ($) |
Total ($) |
| John H. Walker | 50,700 | 0 | 29,956 | 0 | 0 | 0 | 80,656 |
| Paul A. Larkin | 53,100 | 0 | 29,956 | 0 | 0 | 0 | 83,056 |
| Leland L. Mink | 40,300 | 0 | 23,965 | 0 | 0 | 0 | 64,265 |
| Randolph J. Hill | 12,250 | 0 | 29,430 | 0 | 0 | 0 | 41,680 |
| James C. Pappas | 11,850 | 0 | 29,430 | 0 | 0 | 0 | 41,280 |
| (1) |
Stock options are valued at the grant date in accordance with FASB ASC Topic 718. |
Directors who are not otherwise remunerated per an employment agreement are paid $7,500 per quarter, $1,500 per face-to-face meetings, $400 per telephone meetings, $2,500-$5,000 per annum as committee heads, and are eligible to receive awards under our equity compensation plans. Directors who are also officers do not receive any compensation for serving in the capacity of director. However, all directors are reimbursed for their out-of-pocket expenses in attending meetings.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth the number of securities authorized for issuance under the Company’s equity compensation plans as of December 31, 2016.
| Equity Compensation Plan Information | |||
Plan category |
Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) |
Weighted-average exercise price of outstanding options, warrants and rights (b) |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
| Equity compensation plans approved by security holders | 1,824,664 | $3.38 | 1,020,903 |
| Equity compensation plans not approved by security holders | Nil | Nil | Nil |
| Total | 1,824,664 | $3.38 | 1,020,903 |
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information regarding beneficial ownership of the Company’s common stock, as of December 31, 2016 by each person known by us to be the beneficial owner of more than 5% of the Company’s outstanding common stock. The percentage of beneficial ownership is based on 18,970,445 shares of the Company’s common stock outstanding as of December 31, 2016.
| Amount and Nature | |||||||
| Name and Address of Beneficial Owner | of Beneficial | Percent of | |||||
| Ownership | Class | ||||||
| JCP Investment Management, LLC | |||||||
| 1177 West Loop South, Suite 1650 | 2,854,948 | (1) | 15.05% | ||||
| Houston, TX 77027 | |||||||
| Bradley Louis Radoff | |||||||
| 1177 West Loop South, Suite 1625 | 1,825,000 | (2) | 9.62% | ||||
| Houston, TX 77027 | |||||||
| Private Management Group, Inc. | |||||||
| 15635 Alton Parkway, Suite 400 | 1,591,847 | (3) | 8.39% | ||||
| Irvine, CA 92618 |
| (1) |
As of September 30, 2016, based on information set forth in a Schedule 13D filed with the SEC on October 3, 2016 by JCP Investment Management, LLC. Each of the persons listed may be deemed to be a member of a Section 13(d) group that collectively beneficially owns more than 10% of the Issuer’s outstanding shares of Common Stock, and each such person disclaims beneficial ownership of the shares of Common Stock reported herein except to the extent of his or its pecuniary interest therein. Includes 938,360 shares of Common Stock owned directly by JCP Investment Partnership, LP (“JCP Partnership”). Also includes 1,916,588 shares of Common Stock owned directly by JCP Drawdown Partnership III, LP (“JCP Drawdown III”). JCP Partners, as the general partner of each of JCP Partnership and JCP Drawdown III, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Holdings, LLC (“JCP Holdings”), as the general partner of each of JCP Partners, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Holdings, LLC (“JCP Holdings”), as the general partner of JCP Partners, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. JCP Investment Management, LLC (“JCP Management”), as the investment manager of each of JCP Partnership and JCP Drawdown III, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. James C. Pappas, as the managing member of JCP Management and sole member of JCP Holdings, may be deemed the beneficial owner of the (i) 938,360 shares owned by JCP Partnership and (ii) 1,916,588 shares owned by JCP Drawdown III. |
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| (2) |
As of December 31, 2016, based on information set forth in a Schedule 13G/A filed with the SEC on February 13, 2017 by Bradley Louis Radoff, who has sole voting and dispositive power over 42,057 shares of the Company’s common stock and shared dispositive power over 1,782,943 shares under FMLP, Inc. |
| (3) |
As of December 31, 2016, based on information set forth in a Schedule 13G filed with the SEC on January 31, 2017 by Private Management Group, Inc., which has sole voting and dispositive power over 1,591,847 shares of the Company’s common stock. |
Security Ownership of Management
Our executive
officers and directors are encouraged to own our common stock to further align
their interests with our shareholders’ interests. The following table sets forth
certain information regarding beneficial ownership of the Company’s common
stock, as of December 31, 2016, by each of our directors, Named Executive
Officers and directors and executive officers as a group. The percentage of
beneficial ownership is based on 18,970,445 shares of the Company’s common stock
outstanding as of December 31, 2016.
| Amount and | |||||||
| Nature | |||||||
| Name of Beneficial Owner | of Beneficial | Percent of | |||||
| Ownership | Class | ||||||
| Dennis J. Gilles | 643,277 | (1) | 3.39% | ||||
| Douglas J. Glaspey | 278,280 | (2) | 1.47% | ||||
| Kerry D. Hawkley | 130,329 | (3) | * | ||||
| Randolph J. Hill | 8,333 | (4) | * | ||||
| Paul A. Larkin | 134,134 | (5) | * | ||||
| Leland L. Mink | 78,061 | (6) | * | ||||
| James C. Pappas | 2,863,281 | (7) | 15.09% | ||||
| John H. Walker | 75,606 | (8) | * | ||||
| Jonathan Zurkoff | 121,169 | (9) | * | ||||
| All directors and executive officers as a group (10 persons) | 4,332,470 | (10) | 22.84% |
| * | Less than 1% of the Company’s outstanding common stock |
| (1) |
Includes 418,332 options exercisable within 60 days of December 31, 2016. |
| (2) |
Includes 161,666 options exercisable within 60 days of December 31, 2016. |
| (3) |
Includes 94,999 options exercisable within 60 days of December 31, 2016. |
| (4) |
Includes 8,333 options exercisable within 60 days of December 31, 2016. |
| (5) |
Includes 83,330 options exercisable within 60 days of December 31, 2016. |
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| (6) |
Includes 53,332 options exercisable within 60 days of December 31, 2016. |
| (7) |
Includes 8,333 options exercisable within 60 days of December 31, 2016. |
| (8) |
Includes 58,331 options exercisable within 60 days of December 31, 2016. |
| (9) |
Includes 91,665 options exercisable within 60 days of December 31, 2016. |
| (10) |
Includes 978,321 options exercisable within 60 days of December 31, 2016. |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Related Person Transactions
There have been no financial transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which the Company or any of its subsidiaries, was or is to be a participant, and the amount involved exceeds the lesser of $120,000 or 1% of the average of the Company’s total assets at year end for the last two completed fiscal years, and in which a director, an executive officer, any immediate family member of a director or executive officer, a beneficial owner of more than 5% of the Company’s outstanding common stock or any immediate family member of the beneficial owner, had or will have a direct or indirect material interest.
Director Independence
The Board is currently composed of eight directors: Dennis J. Gilles, Douglas J. Glaspey, Ali G. Hedayat, Randolph J. Hill, Paul A. Larkin, Leland L. Mink, James C. Pappas and John H. Walker. A majority of the Board, made up of Mr. Hedayat, Mr. Hill, Mr. Larkin, Dr. Mink, Mr. Pappas and Mr. Walker, satisfy the applicable independence requirements of the NYSE MKT. Mr. Gilles and Mr. Glaspey do not satisfy such independence requirements based on their employment as executive officers of the Company. The Board has three standing committees: the Audit Committee, the Nominating and Corporate Governance Committee and the Compensation and Benefits Committee. Each of the Board’s committees is composed only of directors that satisfy the applicable independence requirements of the NYSE MKT.
The Board has adopted certain standards to assist it in assessing the independence of each director. Absent other material relationships with the Company, a director of the Company who otherwise meets the applicable independence requirements of the NYSE MKT may be deemed “independent” by the Board after consideration of all relationships between the Company, or any of its subsidiaries, and the director, or any of his or her immediate family members (as defined in NYSE MKT listing standards), or any entity with which the director or any of his or her immediate family members is affiliated by reason of being a partner, officer or a significant shareholder thereof.
In assessing the independence of our directors, our full Board carefully considered all of the business relationships between the Company and our directors or their affiliated companies. This review was based primarily on responses of the directors to questions in a questionnaire regarding employment, business, familial, compensation and other relationships with the Company and our management.
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Item 14. Principal Accountant Fees and Services
Audit Fees
The aggregate fees billed to the Company by Moss Adams LLP for the year ended December 31, 2016 and 2015 for annual financial statements and reviews of financial statements included in the Company’s Quarterly Report on Forms 10-Q totaled $298,228 and $179,818; respectively.
Audit-Related Fees
The fees billed to the Company by Moss Adams LLP for the financial statement audits of the Company’s five subsidiaries (three in 2015) Idaho USG Holdings LLC and Oregon USG Holdings LLC, USG Oregon LLC, USG Nevada LLC and Raft River Energy I LLC for the years ended December 31, 2016 and 2015 were $76,000 and $51,000; respectively.
All Other Fees
The Company was billed by Moss Adams LLP for any other services during year ended December 31, 2016 that amounted to $9,885.
Administration of Engagement of Independent Auditor
The Audit Committee is responsible for appointing, setting compensation for and overseeing the work of our independent auditor. The Audit Committee has established a policy for pre-approving the services provided by our independent auditor in accordance with the auditor independence rules of the SEC. This policy requires the review and pre-approval by the Audit Committee of all audit and permissible non-audit services provided by our independent auditor and an annual review of the financial plan for audit fees.
All of the services provided by our independent auditor for the years ended December 31, 2016 and 2015, including services related to the Audit-Related Fees and Tax Fees described above, were approved by the Audit Committee under its pre-approval policies.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as a part of this report:
1. 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 |
Amended Certificate of Incorporation of U.S. Geothermal Inc. (incorporated by reference to exhibit 3.1 to the registrant’s Form S-3 filed on March 20, 2015) | |
| 3.2 | Third Amended and Restated Bylaws of U.S. Geothermal Inc. (Incorporated by reference to exhibit 99.2 to the registrant’s Form 8-K as filed on March 10, 2016) | |
| 3.3 |
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) | |
| 3.4 |
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) | |
| 3.5 | Certificate of Amendment to Certificate of Incorporation of U.S. Geothermal Inc. (incorporated by reference to exhibit 3.1 to the registrant’s Form 8-K filed on November 9, 2016) | |
| 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) | |
| 4.4 |
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) |
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| 4.12 |
Form of Warrant Certificate used in December 2012 registered offering (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K filed on December 21, 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) | |
| 10.12 |
Employment Agreement dated July 1, 2013 with Kerry D. Hawkley (Incorporated by reference to exhibit 10.2 to the registrant’s Form 8-K as filed on July 26, 2013) | |
| 10.13 |
Employment Agreement dated July 1, 2013with Douglas J. Glaspey (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on July 26, 2013) | |
| 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) |
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| 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 10.36 to the registrant’s Form 10- Q as filed on August 10, 2009). | |
| 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 10.33 to the registrant’s Form 10-Q as filed on August 10, 2009). | |
| 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) |
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| 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 |
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) * | |
| 10.35 |
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) | |
| 10.36 |
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)** | |
| 10.37 |
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) | |
| 10.38 |
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) | |
| 10.39 |
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) | |
| 10.40 |
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) | |
| 10.41 |
Financing Agreement dated November 9, 2011, between USG Nevada LLC and AresCapital Corporation (incorporated by reference to Exhibit 10.1 to the registrant’s Form 8-K filed on November 16, 2011) | |
| 10.42 |
Purchase Agreement dated January 22, 2016, 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 January 25, 2016) | |
| 10.43 |
Form of Subscription Agreement used in December 2012 registered offering (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on December 21, 2012) |
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| 10.44 |
Purchase and Sale Agreement dated as of December 14, 2015, among Idaho USG Holdings, LLC, Raft River I Holdings, LLC, Goldman, Sachs & Co., and U.S. Geothermal Inc. (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on December 18, 2015). | |
| 10.45 |
Second Amended and Restated Operating Agreement of Raft River Energy I LLC, dated as of December 14, 2015, among Idaho USG Holdings, LLC, and Raft River I Holdings, LLC (Incorporated by reference to exhibit 3.1 to the registrant’s Form 8-K as filed on December 18, 2015). | |
| 10.46 |
Employment Agreement dated April 19, 2013 with Dennis J. Gilles (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on April 23, 2013) | |
| 10.47 |
Amendment to the Employment Agreement dated January 9, 2017 with Dennis J. Gilles (Incorporated by reference to exhibit 10.1 to the registrant’s Form 8-K as filed on January 12, 2017) | |
| 10.48 |
Employment Agreement dated December 31, 2010 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.3 to the registrant’s Form 8-K as filed on July 26, 2013) | |
| 10.49 |
Amendment No. 5 to the Employment Agreement dated February 10, 2017 with Jonathan Zurkoff (Incorporated by reference to exhibit 10.5 to the registrant’s Form 8-K as filed on February 16, 2017) | |
| 10.50 | Note Purchase Agreement dated May 19, 2016 among Idaho USG Holdings, LLC, The Prudential Insurance Company of America and Prudential Annuities Life Assurance Corporation relating to $20,000,000, 5.80% Senior Secured Notes due March 31, 2023 (Incorporated by reference to exhibit 10.1 to the registrant’s Form 10-Q as filed on August 9, 2016) | |
| 13.1 |
Audited Consolidated Financial Statements of U.S. Geothermal Inc. as of December 31, 2015. | |
| 21.1 | ||
| 23.1 | ||
| 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.
Item 16 Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| U.S. Geothermal Inc. | |||
| (Registrant) | |||
| March 9, 2017 | |||
| By: | /s/ Dennis J. Gilles | ||
| Date | Dennis J. Gilles | ||
| Chief Executive Officer | |||
| (Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
| Name | Title | Date | |
| Chief Executive Officer and Director (Principal | |||
| /s/ Dennis J. Gilles | Executive Officer) | March 9, 2017 | |
| Dennis J. Gilles | |||
| Chief Financial Officer (Principal Financial and | |||
| /s/ Kerry Hawkley | Accounting Officer) | March 9, 2017 | |
| Kerry Hawkley | |||
| /s/ Douglas J. Glaspey | President, Chief Operating Officer and Director | March 9, 2017 | |
| Douglas J. Glaspey | |||
| /s/ John H. Walker | Chairman and Director | March 9, 2017 | |
| John H. Walker | |||
| /s/ Paul A. Larkin | Director | March 9, 2017 | |
| Paul A. Larkin | |||
| /s/ Leland L. Mink | Director | March 9, 2017 | |
| Leland R. Mink | |||
| /s/ Ali G. Hedayat | Director | March 9, 2017 | |
| Ali G. Hedayat | |||
| /s/ Randolph J. Hill | Director | March 9, 2017 | |
| Randolph J. Hill |
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| Name | Title | Date | |
| /s/ James C. Pappas | Director | March 9, 2017 | |
| James C. Pappas |
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