UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
SCHEDULE 14A
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U.S. GEOTHERMAL INC.
(Name
of Registrant as Specified In Its Charter)
________________________________________________________
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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, 2014
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) |
Registrants 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 registrants
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] |
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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 registrants most recent
second quarter (taking into account the change in fiscal year end), based upon
the closing sale price of the registrants common stock as reported by the NYSE
MKT LLC on March 21, 2014, was $85,252,768
The number of shares outstanding of the registrants
common stock as of March 6, 2015 was 107,063,029.
U.S. Geothermal Inc. and Subsidiaries
Form 10-K INDEX
For the Year Ended December 31, 2014
U.S. Geothermal Inc. and Subsidiaries
Form 10-K INDEX
For the Year Ended December 31, 2014
U.S. Geothermal Inc. and Subsidiaries
Form 10-K INDEX
For the Year Ended December 31, 2014
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. Examples of these forward-looking statements include, but are not
limited to:
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our business and growth strategies; |
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our future results of operations; |
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anticipated trends in our business; |
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the capacity and utilization of our geothermal
resources; |
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our ability to successfully and economically
explore for and develop geothermal resources; |
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our exploration and development prospects,
projects and programs, including construction of new projects and
expansion of existing projects; |
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availability and costs of drilling rigs and
field services; |
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our liquidity and ability to finance our
exploration and development activities; |
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our working capital requirements and
availability; |
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our illustrative plant economics; |
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market conditions in the geothermal energy
industry; and |
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the impact of environmental and other
governmental regulation. |
These forward-looking statements are based on the current
beliefs and expectations of our management and are subject to significant risks
and uncertainties. If underlying assumptions prove inaccurate or unknown risks
or uncertainties materialize, actual results may differ materially from current
expectations and projections. The following factors, among others, could cause
actual results to differ from those set forth in the forward-looking statements:
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the failure to obtain sufficient capital
resources to fund our operations; |
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unsuccessful construction and expansion
activities, including delays or cancellations; |
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incorrect estimates of required capital
expenditures; |
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increases in the cost of drilling and
completion, or other costs of production and operations; |
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the enforceability of the power purchase
agreements (PPAs) for our projects; |
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impact of environmental and other governmental
regulation, including delays in obtaining permits; |
-6-
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hazardous and risky operations relating to the
development of geothermal energy; |
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our ability to successfully identify and
integrate acquisitions; |
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our dependence on key personnel; |
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the potential for claims arising from
geothermal plant operations; |
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general competitive conditions within the
geothermal energy industry; and |
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financial market conditions.
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All subsequent written or oral forward-looking statements
attributable to us or any person acting on our behalf are expressly qualified in
their entirety by the cautionary statements contained or referred to in this
section. We do not undertake any obligation to release publicly any revisions to
these forward-looking statements to reflect events or circumstances after the
date of this document or to reflect the occurrence of unanticipated events,
except as may be required under applicable U.S. securities law. If we do update
one or more forward-looking statements, no inference should be drawn that we
will make additional updates with respect to those or other forward-looking
statements.
The U.S. dollar is the Companys functional currency; however
some transactions involved the Canadian dollar. All references to dollars or
$ are to United States dollars and all references to CDN$ are to Canadian
dollars.
U.S. Geothermal Inc. (the Company, 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 earths 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.
-7-
Development of Business
U.S. Geothermal Inc. 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, manages and operates power plants that utilize geothermal
resources to produce energy. The Companys 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 operate, identify, evaluate,
acquire, and develop 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. |
-8-
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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. We are currently engaged in
negotiation for the acquisition of additional pipeline opportunities that
are also 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 enhance the project economics and attract capital investment.
For the Raft River Unit I project, we partnered with Goldman Sachs as a
tax equity partner to fully utilize production tax credits available to
the project. Our strategy going forward is to structure project ownership
to be the primary beneficiary of project economics. Under current
legislation, a company may elect to take 30% ITC for certain qualified
investments provided construction of the project was started prior to the
end of 2014. 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. |
-9-
During the current year ended December 31, 2014, the Company
was focused on these specific items:
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operating and optimizing the Neal Hot Springs, San Emidio
and Raft River power plants; |
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completing the acquisition of the WGP Geysers project,
pursuing PPA and steam sale opportunities, and optimizing power plant
design; |
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completing the acquisition of leases for the Vale
project; |
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completing the acquisition of Earth Power Resources;
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drilling of nine temperature gradient wells to define the
target resource area for the El Ceibillo project, leasing surface lands,
and working with the Guatemalan Ministry of Energy and Mines to adopt a
new construction schedule; |
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drilling two new wells, and constructing a tie in
pipeline at San Emidio for Phase II; and |
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evaluating potential new geothermal projects and
acquisition opportunities. |
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 Companys operations
is as follows:
Projects in Operation |
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Generating |
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Contract |
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Project |
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Location |
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Ownership |
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Capacity (megawatts) |
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Power Purchaser |
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Expiration |
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Neal Hot
Springs |
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Oregon |
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JV(1) |
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22.0 |
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Idaho Power |
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2036 |
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San Emidio (Unit I) |
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Nevada |
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100% |
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10.0 |
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Sierra Pacific |
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2038 |
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Raft River
(Unit I) |
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Idaho |
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JV(2) |
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13.0(3) |
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Idaho Power |
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2032 |
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(1) |
In September 2010, the Companys wholly owned subsidiary
(Oregon USG Holdings LLC) entered into agreements that formulated a
strategic partnership with Enbridge (U.S.) Inc. (Enbridge). Enbridge
contributed approximately $32.8 million to the Neal Hot Springs geothermal
project. The Companys equity interest in the project is 60% and
Enbridges equity interest is 40%. |
(2) |
As part of the financing package for Unit I of the Raft
River project, we contributed $16.5 million in cash and approximately $1.4
million in property to Raft River Energy I LLC, the Unit I project joint
venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman
Sachs Group, contributed $34 million to finance the construction of the
project. |
(3) |
Based on the designed annual average net output. The
actual output of the Raft River Unit I plant currently is approximately
9.4 megawatts annual average. |
-10-
Neal Hot Springs, Oregon
Neal Hot Springs is located
in Eastern Oregon near the town of Vale, the county seat of Malheur County, and
achieved commercial operation on November 16, 2012. The Neal Hot Springs
facility is designed as a 22 megawatt net annual average power plant, consisting
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 flow
and temperature of geothermal brine.
Generation from the facility during the fourth quarter of 2014
totaled 54,472 megawatt-hours with an average of 25.08 net megawatts per hour of
operation. Plant availability was 98.3% during the quarter. Total generation at
Neal Hot Springs for 2014 was 183,394 megawatt-hours. This compares to 155,428
megawatt-hours of generation for 2013, reflecting an 18% increase over the prior
year.
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
annually 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 average price paid under the PPA for 2014 was $102.78 per megawatt-hour and
will increase to $106.79 per megawatt-hour in 2015.
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. Generation from the facility during the fourth quarter 2014
totaled 21,745 megawatt-hours, with an average of 9.93 net megawatts per hour of
operation. Plant availability was 99.2% during the quarter. Total generation for
2014 was 76,894 megawatt-hours. This compares to 76,697 megawatt-hours of
generation for 2013 reflecting continued, steady state operation of the
facility.
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 an annual escalation rate of
1 percent. The average price paid under the PPA for 2014 was $91.17 per
megawatt-hour and will increase to $92.08 per megawatt-hour in 2015.
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.
Generation from the facility during the fourth quarter 2014
totaled 20,614 megawatt-hours, with an average of 9.59 net megawatts per hour of
operation. Plant availability was 97.3% during the quarter. Total generation for
2014 was 78,798 megawatt-hours. This compares to 77,560 megawatt-hours for the
same period of 2013, reflecting continued steady state operation of the
facility.
-11-
The PPA for the project was signed on September 24, 2007 with
the Idaho Power Company. The PPA has a 25 year term with a starting average
price for the year 2007 of $52.50 that escalates at 2.1% per year 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 average price paid under
the PPA for 2014 was $60.72 per megawatt-hour and will increase to $62.00 per
megawatt-hour in 2015.
In addition to the price paid for energy by Idaho Power, Raft
River Unit I currently receives $4.75 per megawatt-hour under a separate
contract for the sale of Renewable Energy Credits (RECs) to Holy Cross Energy,
a Colorado electric cooperative. Starting in calendar year 2018, 51% of the RECs
are owned by Idaho Power and 49% by the project. For the RECs owned by Raft
River, a new, 10 year REC contract with the Public Utility District No. 1 of
Clallam County, Washington will replace the current contract.
Material Acquisitions/Development
In addition to our projects in operation, we have projects
under development and under exploration. Projects under development have at
least a geothermal resource discovery or may have wells in place, but require
the drilling of new or additional production and injection wells in order to
supply enough geothermal fluid sufficient to operate a commercial power plant.
Projects under exploration do not have a geothermal resource discovery
occurrence yet, but have significant thermal and other physical evidence that
warrants the expenditure of capital in search of the discovery of a geothermal
resource. Due to inflation and marketplace increases in the costs of labor and
construction materials, estimates of property development costs may be low.
A summary of projects under development and under exploration
is as follows:
Projects Under
Development |
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Estimated |
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Target |
Projected |
Capital |
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Development |
Commercial |
Required |
Power |
Project |
Location |
Ownership |
(Megawatts) |
Operation Date |
($million) |
Purchaser |
El Ceibillo Phase I |
Guatemala |
100% |
25 |
2nd
Quarter 2018 |
138 |
TBD |
San Emidio Phase II |
Nevada |
100% |
11 |
3rd Quarter 2017 |
65 |
TBD |
WGP Geysers |
California |
100% |
30 |
2nd
Quarter 2017 |
160 |
TBD |
Crescent Valley Phase I |
Nevada |
100% |
25 |
1st Quarter 2018 |
141 |
TBD |
-12-
Properties Under Exploration |
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Target Development |
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Project
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Location |
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Ownership |
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*(Megawatts) |
|
Gerlach |
|
Nevada |
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60% |
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10 |
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Vale |
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Oregon |
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100% |
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15 |
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El Ceibillo Phase II |
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Guatemala |
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100% |
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25 |
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Neal Hot Springs II |
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Oregon |
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100% |
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10 |
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Raft River Unit II |
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Idaho |
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100% |
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13 |
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Crescent Valley Phase II |
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Nevada |
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100% |
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25 |
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Crescent Valley Phase III |
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Nevada |
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100% |
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25 |
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Lee Hot Springs |
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Nevada |
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100% |
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20 |
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Ruby Hot Springs Phase I |
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Nevada |
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100% |
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20 |
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Granite Creek During the current year ended December 31,
2014, the Company elected to not continue exploration and development activities
due to more attractive projects in its portfolio. The Company is in the process
of releasing its interests in the area.
Neal Hot Springs Phase III, Raft River Phase III, and San
Emidio Phase III These projects were removed from the list of properties under
exploration during the current year. Unfavorable market conditions and
development time frames did not warrant the allocation of exploration or
development resources.
* Target development sizes are predevelopment estimates of
resource potential of unproven resources.
A summary of the property size, temperature, well-depth and
power plant technology used or anticipated to be used at our properties is as
follows:
Property Details |
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Property Size |
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(square |
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Property |
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miles) |
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Temperature (ºF)
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Depth (Ft) |
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Technology |
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Neal Hot Springs |
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9.6 |
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286-311 |
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2,500-3,000 |
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Binary |
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San Emidio |
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27.9 |
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289-316 |
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1,500-3,000 |
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Binary |
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Raft River |
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10.8 |
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275-302 |
|
4,500-6,000 |
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Binary |
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Gerlach |
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4.7 |
|
338-352 |
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2,000-3,000 |
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Binary |
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El Ceibillo |
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38.6 |
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410-526 |
|
1,800-TBD |
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Steam |
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WGP Geysers |
|
6.0 |
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380-598 |
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6,000-10,000 |
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Steam |
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Crescent Valley |
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33.3 |
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326-351 |
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2,000-3,000 |
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Binary |
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Lee Hot Springs |
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4.0 |
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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.
-13-
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.
-14-
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.
San Emidio, 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 project loans, with the remainder funded through equity financing. We
anticipate the project qualifying for the 30% Federal investment tax credit. As
a result of the delays experienced in permitting wells on BLM administered
leases, it was determined that it is not possible to complete the development of
the Phase II project within the development time frame required in the existing
19.9 megawatt NV Energy PPA.
A Small Generator Interconnection Agreement for 16 megawatts of
transmission capacity was executed with Sierra Pacific Power Company on December
28, 2010. An application to increase the interconnection agreement to the full
19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9,
2014. A System Impact Study (SIS) agreement, which is the next step in the
interconnection process mandated by the Federal Energy Regulatory Commission,
was signed on August 28, 2014. Results from the SIS were received on December
24, 2014. A second phase interconnection study, called the Facilities Study, was
started in January of 2015.
-15-
On October 30, 2009, the Company was awarded $3.77 million in
Recovery Act funding from the Department of Energy (DOE) for the exploration
and development of its San Emidio geothermal power project using advanced
geophysical exploration techniques. This award was categorized under the
Innovative Exploration and Drilling Projects section of the American Recovery
and Reinvestment Act. The first stage of the DOE project applied innovative,
seismic and satellite imagery techniques along with state-of-the-art structural
modeling, to locate large aperture fractures that represent high-productivity
geothermal drilling targets and was completed in 2011. Two zones along the 4.5
mile long San Emidio fault structure were identified as high quality targets for
drilling during the first phase of the DOE program, a South Zone and a North
Zone.
The second stage of the DOE program was a 50-50 cost shared
drilling plan that was intended to follow up on targets identified in the first
stage. Drilling started in the South Zone, and two wells were completed by the
Company. After approval of the drilling program by the DOE in November 2011, one
of the first two wells was deepened and three additional wells were completed in
the South Zone with the costs being shared on a 50-50 basis.
As part of the continuing DOE program, permitting was initiated
early in the year with the Bureau of Land Management (BLM) for four new
observation wells to be drilled in the South Zone to follow up on the high
temperatures found in wells 61-21 (302°F) and 45-21 (316°F). As part of the
permitting process, cultural and biological surveys were performed, and the well
design and drilling program were submitted during the first quarter. Permits for
three wells were issued by the BLM on April 29th and a drill rig was
mobilized to the site on June 26th. Two additional wells were
completed on the BLM administered land during the third quarter. Well OW-14 was
drilled to a depth of 3,501 feet and had a bottomhole temperature of 265°F. Well
OW-15 was drilled to a depth of 3,716 feet and had a maximum downhole
temperature of 300°F. While the wells extended the high temperature outline of
the South Zone, neither well encountered the commercial permeability seen in
well 61-21 (OW-10). Geologic, geochemical and temperature data generated by the
drilling program is being evaluated to determine the next phase of drilling.
A second round of permitting for an expanded temperature
gradient drilling program is underway for an area south west of the current
resource. Results from the recent OW drilling program combined with 1970s era,
shallow temperature gradient data, indicate a high temperature trend into this
south-west zone. Geophysical surveys have also identified structural trends in
this area. Several 1,000 foot deep temperature gradient wells are being
permitted to follow up on this portion of the resource.
Well 61-21 (formerly OW-10) in the South Zone, was reworked
beginning on October 25, 2013 and was completed on November 2, 2013. Flow
testing of 61-21 was completed during the second quarter of 2014. To allow for
early, long term testing of the South Zone resource area, a cross tie pipeline
was constructed between the Phase I and Phase II project areas and a production
pump was installed in well 61-21 during the third quarter. Well 61-21 is
currently producing 620 gallons per minute of 296°F fluid to the San Emidio
Phase I power plant. San Emidio Phase I plant generation has increased
approximately a half of megawatt. Hooking up and flow testing well 61-21 was the
last work under the DOE Innovative Exploration and Drilling Project grant. The
grant program was completed at the end of September 2014, with the DOE
Geothermal Technologies Program having expended $3,772,560 and the Company
$4,156,741.
-16-
A Request for Proposal (RFP) from NV Energy for 100 megawatts
of renewable energy was issued on October 1, 2014. On November 12, we submitted
a bid for an air cooled power plant to be developed on the Phase II project
site. In early December, NV Energy submitted a request to the Nevada Public
Utilities Commission (NPUC) to combine the 2014 solicitation with the 2015
solicitation for a total of 200 megawatts to be procured in 2014. The request
also allows re-submittal of any projects that had been previously submitted for
the original 2014 RFP. NV Energys request was approved by the NPUC, and
Subsequent to the end of the year on February 16, 2015, we submitted an
alternative option into the new NV Energy solicitation that uses a water cooled
plant as the basis for the bid. We were notified on March 3rd that
our bid was advanced to the initial short list for geothermal projects.
In parallel, we are continuing to investigate a power purchase
agreement with California off-takers, where power prices are typically
higher.
Raft River, Idaho
The Raft River project was awarded an $11.4 million
cost-shared, thermal fracturing program grant from the Department of Energy. 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, and
after installing four, 300 foot deep seismic monitoring wells with seismic
geophones to allow for seismic monitoring, 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.
Injection continued through the quarter from power plant injectate, with flow
into the well seeing a moderate increase to now over 450 gpm, indicating that
significant additional permeability has developed. The EGS stimulation is
expected to continue through 2015.
If the fracturing program is successful, and permeability is
improved to a commercial level, well RRG-9 may be utilized as a production or
injection well for the existing Raft River power plant. The Companys
contributions for the thermal fracturing program are made in-kind by the use of
the RRG-9 well, well field data, and monitoring support.
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.
-17-
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.
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.
El Ceibillo, Republic of Guatemala
A geothermal
energy rights concession, located 14 kilometers southwest of Guatemala City, was
awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the
Company in April 2010. The concession has a 5 year term for the development and
construction of a power plant. There are 24,710 acres (100 square kilometers) in
the concession which is at the center of the Aqua and Pacaya twin volcano
complex.
An office and staff are located in Guatemala City and a 17 acre
plant site is under lease on land adjacent to the existing wells. A second
surface lease for use of an additional 80 acre parcel was signed on October 15,
bringing the total surface leasehold interest to 97 acres. Construction of a
drill pad, pond and cellar for EC-2, our new well, was completed during the
fourth quarter. EC-2 is located on the new surface leasehold. Drilling of EC-2
is expected to begin as soon as the approval to extend the development schedule
contained in the concession agreement has been obtained from the Guatemalan
Ministry of Energy and Mines.
Our attempts to obtain approval of our modified development
schedule from the Guatemala Ministry of Energy (MEM) continue. Our request has
been approved by the MEM legal department and, subsequent to the end of the
year, the new schedule was approved by the technical department, and has been
approved by the Vice-Minister. Final approval for the new schedule now awaits
signature by the Minister of Energy.
El Ceibillo, the first development target on the concession, is
located near the town of Amatitlan, in a developed industrial zone immediately
adjacent to the highway that connects Guatemala City to the Port of San Jose on
the Pacific coast. An initial development of a 25 megawatt (Phase I) power plant
is planned in the El Ceibillo area of the concession, but the final size of the
facility will be determined after drilling and resource delineation has
advanced. Initial transmission studies have been completed, and identified the
grid interconnection point approximately 1.2 miles (2 kilometers) from the site.
A temperature gradient (TG) drilling program was initiated
during the first quarter of 2014 with a series of 656 foot (200 meter) deep
wells planned. Nine TG wells have been completed with depths ranging from 656 to
1,312 feet (200 to 400 meters). Bottom-hole temperatures found in this shallow
drilling program range from 176 to 413°F (80 to 211°C) with two of the wells
encountering permeability and flowing brine. The data from these wells provided
a more accurate temperature gradient map of the underlying geothermal resource
which has assisted in identifying future drilling targets.
-18-
A first phase of drilling took place during the third quarter
of 2013 when well EC-1 was drilled to a depth of 4,829 feet (1,472 meters) and
encountered a bottom hole temperature of 491°F (255°C), with the temperature
gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet
(129.1°C/km) . High temperatures in excess of 392°F (>200°C) were encountered
in the well beginning at a depth of 2,625 feet (800 meters), which represents a
potential high temperature reservoir interval in excess of 2,204 feet (672
meters) thick. Due to the high temperature gradient found in the lower section
of the well, the decision was made to deepen the well. The final depth of the
well is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of
526°F (274°C). Clean out and short term flow tests were conducted along with
temperature surveys and have been incorporated in the geologic model of the
reservoir. Well EC-1 did not encounter commercial permeability.
In early September 2013, the Guatemalan Ministry of the
Environment and Natural Resources (MARN) issued the Environmental License for
the construction and operation of the planned, first phase, 25 megawatt power
plant at the El Ceibillo site. The license is based on the Environmental Impact
Assessment Study that was submitted in December 2012, describing the initial
design of the 25 megawatt facility, and requires the submittal of final design
specifications for review by MARN prior to starting physical construction of the
plant. Additionally, the license requires compliance with all legal and
regulatory requirements under Guatemalan law, submittal of an air quality
monitoring plan, and that final design comply with the strict guidelines for
noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an
environmental bond was posted with the Ministry of Environment and Natural
Resources.
A binding Memorandum of Understanding (MOU) was signed on
October 18, 2012 with one of the largest power brokers in Central America. The
MOU established the framework for a PPA that included a 15-year term for an
initial, estimated 25 megawatts of power generation up to a maximum of 50
megawatts of power generation to be developed in two phases. As a result of the
delays in approval of the modified development schedule from MEM, we requested
an extension of our MOU, which was allowed under the terms of the agreement, but
our request was declined and the MOU is now terminated. We are continuing
discussions with the broker to reinstate or renegotiate the agreement, and are
approaching other power consumers in Guatemala and Central America.
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.
-19-
WGP Geysers is an advanced stage project that encompasses the
former Pacific Gas and Electric Unit 15, which once had a 62 megawatt (gross)
capacity geothermal power plant that was shut down in l989. The project includes
3,809 acres (6 square miles) of geothermal leases and property, development
design plans, and permits for an up to 38.5(gross) megawatt power plant. There
are four existing wells drilled in 2008-2009 which are immediately available for
production or injection, with a fifth, historic well that has temporary plugs
installed but can be reworked. The four new wells have been tested with an
initial steam flow totaling 462,000 pounds per hour. A report prepared in 2012
by a third party reservoir engineering firm, states that the total initial power
capacity from these wells is estimated at about 30 megawatts (gross).
A 12 month extension for the Sonoma County Conditional Use
Permit to construct the up to 38.5 megawatt power plant was applied for and was
approved on June 12, 2014. Additionally, an application was made to the Sonoma
County Air Quality Board for a permit to conduct flow tests on the four
production wells drilled in 2009. The Air Quality permit was approved on June
19, 2014. A new conditional use permit application is currently being prepared
for submittal to local regulatory agencies to replace the recently extended
conditional use permit that expires in July.
A new transmission interconnection agreement has been applied
for to the California Independent System Operator. Engineering optimization of
the power plant design continues. The current well field reservoir model is
being updated to reflect a new hybrid plant design that includes both water and
air cooling, which will dramatically increase the volume of water available for
injection back into the reservoir. Traditional water cooled steam plants
re-inject approximately 20% of the water that is removed during power
generation, while a hybrid design may re-inject up to 65% 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. A flow
testing program for the production wells is being designed and will be scheduled
during the first half of 2015.
Crescent Valley, 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 November 2014.
Multiple geothermal and mineral exploration drilling programs
have identified high temperatures and high temperature gradients in the shallow
subsurface over an area greater than 30 square miles. Historic drill holes
defining this area have anomalous temperature gradients of up to 40°F/100 feet
of depth, and a recorded high temperature of 285°F at 395 feet below the
surface. These drill holes define large areas of hydrothermal alteration that
correspond to positive anomalies defined by gravity surveys that extend into
undrilled areas of the valley.
A mineral exploration hole drilled in the mid-l990s near the
Crescent Valley fault encountered geothermal fluid under pressure and the
driller lost control the well. An oil field service company had to be contracted
to regain control prior to the abandonment of the well. This well demonstrates
that prospective permeability and commercial temperature are known from past
minerals exploration.
-20-
Hot springs located on the property have discharge temperatures
of up to 198°F and broad areas of hydrothermal alteration occur at both Hot
Springs Point and along the Crescent Valley fault 8 miles to the southeast.
Chemistry of the hot springs and the occurrence of silica sinter deposits at
surface, and intersected by drilling in the shallow subsurface, suggest
reservoir temperatures at depth of greater than 350°F. Chemistry of fluids from
the Crescent Valley hot spring is permissive for even higher temperatures of
greater than 400°F.
Anomalous temperature gradients extend up to 7 miles northwest
from the Crescent Valley fault into Crescent Valley proper. Additional fracture
controlled permeability may be present under the valley floor as horst-bounding
fault systems interpreted from historic seismic studies are indicated to exist.
An independent geothermal consulting firm evaluated all of the
available data for the Crescent Valley Prospect in late 2009. After evaluating
the data, a recoverable, heat-in-place Monte Carlo method was used to estimate
the generation potential of the prospect. The resulting estimate for the field
was 71 megawatt with 90% probability and 186 megawatt with 50% probability over
a 20 year period. The actual, producible power generation may be significantly
different than the recoverable heat-in-place calculations, and will depend upon
the discovery of commercial temperatures and permeability.
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 well CVP-001 (67-3) was
initiated in December of 2014, following completion of gravity surveys, and
analysis of prior temperature gradient drilling data. The first string of
production casing was set and cemented before year end. Subsequent to the end of
the year, the well was drilled to 730 feet and the production casing was
cemented in place.
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.
-21-
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. The 3,000 foot test well mentioned above reportedly
flowed at over 300°F. A drilling log shows hot temperatures escalating to depth.
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.
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.
-22-
Employees
At December 31, 2014, 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.
Principal Products
The principal product is based upon activities related to the
production of electrical power from the utilization of the Companys 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
Earths 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.
-23-
Unless major geological changes occur that impact the
geothermal reservoirs, the condition of the existing resources is expected to
remain relatively consistent over time.
Significant Government Permits
The Company has obtained permits for its three operational
plants and at the WGP Geysers project.
Neal Hot Springs, Oregon. The Neal Hot Springs project
has four primary permits that govern the continued operations at the Neal Hot
Springs geothermal plant. The permits include:
|
1. |
Geothermal Well Permits; Department of Geology; Multiple
API #s |
|
2. |
Right-of-Way; Bureau of Land Management,
OR-65701 |
|
3. |
Malheur County Conditional Use Permit; Malheur County,
10-21-2009 |
|
4. |
Underground Injection Control Permit; Oregon Department
of Environmental Quality, 13281-8 |
San Emidio, Nevada. The San Emidio project has five
significant permits in place necessary for continued operations:
|
1. |
Geothermal well permits for production and injection
wells issued by the Nevada Division of Minerals. |
|
2. |
A Special Use Permit issued by the Washoe County Board of
Commissioners on July 1, 1987. |
|
3. |
An Air Quality Permit to Operate from Washoe County
renewed on January 1, 2008. |
|
4. |
A Surface Discharge Permit from Nevada Division of
Environmental Protection issued on June 11, 2001. |
|
5. |
An Underground Injection Permit from Nevada Division of
Environmental Protection issued on August 18,
2000. |
Raft River, Idaho. The Raft River project has four
significant permits in place necessary for continued operations:
|
1. |
Geothermal well permits for production and injection
wells issued by the Idaho Department of Water Resources. |
|
2. |
A Conditional Use Permit for the first two power plants
was issued by the Cassia County Planning and Zoning Commission on April
21, 2005. |
|
3. |
The Idaho Department of Environmental Quality issued the
Air Quality Permit to Construct on May 26, 2006. |
|
4. |
A Wastewater Reuse Permit issued by the Idaho Department
of Environmental Quality on February 23, 2007 is being renewed with the
agency. |
-24-
WGP Geysers, California. The Geysers Unit 15 property
has local and state permits that authorize construction and operation of up to a
38.5 megawatt geothermal power plant. The significant permits include:
|
1. |
Four geothermal well permits for production and injection
wells issued by the California Department of Oil, Gas, and Geothermal
Resources. |
|
2. |
A Conditional Use Permit issued by the Sonoma County
along with preliminary design approval for a septic system. |
|
3. |
Northern Sonoma Air Quality Board has issued permits for
well and geothermal power plant operations. |
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. Generally, the Companys 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. Conversely, 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 in our areas of operation are
limited. The Companys 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. Even at planned levels
of operation, it is expected that the Company and its interests will have a
small number of direct customers that may amount to less than 5 or 6 over the
next 5 to 10 years.
-25-
PPAs, energy credits that are earned by USG Oregon LLC and USG
Nevada LLC plants are bundled with energy sales. Even at planned levels of
operation, it is expected that the Company and its interests will have a small
number of direct customers that may amount to less than 5 or 6 over the next 5
to 10 years.
Competitive Conditions
Although the market for different forms of energy is large and
dominated by very powerful players, we perceive our industrial competition to be
independent power producers and in particular those producers who provide
green renewable power. Our definition of green power is electricity derived
from a source that does not pollute the air, water or earth. Sources of green
power, in addition to geothermal, include wind, solar, biomass and run-of-the
river hydroelectric. A number of states have instituted renewable portfolio
standards (RPS) that require utilities to purchase a minimum percentage of
their power from renewable sources. For example, RPS statutes in California
require 33% renewable and Nevada require 25% renewable. According to the
Department of Energys 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. |
-26-
Environmental Compliance
Geothermal drilling, resource development and site construction
is subject to federal, state and local environmental and construction
oversight including state and local agencies in Idaho, Oregon, Nevada and
California. Applicable laws may include 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, the Resource Conservation and
Recovery Act, and geothermal drilling rules and local building codes.
Prior to acquiring a new property or project, USG has retained
licensed environmental professionals to conduct Phase I Site Assessments and
evaluate each property. The purpose of the site assessment is to identify, in
accordance with federal standards, any existing environmental contaminant
release or on-site contamination and prevent an unrecognized financial liability
from being passed to U.S. Geothermal Inc. or our subsidiaries.
Our geothermal operations involve significant quantities of
brine that is returned to the local subsurface, geologic formation. We also use
isopentane and R-134A working fluids, and numerous industrial lubricants that
are generally flammable and 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 for the financing of each project.
Independent legal review 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 from Vale, Oregon in an area with
only one nearby resident. There are no unique plant 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.
-27-
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.
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 the volume, quality, and disposition of
geothermal water and cooling water is reported.
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 from Malta, Idaho and is in a rural agricultural area
with the nearest residence approximately two miles from the plant site. There
are no unique plant or animal communities in the area and no unique cultural or
environmental constraints.
Key environmental reports include:
|
1) |
Monthly production and injection reports filed with the
Idaho Department of Water Resources; |
|
2) |
Annual land application and cooling water quality reports
filed with the Idaho Department of Environmental Quality and Idaho
Department of Water Resources. |
|
3) |
Annual Tier II reporting filed with the Idaho Bureau of
Homeland Security, Local Emergency Planning Committee, and the local fire
department. |
The projects most significant environmental compliance
requirement is for water quality monitoring and reporting. The Company has added
seven years of water monitoring data to a substantial volume of historical data
developed by the US Department of Energy. The IDWR and Idaho Department of
Environmental Quality concur with the Projects findings that geothermal
operations have no impact on water quality. The Projects private lands must be
managed on an ongoing basis for weed control, water management, irrigation, and
fencing infrastructure. USG has leased the grazing rights and cropland rights to
a local rancher who is responsible for the day to day farming and maintenance
obligations.
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.
-28-
WGP Geysers, California
The Unit 15 property is
located approximately 30 minutes north of the city of Healdsburg, CA. The
property encompasses a ridgetop and a north facing hillside that has been
developed and was used for geothermal operations for over 10 years 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 WGP to remove approximately 25 yards of soil
that has been identified as having arsenic levels that exceed 150 parts per
million. The NCRWQB has accepted WGPs proposal for the soil removal and we are
in compliance the NCRWQBs requirements. The work is scheduled for completion
not later than June 2015.
WGPs 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 Unit 15 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.
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, |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
USG Oregon LLC located in
Eastern Oregon |
$ |
18,759,248
|
|
$ |
15,566,409
|
|
USG Nevada LLC located in Northwestern Nevada
|
|
7,031,445 |
|
|
6,792,382 |
|
Raft River Energy I LLC
located in Southeastern Idaho |
|
5,178,089 |
|
|
5,012,143 |
|
|
|
|
|
|
|
|
Total energy and energy credits sales |
$ |
30,968,782 |
|
$ |
27,370,934 |
|
-29-
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 SECs Public Reference Room at 100 F Street, N.E., Room 1580;Washington D.C.
20549. You may obtain information on the operation of the SECs 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.
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, 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 utilitys 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).
-30-
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 FERCs 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
Companys 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.
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 FERCs 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.
-31-
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.
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.
-32-
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 Companys
projects, these credits have been sold separately, or bundled with the
electricity to provide an additional source of revenue.
We expect the following key incentives to influence our results
of 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. At
present, unless extended, facilities that begin construction after December 31,
2014 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 2014, 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.
-33-
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.
-34-
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, geothermal 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, geothermal 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 lines 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.
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:
-35-
|
|
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 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 quarterly operating results have fluctuated in the
past and could be negatively impacted in the future as a result of a number of
factors, including:
|
|
seasonal variations in ambient weather
conditions; |
|
|
variations in levels of production; and
|
-36-
|
|
the completion of exploration and production
projects. |
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;
|
|
|
pollution; 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.
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
will 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.
-37-
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 cause seismic activity and related property
damage. There are approximately two-dozen steam geothermal plants
operating within a fifty-square-mile region in the area of Anderson Springs, in
Northern California, and there is general agreement that the operation of these
plants causes a generally low level of seismic activity. Some residents in the
Anderson Springs area have asserted property damage claims against those plant
operators. There are significant issues whether the plant operators are liable,
and to date no court has found in favor of such claimants. While we do not
believe the areas 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 in accordance with
the rules of the SEC 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.
Under current rules of the SEC, 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 and our
independent registered public accounting firm can render an opinion on
managements assessment. 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.
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. In addition,
we cannot assure you that our independent registered public accounting firm will
agree with our assessment that any identified material weaknesses have been
remediated. 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 individuals
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.
-38-
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. Its 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 counterpartys 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.
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:
-39-
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water extraction from surface streams and
lakes; |
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well drilling or workover, operation and
abandonment; |
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waste management; |
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injection well classifications; |
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land reclamation; |
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financial assurance, such as posting bonds; and
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controlling air, water and waste emissions.
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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. We are dependent upon the services of our Chief Executive
Officer, Dennis J. Gilles, our President and Chief Operating Officer, Douglas J.
Glaspey, our Chief Financial Officer, Kerry D. Hawkley, and our Treasurer and
Executive Vice President, Jonathan Zurkoff. The loss of any of their services
could have a material adverse effect upon us. As of the date of this report, the
Company has executed employment agreements with these persons, but does not have
key-man insurance on any of them.
Our 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 negative
effect on our business.
-40-
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:
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identify suitable locations and appropriate
technology; |
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secure rights to exploit the resources; |
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obtain sufficient capital and revenue sources;
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obtain appropriate governmental permits; |
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maintain cost controls during construction; and
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identify, hire and retain a qualified work
force. |
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.
-41-
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.
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 Companys financing agreements provide for a priority
payback to our partner. If the actual costs of construction or operations exceed
the model costs, we may not be able to operate profitably or receive the planned
share of cash flow and proceeds from the project. As an example, the actual
costs of operating the Raft River power project were higher than the original
estimate due to several factors including the need to filter the ground water
used for cooling to remove harmful and unanticipated chloride levels in the
water, the need to purchase production pump power from a third party to provide
maximum plant output, and increased general costs related to labor, maintenance
and management.
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:
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failure of the acquired companies to achieve
the results we expect; |
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inability to retain key personnel of the
acquired companies; |
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risks associated with unanticipated events or
liabilities; and |
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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.
-42-
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:
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unexpected drilling conditions; irregularities
in formations; equipment failures or accidents; |
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compliance with governmental regulations;
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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.
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.
-43-
Furthermore, acquisitions involve a number of risks and
challenges, including:
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diversion of managements attention; |
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the need to integrate acquired operations;
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potential loss of key employees of the acquired
companies; |
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greater geographic dispersion of employees;
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the potential that we may make bad
acquisitions; |
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potential lack of operating experience in a
geographic market of the acquired business; and |
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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.
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:
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availability of equipment, particularly
drilling rigs and well casing; |
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lack of acceptable prospective acreage; |
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inadequate capital resources; |
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weather; |
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compliance with governmental regulations; and
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mechanical difficulties; |
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opposition to development. |
Natural gas prices are volatile, and a decline in gas
prices would affect significantly 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 todays market are substantially associated with the prices and demand for
natural gas. The markets for these commodities are volatile, and modest drops in
prices can affect significantly our financial results and impede our growth.
Prices for natural gas 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:
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domestic and foreign supply of oil and gas;
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price and quantity of foreign imports; |
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actions of the Organization of Petroleum
Exporting Countries and state-controlled oil companies relating to oil
price and production controls; |
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domestic and foreign governmental regulations;
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political conditions in or affecting other oil
producing and gas producing countries, including the current conflicts in
the Middle East and conditions in South America and Russia;
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weather conditions, as evidenced by recent
hurricanes; |
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technological advances affecting oil and gas
consumption; |
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overall U.S. and global economic conditions;
and |
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price and availability of alternative fuels.
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Further, oil prices 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:
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Changes in government policies or personnel;
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Changes in general economic conditions; |
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Restrictions on currency transfer or
convertibility; |
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Changes in labor relations; |
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Political instability and civil unrest; |
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Changes in the local electricity market; |
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Breach or repudiation of important contractual
undertakings by governmental entities; and |
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Expropriation and confiscation of assets and
facilities. |
In particular, the Guatemalan electricity sector was partially
privatized and it is currently unclear whether further privatization will occur
in the future. Such developments may affect our projects and the El Ceibillo
project currently under development if, for example, they result in changes to
the prevailing tariff regime or in the identity and creditworthiness of our
power purchasers.
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.
-45-
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 prices than our geothermal
plants. In addition, there are other technologies that can produce electricity,
most notably fossil fuel power systems, hydroelectric systems, wind-turbines and
photovoltaic (solar) cells. Some 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 is gradually
declining. 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 projects may be significantly impaired.
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 and/or 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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Risks Related to Our Liquidity and Capital
Resources
Substantial leverage and debt service obligations may
adversely affect our cash flows, liquidity and operations. We will 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:
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limiting our ability to borrow additional
amounts for working capital, capital expenditures, debt service
requirements, entering into other renewable energy businesses, or other
purposes; |
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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; |
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increasing our vulnerability to general adverse
economic and industry conditions; |
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limiting our ability to or increasing the costs
of refinance indebtedness; and |
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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.
We may be unable to obtain the financing we need to
pursue our growth strategy in the geothermal power production segment, which may
adversely affect our ability to expand our operations. When we identify
a geothermal property that we may seek to acquire or to develop, a substantial
capital investment will be required. Our continued access to capital, through
project financing or through a partnership or other arrangements with acceptable
terms is necessary for the success of our growth strategy. Our attempts to
secure the necessary capital may not be successful on favorable terms, or at
all.
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Market conditions and other factors may not permit future
project and acquisition financings on terms favorable to us. Our ability to
arrange for financing on favorable terms, and the costs of such financing, are
dependent on numerous factors, including general economic and capital market
conditions, investor confidence, the continued success of current projects, the
credit quality of the projects being financed, the political situation in the
state in which the project is located and the continued existence of tax laws
which are conducive to raising capital. If we are unable to secure capital
through partnership or other arrangements, we may have to finance the projects
using equity financing which will have a dilutive effect on our common stock.
Also, in the absence of favorable financing or other capital options, we may
decide not to build new plants or acquire facilities from third parties. Any of
these alternatives could have a material adverse effect on our growth prospects
and financial condition.
It is very costly to place geothermal resources into
commercial production. Before the sale of any power can occur, it
will be necessary to construct a gathering and disposal system, a power plant,
and a transmission line, and considerable administrative costs would be
incurred, together with the drilling of 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.
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:
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make prepayments on or purchase indebtedness in
whole or in part; |
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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; |
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make certain investments, including capital
expenditures; |
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enter into transactions with affiliates; |
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create or incur liens to secure debt;
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-49-
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consolidate or merge with another entity, or
allow one of our subsidiaries to do so; |
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lease, transfer or sell assets and use proceeds
of permitted asset leases, transfers or sales; |
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incur dividend or other payment restrictions
affecting certain subsidiaries; |
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engage in certain business activities; and
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acquire facilities or other businesses
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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.
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.
-50-
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.
On a Federal level, the most important tax rule that affects
our business is the PTC, which was extended to December 31, 2014. Recent
legislation enacted as part of the Fiscal Cliff efforts resulted in the
extension of the 30% ITC with eligibility for projects that started construction
in 2014. 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 future expansions at our current project sites, or
development at new sites, uneconomic. New rules recently 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.
In the states of Idaho, Nevada and Oregon, drilling for
geothermal resources is governed by specific rules. In Nevada drilling
operations are governed by the Division of Minerals (Nevada Administrative Code
Chapter 534A); in Idaho by the Idaho Department of Water Resources (IDAPA 37
Title 03 Chapter 04); and in Oregon by the Division of Oil, Gas and Mineral
Industries (Division 20 Geothermal Regulation). These rules require drilling
permits and govern the spacing of wells, rates of production, prevention of
waste and other matters, and, may not allow or may restrict drilling activity,
or may require that a geothermal resource be unitized (shared) with adjoining
land owners. Such laws and regulations may increase the costs of planning,
designing, drilling, installing, operating and abandoning our geothermal wells,
the power plant and other facilities. State environmental requirements and
permits, such as the Idaho Department of Environmental Quality, 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.
-51-
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:
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from a well or drilling equipment at a drill
site; |
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leakage of fluids or airborne pollutants from
gathering systems, pipelines, power plant and storage tanks; |
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damage to geothermal wells resulting from
accidents during normal operations; and |
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blowouts, cratering and explosions.
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Because the requirements imposed by such laws and regulations
are frequently changed, we cannot assure you that laws and regulations enacted
in the future, including changes to existing laws and regulations, will not
adversely affect our business by increasing cost and the time required to
explore and develop geothermal projects. In addition, because 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.
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:
-52-
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actual or anticipated variations in our reserve
estimates and quarterly operating results; |
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changes in electricity prices; |
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changes in our funds from operations or
earnings estimates; |
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publication of research reports about us or the
exploration and production industry; |
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increases in market interest rates which may
increase our cost of capital; |
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changes in applicable laws or regulations,
court rulings and enforcement and legal actions; |
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changes in market valuations of similar
companies; |
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adverse market reaction to any increased
indebtedness we incur in the future; |
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additions or departures of key management
personnel; |
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actions by our stockholders; |
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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 |
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general market and economic conditions.
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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) and on the Toronto Stock
Exchange (TSX) 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.
-53-
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 Companys internal control over financial reporting, as well as an
attestation report by the Companys independent auditors on internal controls
over financial reporting if the Company is no longer qualified as a smaller
reporting company under applicable SEC rules. We may incur additional costs in
order to comply with Section 404. In addition, if we fail to achieve and
maintain the adequacy of our internal controls, as such standards are modified,
supplemented or amended from time to time, we may not be able to ensure that we
can conclude on an ongoing basis that we have effective internal controls over
financial reporting in accordance with Section 404 of 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 stocks liquidity; SEC
enforcement actions; and securities claims and litigation.
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.
Future sales of our common stock by our existing
stockholders may depress our stock price.
Sales of a substantial number of shares of our common stock in
the public market, or the perception that these sales may occur, could cause the
market price of our common stock to decline and impair our ability to raise
capital through the sale of additional securities.
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.
-54-
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.
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 $6,500,000 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 36 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 eight 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 (4) and California (1). The properties include the Raft
River area located in southeastern Idaho, the two properties located in
southeastern Oregon, and six 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 properties in
northwestern Nevada include San Emidio, Gerlach, Crescent Valley, Lee Hot
Springs, and Ruby Hot Springs.
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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WESTERN UNITED STATES REGIONAL LOCATION MAP
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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 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 includes 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, USGs 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. As a result leases are held through rental
payment.
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El Ceibillo, Republic of Guatemala
The Company successfully acquired a geothermal energy rights
concession in the Republic of Guatemala. The concession, granted by the
Guatemalan government, consists of 24,710 acres (100 square kilometers) and is
located 14 miles southwest of Guatemala City, the capital. The concession has a
five year term for the development and construction of a power plant and there
are no royalties due to the government. The El Ceibillo project, is located near
the town of Amatitlan, in a developed industrial zone immediately adjacent to
the highway that connects Guatemala City to the Port of San Jose on the Pacific
coast. An office and staff are located in Guatemala City, and 17 acres of
surface has been under lease. An additional surface lease of 80 acres was signed
on October 15, 2014, bringing the total surface leasehold interest to 97
acres.
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Crescent Valley and Lee Hot Springs, Nevada
On December 16, 2014, U.S. Geothermal completed the acquisition
of EPR and EPRs 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. EPRs 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. WGPs Unit 15 property includes surface and geothermal
rights that consist of two federal geothermal leases (CA-51000 & CA-51001),
and two private geothermal leases with no expiration. The total project acreage
is 3,808 acres. The site is 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, 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 prepaid royalty for the 421 acre
parcel private land 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 then divided between 3 surface owners based
on a 50-25-25 basis. The Filly-Brown Lease includes 214 acres of surface access
rights and 50% of the mineral rights; the remaining 50% mineral interest is
owned by Western GeoPower. The Filly-Brown lease rental totals $260,000 annually
but has no expiration or renewal date. Geothermal royalty payments for Abril
Ranch and Filley-Brown are calculated on a sliding scale to account for the
final contracted electricity price established by a power purchase agreement.
-64-
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 311F to 320F and
historical drilling in the area has encountered ground (rock) temperatures in
excess of 300F. 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 newly acquired leases.
-65-
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 1,370 acres while approximately 64,064 acres are controlled
through geothermal development leases signed with the BLM, local governmental
entities and private owners. The companys average per acre lease rate is $9.00
per acre/year.
BLM Leases
The Company and its subsidiaries have 28 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 lessees 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 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.
-66-
Typical BLM leases issued to geothermal lessees 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.
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 arms
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 arms length transaction is 10.0% of the gross
proceeds from the arms length sale.
Private Geothermal Leases
U.S. Geothermal and its subsidiaries hold 70 geothermal leases
with private parties. The leases authorize the right to conduct geothermal
development and operations on privately owned geothermal estate. 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.
-67-
Lessors reserve the right to conduct other activities on the
leased land in a manner that does not unreasonably interfere with the geothermal
lessees 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, establishes milestones for development
and production. The Company has negotiated and acquired surface access from two
owners and control 115 surface acres enabling geothermal development. The leases
are similar in term and conditions to our leases with private owners in the
United States.
-68-
Item 3. Legal Proceedings
As of March 16, 2015, management is not aware of any material
current or pending legal proceedings in which the Company is a party, as
plaintiff or defendant, or which involve any of its properties.
Item 4. Mine Safety Disclosures
Not applicable.
-69-
PART II
Item 5. Market for Registrants 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, 2013 through December 31, 2014 for
the Companys common stock trading on the NYSE MKT, under the trade
symbol HTM:
Sale Prices on the NYSE
MKT |
|
|
High |
Low |
Year Ended December 31, 2014 |
($) |
($) |
First Quarter |
0.95 |
0.38
|
Second Quarter |
0.83 |
0.52
|
Third Quarter |
0.72 |
0.55
|
Fourth Quarter |
0.57
|
0.43 |
|
|
|
Year Ended December 31, 2013 |
|
|
First Quarter |
0.37 |
0.31
|
Second Quarter |
0.43 |
0.32
|
Third Quarter |
0.59 |
0.36
|
Fourth Quarter |
0.50
|
0.37 |
TSX
The following table sets forth information relating to the
trading of our common stock from January 1, 2013 through December 31, 2014 for
the Companys common stock trading on the TSX under the trade symbol
GTH:
Sale Prices on the TSX |
|
|
High |
Low |
Year Ended December 31, 2014 |
(CDN$) |
(CDN$) |
First Quarter |
1.05 |
0.40
|
Second Quarter |
0.88 |
0.57
|
Third Quarter |
0.77 |
0.60
|
Fourth Quarter |
0.64
|
0.51 |
|
|
|
Year Ended December 31, 2013 |
|
|
First Quarter |
0.39 |
0.31
|
Second Quarter |
0.44 |
0.33
|
Third Quarter |
0.65 |
0.36
|
Fourth Quarter |
0.53
|
0.39 |
As of March 6, 2015, we had approximately 17,000 stockholders.
The Company has never paid and does not intend to pay dividends
on its common stock in the foreseeable future. Although the Companys
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.
-70-
On December 12, 2014, the Company completed the acquisition of
EPR for a total of six hundred ninety-two thousand seven hundred sixty-nine
(692,769) shares of our stock that were issued in exchange for all outstanding
shares of EPR stock. The shares issued by the Company in connection with the
acquisition were offered and sold in reliance upon the exemption from
registration provided by Section 4(a)(2) under the Securities Act of 1933, as
amended (the Securities Act). The basis for relying on this exemption is that
the issuance of common stock to the shareholders as consideration for the
merger, was a privately negotiated transaction without general solicitation. The
certificates representing the shares of common stock issued in the merger
contain a legend to the effect that such shares are not registered under the
Securities Act and may not be transferred except pursuant to a registration
statement that has become effective under the Securities Act or pursuant to an
exemption from such registration.
Item 6. Selected Financial Data
|
|
For the Years Ended |
|
|
For the Fiscal Years Ended |
|
|
|
December 31, |
|
|
March 31, |
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2012 |
|
|
2011 |
|
Operating Revenues |
$ |
30,596,261 |
|
$ |
27,370,934 |
|
$ |
9,758,946 |
|
$ |
5,894,113 |
|
$ |
3,253,545 |
|
Operating Expenses |
|
26,006,964 |
|
|
23,240,285 |
|
|
14,090,471 |
|
|
16,522,690 |
|
|
7,292,895 |
|
Income (Loss) from Continuing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
4,589,297 |
|
|
4,130,649 |
|
|
(4,331,525 |
) |
|
(6,222,129 |
|
|
(3,954,416 |
) |
Income (Loss) attributable to U.S.
Geothermal Inc. |
|
11,613,711 |
|
|
1,946,579 |
|
|
(2,958,567 |
) |
|
|
|
|
|
|
Income (Loss) per share
attributable to
U.S. Geothermal Inc. |
|
0.11 |
|
|
0.02
|
|
|
(0.03 |
) |
|
(0.07 |
) |
|
(0.05 |
) |
Cash dividends declared and paid per
common share |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
As of December 31, |
|
|
As of March 31, |
|
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2012 |
|
|
2011 |
|
Total Assets |
$ |
232,914,304 |
|
$ |
232,765,297 |
|
$ |
240,496,096 |
|
$ |
219,030,868 |
|
$ |
85,322,968 |
|
Total Long-term Obligations (1)
|
|
95,821,634 |
|
|
99,247,344 |
|
|
104,318,206 |
|
|
69,495,470 |
|
|
18,326,802 |
|
(1) |
Long-term obligations represent the stock compensation
payable, a convertible loan, plant loans and capital lease obligations.
The stock compensation liability is the fair value of stock options to be
exercised by officers, directors, employees and consultants of the
Company. These obligations were recorded as a liability since the option
exercise price was stated in Canadian dollars, subjecting the Company and
the employee to foreign currency exchange risk in addition to the normal
market price fluctuation risk. As of December 31, 2014, 2013 and 2012,
long-term obligations did not include stock compensation
payable. |
-71-
|
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. |
Fiscal Year Ended March
31, 2012 |
|
|
|
|
|
1st Quarter
|
(0.03) |
1,397,975 |
(1,110,296) |
(4,633,355) |
(2,341,024) |
2nd Quarter
|
(0.01) |
1,689,609 |
(336,683) |
(1,467,778) |
(922,043) |
3rd Quarter
|
(0.02) |
1,647,442 |
(1,876,779) |
(2,534,598) |
(1,315,339) |
4th Quarter
|
(0.01) |
1,159,087 |
(1,061,775) |
(2,415,858) |
(1,643,723) |
Fiscal Year Ended March
31, 2013 |
|
|
|
|
|
1st Quarter
|
(0.01) |
1,159,087 |
(1,061,775) |
(2,415,858) |
(1,643,723) |
2nd Quarter
|
(0.01) |
1,280,949 |
(52,235) |
(1,827,157) |
(930,870) |
3rd Quarter
|
(0.00) |
2,019,749 |
270,012 |
(836,581) |
(766,100) |
4th Quarter
|
(0.01) |
5,299,161 |
966,804 |
748,072 |
382,126 |
Year Ended December 31,
2013 |
|
|
|
|
|
1st Quarter
|
0.01 |
7,086,990 |
4,102,509 |
2,235,079 |
1,388,523 |
2nd Quarter
|
(0.01) |
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
|
0.02 |
9,550,373 |
5,635,824 |
3,675,999 |
1,962,552 |
Year Ended December 31,
2014 |
|
|
|
|
|
1st Quarter
|
0.01 |
8,501,965 |
4,783,941 |
2,547,091 |
1,339,420 |
2nd Quarter
|
(0.01) |
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
|
0.11 |
9,883,938 |
5,731,213 |
2,654,719 |
11,345,324 |
Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations
Historical Overview
On March 5, 2002, U.S. Geothermal Inc. - Idaho entered into a
letter agreement with the owner of the Raft River project located in
southeastern Idaho, pursuant to which U.S. Geothermal Inc. - Idaho agreed to
acquire all of the real property, personal property and permits that comprised
the owners 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, but
has held steady at that level for two years.
-72-
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 Energys (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 early 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 hold 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 and geothermal water rights.
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).
-73-
Factors Affecting Our Results of Operations
Raft River Operating Agreement
We hold a 50% interest in Raft River Energy I LLC, which owns
Raft River Unit I (Unit I). Construction of Unit I required substantial
capital and partnering with a co-venture tax partner which allowed us to share
the risks of ownership and monetize valuable tax credits and benefits. The joint
venture partner structure allowed the project to monetize production tax credits
which would not otherwise have been available to us. While Unit I generates at
less than full capacity, our annual cash payments from the Raft River I project
will be lower than initially anticipated. If insufficient cash is generated to
satisfy all joint venture obligations, the management fees will be deferred.
Initially, Raft River Energy I LLC (RREI) was a wholly owned
subsidiary of the Company and was recorded as a fully consolidated subsidiary
into the Companys financial statements. In 2006, Raft River I Holdings
(Holdings), a subsidiary of the Goldman Sachs Group, acquired an equity
interest by providing a significant capital investment in RREI under a tax
equity structure. Subsequent accounting activity of RREI was reflected under the
equity method on the Companys consolidated financial statements.
Based on managements annual review of conditions and
circumstances, it was determined that the Company would no longer use the equity
method to reflect the Companys interest in RREI as of April 1, 2011. The
Company is now fully consolidating RREIs assets, liabilities and operations and
is recognizing a non-controlling interest. When making this determination,
Management analyzed whether control had shifted to the Company for accounting
purposes, and notes that participation by Holdings is and has been passive. The
Board of Managers does not hold regular meetings, does not formally approve the
annual operating budgets, and Holdings declined to contribute additional funds
even when benefits can be shown. The Company has possession of and operates the
facility, makes all day-to-day operating decisions, and contributes additional
required capital funding as needed. Active participation in the operations of
RREI is a primary role of the Companys operating staff. The most important
element that has changed is the economics of the project due to the zero balance
in the Raft River Holdings tax capital account. Tax deductions associated with
an additional $12.1 million equity contribution from the Company accelerated the
exhaustion of the Holdings tax capital account to zero sooner than originally
anticipated. The Company has received 100% of the tax deductions and operating
losses for the tax year 2011 and will receive them in subsequent years. Since
the current structure of RREI was established to allocate significant tax
benefits to Holdings, the exhaustion of the Holdings tax capital account to zero
demonstrates that the majority of the tax benefits have been monetized. Holdings
no longer has any tax capital at risk. The Company is the only partner with tax
capital at risk, so future operating decisions will primarily impact the
Company.
-74-
The Companys interests in RREI as defined in the partnership
agreements are summarized as follows:
|
Years 1 4 (2008-2011) |
Years 5 10 (2012-2017) |
Years 11 20 (2018-2027) |
Years 20 25 (2028-2032) |
Cash Flow |
RECs |
70% (1) |
GAAP Income |
1% (2) |
49% |
80% |
Lease Payments, O&M Services & Royalties |
100% |
Distributions |
Guaranteed min. payment |
1% (3)
|
49%
|
80%
|
Tax Benefits |
1% (2) |
49% |
80% |
(1) |
The Company allocates 70% of income and receives 70% of
available cash from RECs sold to third- parties. After year 10, REC income
is shared with Idaho Power Co. For additional details, see the amended and
restated operating agreements as amended. |
|
|
(2) |
Flip to next tier occurs after the later of 10 years or
Raft River I Holdings target IRR is achieved. |
|
|
(3) |
Flip to next tier occurs after Raft River I Holdings
target IRR is achieved. |
Power Purchase Agreements
Prior to the construction of a geothermal project, we typically
enter into a PPA with a utility, which fixes the price of energy produced at a
project for a 20 to 25 year period. Such PPAs are typically negotiated with the
utility company and approved by a state utility commission or similar regulating
body.
Power purchase agreements generally provide for energy
payments, capacity payments, or both. Energy payments are calculated based on
the amount of electrical energy delivered to the relevant power purchaser at a
designated delivery point. The rates applicable to such payments are either
fixed, subject to annual adjustments. Capacity payments, on the other hand, are
generally calculated based on the amount of time that our power plants are
available to generate electricity. Some PPAs provide for bonus payments in the
event that the producer is able to exceed certain target levels and 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 3.9% in the
initial years and by 1.0% during the latter 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 will be
sold under the terms of the amended and restated PPA. The PPA was approved by
the Public Utility Commission of Nevada on December 27, 2011.
-75-
Raft River Energy I LLC
Raft River Energy I LLC currently earns revenue from a
full-output PPA with Idaho Power, which allows power sales up to 13 megawatts
annual average. The PPA was signed on September 24, 2007 and expires in 2032.
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.
Operating Results
For the year ended December 31 2014, the Company reported net
income attributable to the Company of $11,616,504 ($0.11 income per share) which
represented a $10,942,075 increase from net income of $1,946,579 reported in the
year ended 2013 ($0.02 income per share). Net income of $15,025,922 from plant
operations for the year ended December 31, 2014 increased $1,814,010 (13.7%
increase) from income of $13,211,912 reported in the year ended 2013. Other
notable favorable variances were reported in professional and management fees,
salaries and wages, and change in deferred income taxes. Notable unfavorable
variances were reported in stock based compensation, interest expense and other
income/expenses.
Plant Operations
During the years ended December 31, 2014 and 2013, the
Companys energy production revenues and related operating costs originated from
its three fully operational power plants. The San Emidio plant (USG Nevada LLC)
is located in the San Emidio Desert in the northwestern part of the State of
Nevada. The original San Emidio plant and related water rights were purchased in
2008. The old plant ceased operations in December 2011 and was replaced with a
new plant that began commercial operations in May 2012. The Raft River plant
(Raft River Energy I LLC) is located in South Eastern Idaho. The Raft River
plant began operations in January of 2008. The new plant at Neal Hot Springs,
Oregon (USG Oregon LLC) began commercial operations on November 16, 2012.
-76-
A summary of energy sales by plant for the two reporting
periods are as follows:
|
|
For the Year Ended December 31, |
|
|
|
2014 |
|
|
|
|
|
2013 |
|
|
|
|
|
|
$ |
|
|
%* |
|
|
$ |
|
|
%* |
|
Energy sales by plant: |
|
|
|
|
|
|
|
|
|
|
|
|
Neal Hot Spring,
Oregon |
|
18,759,248 |
|
|
61.3 |
|
|
15,566,409 |
|
|
57.7 |
|
San Emidio, Nevada |
|
7,031,445 |
|
|
23.0 |
|
|
6,792,382 |
|
|
25.2 |
|
Raft River,
Idaho |
|
4,805,568 |
|
|
15.7 |
|
|
4,627,258 |
|
|
17.1 |
|
|
|
30,596,261 |
|
|
100.0 |
|
|
26,986,049 |
|
|
100.0 |
|
%* - represents the percentage of
total Company energy sales.
A quarterly summary of megawatt hours generated by plant are as
follows:
|
|
For the Quarter Ended, |
|
|
|
December 31, |
|
|
March 31, |
|
|
June 30, |
|
|
September |
|
|
December 31, |
|
|
|
2013 |
|
|
2014 |
|
|
2014 |
|
|
30, 2014 |
|
|
2014 |
|
Neal Hot Spring, Oregon |
|
53,445 |
|
|
56,047 |
|
|
40,629 |
|
|
32,246 |
|
|
54,472 |
|
San Emidio, Nevada |
|
21,112 |
|
|
21,223 |
|
|
15,686 |
|
|
18,240 |
|
|
21,745 |
|
Raft River, Idaho |
|
21,951 |
|
|
21,614 |
|
|
18,069 |
|
|
18,501 |
|
|
20,614 |
|
|
|
96,508 |
|
|
98,884 |
|
|
74,384 |
|
|
68,987 |
|
|
96,831 |
|
Neal Hot Springs, Oregon (USG Oregon LLC) Plant
Operations
The Neal Hot Springs plant began producing power in the quarter
ended December 31, 2012 and was considered to be commercially operational on
November 16, 2012. The year ended December 31, 2013, was the plant's first full
year of operations. For the year ended December 31, 2014, the plant reported net
profit of $9,826,233 which was an increase of $2,396,997 (32.3% increase) from
the net profit of $7,417,135 reported in the year ended 2013. For the year ended
December 31, 2014, plant energy revenues increased 20.5% from the prior year
ended 2013. The total of 183,394 megawatt hours produced in the current year
increased 27,965 megawatt hours (18.0% increase) from the 155,428 megawatt hours
produced in the prior year. The quarters ended March 31, 2014 and December 31,
2014, were the highest quarters of energy production and revenue to date. High
production was due to less down time and the greater efficiency of the cooling
towers due to the cooler ambient temperatures of the fall/winter months. For the
third quarter of 2013, the plant's three units experienced a total of 928 hours
of lost production which was significantly greater than the 59 hours of lost
production in the third quarter of 2014. The largest loss in third quarter of
2013 was due to the failure of the refrigerant pump at unit one (618 hours). In
the fourth quarter of 2013, the plant lost a total of 316 hours primarily due to
stoppages caused by low liquid levels in the condenser. In the fourth quarter of
2014, the three units only experienced a total loss of approximately 70 hours.
Plant operating costs, excluding depreciation, increased
$693,972, which was a 22.3% increase from the prior year to the current year
ended September 30, 2014. The largest variances were noted in administrative
support, insurance, chemicals and plant/well field maintenance costs. For the
year ended December 31, 2014 administrative and corporate support costs
increased $156,519, which was a 21.4% increase from the year ended 2013.
Effective for the current year, a contracted monthly corporate support fee of
$13,750 was established. Also, additional consulting fees related to the general
plant maintenance that amounted to over $57,000 were incurred for the year ended
December 31, 2014.
-77-
For the year ended December 31, 2014, the plants insurance
costs totaled $377,619 which was an increase of $152,163 (67.5% increase) from
the year ended 2013. In July 2013, the plants insurance coverage transferred
from a builders risk policy to a full property coverage policy which resulted
in a significant increase in cost (approximately $31,660 increase per month). In
May of 2014, an insurance rate adjustment was made that reduced premiums by
approximately 20% (approximately $14,345 decrease per month).
Plant and field maintenance costs increased $219,544, which was
a 43.7% increase for the year ended December 31, 2014 from the year ended 2013.
In May 2014, a turbine seal was replaced at a cost of $62,298. In the third
quarter of 2014, costs that exceeded $169,000 were incurred to repair a feed
pump for Unit 1, repair piping modules for all three units, and rebuild a seal
for Unit 2.
Summarized statements of operations for the Neal Hot Springs,
Oregon plant are as follows:
|
|
Year Ended December 31, |
|
|
2014 |
|
2013 |
|
|
Variance |
|
|
|
$ |
|
|
%* |
|
|
$ |
|
|
% |
|
|
$ |
|
|
%** |
|
Plant revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales |
|
18,759,248 |
|
|
100.0 |
|
|
15,566,409 |
|
|
100.0 |
|
|
3,192,839 |
|
|
20.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
3,812,460 |
|
|
20.3 |
|
|
3,118,488 |
|
|
20.0 |
|
|
(693,972 |
) |
|
(22.3 |
) |
Depreciation and
amortization |
|
3,263,450 |
|
|
17.4 |
|
|
3,217,071 |
|
|
20.7 |
|
|
(46,379 |
) |
|
(1.4 |
) |
|
|
7,075,910 |
|
|
37.7
|
|
|
6,335,559 |
|
|
40.7
|
|
|
(740,351 |
) |
|
(11.7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income |
|
11,683,338 |
|
|
62.3
|
|
|
9,230,850 |
|
|
59.3
|
|
|
2,452,488 |
|
|
26.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
(1,875,639 |
) |
|
(10.0 |
) |
|
(1,856,255 |
) |
|
(11.9 |
) |
|
(31,485 |
) |
|
(1.7 |
) |
Interest income/other |
|
18,534
|
|
|
0.1
|
|
|
42,540
|
|
|
0.2
|
|
|
(24,006 |
) |
|
(56.4 |
) |
|
|
(1,875,105 |
) |
|
(9.9 |
) |
|
(1,813,715 |
) |
|
(11.7 |
) |
|
(55,491 |
) |
|
(3.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
9,826,233 |
|
|
52.4 |
|
|
7,417,135 |
|
|
47.6 |
|
|
2,396,997 |
|
|
32.3 |
|
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2013 to 2014. Increases in revenues and
decreases in expenses from the prior period to the current period are considered
to be favorable and are presented as positive figures.
The intercompany elimination
adjustments for management fees and corporate support are not incorporated into
the presentation of the subsidiarys net operating income/loss.
-78-
Key quarterly production data for the Neal Hot Springs, Oregon
plant is summarized as follows:
|
|
Mega- |
|
|
|
|
|
Ave. Rate |
|
|
|
|
|
Depreciation |
|
|
|
watt |
|
|
Energy |
|
|
per |
|
|
|
|
|
& |
|
|
|
Hours |
|
|
Sales |
|
|
Megawatt |
|
|
Net Income* |
|
|
Amortization |
|
Quarter Ended: |
|
Produced |
|
|
($) |
|
|
Hour ($) |
|
|
($) |
|
|
($) |
|
March 31, 2013 |
|
46,137 |
|
|
4,197,252 |
|
|
90.6 |
|
|
2,424,648 |
|
|
779,299 |
|
June 30, 2013 |
|
30,016 |
|
|
2,435,304 |
|
|
80.2 |
|
|
518,754 |
|
|
814,434 |
|
September 30, 2013 |
|
25,832 |
|
|
2,875,686 |
|
|
110.9 |
|
|
829,374 |
|
|
810,573 |
|
December 31, 2013 |
|
53,445 |
|
|
6,058,169 |
|
|
113.3 |
|
|
3,644,359 |
|
|
812,766 |
|
March 31, 2014 |
|
56,047 |
|
|
5,266,454 |
|
|
93.8 |
|
|
3,070,349 |
|
|
817,503 |
|
June 30, 2014 |
|
40,629 |
|
|
3,403,812 |
|
|
83.7 |
|
|
1,196,404 |
|
|
820,526 |
|
September 30, 2014 |
|
32,246 |
|
|
3,717,609 |
|
|
115.0 |
|
|
1,412,124 |
|
|
805,497 |
|
December 31, 2014 |
|
54,472 |
|
|
6,378,488 |
|
|
117.1 |
|
|
4,147,356 |
|
|
819,924 |
|
* - The intercompany elimination
adjustments for management fees and corporate support are not incorporated into
the presentation of the subsidiarys net income.
San Emidio, Nevada Plant Energy Sales and Plant Operating
Expenses (USG Nevada LLC)
For the year ended December 31, 2014, the San Emidio plant
reported net profit of $487,793 which was a decrease of $670,845 (57.9%
decrease) from the net profit of $1,158,638 reported in the year ended 2013. For
the current year, both energy revenues and megawatt hours produced were
consistent with the prior year ended 2013. Total megawatts produced in the
current year increased to 76,894 megawatt hours from 76,697 megawatt hours (0.3%
increase). The average rate earned per megawatt hour in the current year
increased to $91.4 from $88.7 (3.1% increase) earned in the prior year. For the
year ended December 31, 2014, operating expenses, excluding depreciation,
increased $720,836 (28.8% increase) from the year ended 2013. The primary reason
for the increase related to property tax expenses and related legal costs, which
increased approximately $393,197. In the prior year ended December 31, 2013, the
Company collected a property tax refund of $226,859 related to an error made in
2012. Additional repair costs were incurred in the current year that included
turbine repairs and tuning, two pump motor replacements and control panel
upgrades for costs that exceeded $36,100, $35,200 and $16,480; respectively.
Also, chemical costs for the cooling system increased approximately $108,110
(138.1% increase) from the prior year due to both price increases and lost
product due, in part, to an acid pump malfunction.
For the year ended December 31, 2014, the plants interest
expense increased $318,720 (18.3% increase) from the year ended 2013. During the
quarter ended March 31, 2013, the plant loan had not been finalized and most of
the interest incurred under the contractors obligations was capitalized. In the
quarter ended March 31, 2013, the plant incurred interest costs that totaled
$621,712.
-79-
Summarized statements of operations for the San Emidio, Nevada
plant are as follows:
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
|
|
|
|
|
2014 |
|
|
|
|
|
2013 |
|
|
|
|
|
Variance |
|
|
|
|
|
|
$ |
|
|
%* |
|
|
$ |
|
|
% |
|
|
$ |
|
|
%** |
|
Plant revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales |
|
7,031,445 |
|
|
100.0 |
|
|
6,792,382 |
|
|
100.0 |
|
|
239,063 |
|
|
3.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations |
|
3,221,652 |
|
|
45.8 |
|
|
2,500,816 |
|
|
36.8 |
|
|
(720,836 |
) |
|
(28.8 |
) |
Depreciation and
amortization |
|
1,261,438 |
|
|
17.9 |
|
|
1,392,502 |
|
|
20.5 |
|
|
131,064 |
|
|
9.4 |
|
|
|
4,483,090 |
|
|
63.8
|
|
|
3,893,318 |
|
|
57.3
|
|
|
(589,772 |
) |
|
(15.1 |
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
(loss) |
|
2,548,355 |
|
|
36.2
|
|
|
2,899,064 |
|
|
42.7
|
|
|
(350,709 |
) |
|
(12.1 |
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
(2,060,901 |
) |
|
(29.3 |
) |
|
(1,742,181 |
) |
|
(25.6 |
) |
|
(318,720 |
) |
|
(18.3 |
) |
Interest income |
|
339
|
|
|
0.0
|
|
|
1,755
|
|
|
0.0
|
|
|
(1,416 |
) |
|
(80.7 |
)
|
|
|
(2,060,562 |
) |
|
(29.3 |
) |
|
(1,740,426 |
) |
|
(25.6 |
) |
|
(320,136 |
) |
|
(18.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
487,793 |
|
|
6.9 |
|
|
1,158,638 |
|
|
17.1 |
|
|
(670,845 |
) |
|
(57.9 |
) |
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2013 to 2014. Increases in revenues and
decreases in expenses from the prior period to the current period are considered
to be favorable and are presented as positive figures.
The intercompany elimination
adjustments for management fees and corporate support are not incorporated into
the presentation of the subsidiarys net operating income/loss.
Key quarterly production data for the San Emidio, Nevada plant
is summarized as follows:
|
|
Mega- |
|
|
|
|
|
Ave. Rate |
|
|
|
|
|
Depreciation |
|
|
|
watt |
|
|
Energy |
|
|
per |
|
|
Net Income |
|
|
& |
|
|
|
Hours |
|
|
Sales |
|
|
Megawatt |
|
|
(Loss)* |
|
|
Amortization |
|
Quarter Ended: |
|
Produced |
|
|
($) |
|
|
Hour ($) |
|
|
($) |
|
|
($) |
|
March 31, 2013 |
|
19,228 |
|
|
1,726,927 |
|
|
90.3 |
|
|
834,266 |
|
|
407,060 |
|
June 30, 2013 |
|
18,039 |
|
|
1,628,382 |
|
|
90.3 |
|
|
(212,058) |
|
|
365,314 |
|
September 30, 2013 |
|
18,317 |
|
|
1,531,260 |
|
|
83.6 |
|
|
355,498 |
|
|
307,854 |
|
December 31, 2013 |
|
21,112 |
|
|
1,905,813 |
|
|
90.3 |
|
|
180,931 |
|
|
312,273 |
|
March 31, 2014 |
|
21,223 |
|
|
1,935,091 |
|
|
91.2 |
|
|
423,350 |
|
|
312,908 |
|
June 30, 2014 |
|
15,686 |
|
|
1,450,526 |
|
|
92.5 |
|
|
(203,424) |
|
|
316,283 |
|
September 30, 2014 |
|
18,240 |
|
|
1,663,119 |
|
|
91.2 |
|
|
109,515 |
|
|
316,638 |
|
December 31, 2014 |
|
21,745 |
|
|
1,982,709 |
|
|
91.2 |
|
|
158,352 |
|
|
315,609 |
|
* - The
intercompany elimination adjustments for management fees are not incorporated
into the presentation of the subsidiarys net income/loss.
-80-
Raft River, Idaho Unit I (Raft River Energy I LLC) Plant
Operations
Net loss from Raft River Energy I LLC (RREI) operations of
$197,125 for the year ended December 31, 2014 favorably decreased by $197,732
from the loss of $394,847 reported for the year ended 2013. For the current
year, both energy revenues ($4,805,568) and megawatt hours produced (78,798
megawatt hours) were consistent with the prior year ended 2013. For the year
ended December 31, 2014, the megawatt hours produced increased 1,238 (1.6%
increase) from the year ended 2013. Depreciation costs decreased 6.9% from the
prior year primarily due to many of the assets with shorter estimated useful
lives (5 years or less) that were placed into operation during the initial years
of production have been fully depreciated.
The summarized statements of operations for RREI are as
follows:
|
|
Year Ended December 31, |
|
|
|
2014 |
|
|
|
|
|
2013 |
|
|
|
|
|
Variance |
|
|
|
$ |
|
|
%* |
|
|
$ |
|
|
%* |
|
|
$ |
|
|
%** |
|
Plant revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales |
|
4,805,568 |
|
|
92.8 |
|
|
4,627,258 |
|
|
92.3 |
|
|
178,310 |
|
|
3.9 |
|
Energy credit sales |
|
372,521 |
|
|
7.2
|
|
|
384,885 |
|
|
7.7
|
|
|
(12,364 |
) |
|
(3.2 |
)
|
|
|
5,178,089 |
|
|
100.0 |
|
|
5,012,143 |
|
|
100.0 |
|
|
165,946 |
|
|
3.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General operations |
|
3,566,337 |
|
|
68.9 |
|
|
3,378,794 |
|
|
67.4 |
|
|
(187,533 |
) |
|
(5.6 |
) |
Depreciation and
amortization |
|
1,716,465 |
|
|
33.1 |
|
|
1,844,579 |
|
|
36.8 |
|
|
128,114 |
|
|
6.9 |
|
|
|
5,282,802 |
|
|
102.0
|
|
|
5,223,373 |
|
|
104.2
|
|
|
(59,419 |
) |
|
(1.1 |
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss |
|
(104,713 |
) |
|
(2.0 |
) |
|
(211,230 |
) |
|
(4.2 |
) |
|
106,527 |
|
|
50.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
(95,592 |
) |
|
(1.9 |
) |
|
(197,461 |
) |
|
(3.9 |
) |
|
101,869 |
|
|
51.6 |
|
Other and interest income |
|
3,180
|
|
|
0.1
|
|
|
13,844
|
|
|
0.2
|
|
|
(10,664 |
) |
|
(77.0 |
)
|
|
|
(92,412 |
) |
|
(1.8 |
) |
|
(183,617 |
) |
|
(3.7 |
) |
|
91,205 |
|
|
49.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
(197,125 |
) |
|
(3.8 |
) |
|
(394,847 |
) |
|
(7.9 |
) |
|
197,732 |
|
|
50.1 |
|
%* - represents the percentage of
total plant operating revenues.
%** - represents the
percentage of change from 2013 to 2014. Increases in revenues and
decreases in expenses from the prior period to the current period are considered
to be favorable and are presented as positive figures.
The intercompany elimination
adjustments for interest expense, management fees and lease costs are not
incorporated into the presentation of the subsidiarys operations.
-81-
Key quarterly production data for RREI is summarized as
follows:
|
|
Mega- |
|
|
|
|
|
Ave. Rate |
|
|
|
|
|
Depreciation |
|
|
|
watt |
|
|
Energy |
|
|
per |
|
|
Net Income |
|
|
& |
|
|
|
Hours |
|
|
Sales |
|
|
Megawatt |
|
|
(Loss)* |
|
|
Amortization |
|
Quarter Ended: |
|
Produced |
|
|
($) |
|
|
Hour ($) |
|
|
($) |
|
|
($) |
|
March 31, 2013 |
|
19,675 |
|
|
1,064,481 |
|
|
56.1 |
|
|
67,620 |
|
|
472,040 |
|
June 30, 2013 |
|
17,248 |
|
|
823,154 |
|
|
49.9 |
|
|
(715,605) |
|
|
472,094 |
|
September 30, 2013 |
|
18,687 |
|
|
1,260,124 |
|
|
69.5 |
|
|
(1,166) |
|
|
450,222 |
|
December 31, 2013 |
|
21,951 |
|
|
1,479,499 |
|
|
69.0 |
|
|
254,302 |
|
|
450,222 |
|
March 31, 2014 |
|
21,614 |
|
|
1,199,550 |
|
|
57.9 |
|
|
61,749 |
|
|
427,907 |
|
June 30, 2014 |
|
18,069 |
|
|
907,194 |
|
|
52.6 |
|
|
(579,569) |
|
|
428,180 |
|
September 30, 2014 |
|
18,501 |
|
|
1,273,013 |
|
|
71.2 |
|
|
117,281 |
|
|
429,164 |
|
December 31, 2014 |
|
20,614 |
|
|
1,425,811 |
|
|
71.3 |
|
|
203,414 |
|
|
431,214 |
|
* - Net income (loss) does not
include intercompany elimination adjustments for interest expense, management
fees and lease costs.
Professional and Management Fees
For the year ended December 31, 2014, the Company incurred
professional and management fees of $986,742, which was a decrease of $298,194
(23.2% decrease) from the year ended 2013. The two primary elements for the
decrease were the consulting fees paid to the former CEO and the decreases in
legal fees. In May 2013, the Company entered into a contract with the former
CEOs consulting firm. The original contract ended April 2014, and was extended
through December 2014 at a reduced rate of $1,000 per month. During the current
year, consulting fees were paid to the former CEOs consulting firm totaled
$60,161, which was a decrease of $161,120 (72.8% decrease) from the fees paid in
2013. During the year ended December 31, 2014, legal fees were paid to the
Companys primary legal counsel of $93,782, which was a decrease of $121,877
(56.5% decrease) from the fees paid in 2013. In the prior year, additional legal
fees were incurred for negotiations and contract reviews concerning the
employment agreements for both the prior and successor Chief Executive Officers.
Also, legal fees were incurred related to capital raise that was completed in
December 2012.
Salaries and Wages
Salaries and wages include payroll and related costs incurred
for exploration, design and development costs that cannot be capitalized, as
well as general management and administration. Payroll and related costs for
plant operations are expensed as plant production costs. For the year ended
December 31 2014, the Company reported $1,858,423 in salaries and related costs,
which was a decrease of $277,522 (13.0% decrease) from the year ended 2013.
Salaries and related costs for administration and development employees before
allocations totaled $2,595,439, which was an increase 1.5% from the year ended
2013. In the year current year, allocations for capital projects and plant
operations exceeded $499,000 and $452,000; respectively. For the prior year,
allocations for capital projects and plant operations exceeded $723,000 and
$13,000; respectively. The two projects that utilized management and development
staff resources in the current year were the San Emidio Phase II, Nevada and
Guatemala projects, which incurred management and development salary costs of
approximately $120,400 and $125,100; respectively. In the prior year, the major
project was Neal Hot Springs, Oregon. In April 2014, the Company awarded raises
to its employees that averaged 2.9%, and bonuses were awarded that totaled
$376,750. In April 2013 and July 2013, employee bonuses were awarded that
totaled $171,000 and $237,800; respectively.
-82-
Stock Based Compensation
For the year ended December 31 2014, the Company reported
$1,339,496 in stock based compensation, which was an increase of $582,561 (77.0%
increase) from the year ended 2013. Stock based compensation includes the
calculated values for both Company stock and stock options granted to employees
and board members. The Company uses the Black-Scholes option-pricing model to
value the cost of the outstanding stock options. The higher value of the stock
options for the current year was directly impacted by the number of outstanding
options, the increase in the Companys stock price and the related increase in
the volatility of the Companys stock price. On April 2, 2014, the
Company awarded employees 2,883,500 stock options and 559,122 shares (restricted
shares). In the prior year, the Company did not issue stock options to employees
until July 22, 2013 (1,950,000 options, no restricted shares to employees).
During the current year ended December 31, 2014, the Companys common stock
price reached a high of $0.95 and a low of $0.38 ($0.59 average daily closing
price). During the year ended December 31, 2013, the Companys common stock
price reached a high of $0.59 and a low of $0.31 ($0.40 average daily closing
price).
The stock based compensation components are summarized as
follows:
|
|
For the Year Ended |
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
|
|
|
2014 |
|
|
2013 |
|
|
Variances |
|
|
|
$ |
|
|
$ |
|
|
$ |
|
|
% |
|
Total Stock Based Compensation: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock option
compensation |
|
1,115,392 |
|
|
683,443 |
|
|
431,949 |
|
|
63.2 |
|
Stock compensation |
|
224,104 |
|
|
73,492 |
|
|
150,612 |
|
|
204.9
|
|
|
|
1,339,496 |
|
|
756,935 |
|
|
582,561 |
|
|
77.0 |
|
% - represents the percentage of change from 2013 to
2014.
Exploration
For the year ended December 31, 2014, the Company reported
$508,500 in exploration costs, which was an increase of $469,018 from the year
ended 2013. During the current year, the Company incurred costs of $432,705 on
well drilling activities for the Gerlach, Nevada project.
Other Income/Expenses
For the year ended December 31, 2014, the Company reported a
net loss of $346,588 in other income/expenses which was an unfavorable increase
of $462,453 from the net gain reported the year ended 2013. In the fourth
quarter of 2014, the Company abandoned the Granite Creek area located in the
State of Nevada, and is in the process of disposing the 2,445 acres of
geothermal water rights purchased in April 2008 for $451,299.
-83-
Change in Deferred Income Tax Assets and Liabilities
For the year ended December 31, 2014, the Company reported an
increase in deferred income tax assets and liabilities of $12,060,000 which was
an increase of $10,482,000 from the year ended 2013. At the end of the current
year, the Company determined that the more likely than not threshold had been
met regarding the Companys ability to use its earned deferred income tax assets
(primarily unused net operating losses). Prior to December 31, 2014, the Company
only recognized net deferred income tax assets to the extent used for reported
book income.
Net Income Attributable to the Non-Controlling
Interests
The net income attributable to the non-controlling interest
entities is the line item that removes the portion of the total consolidated
operations that are owned by the Companys partners. For the year ended December
31, 2014, the Company reported $3,277,793 in net income attributable to
non-controlling interests, which was an increase of $1,093,723 (32.5% increase)
from net income of $2,184,070 for the year ended 2013. The primary reason for
the increase was due to the operations of the Neal Hot Springs plant (Oregon USG
Holdings LLC) which reported net income of $9,826,233 for the year ended
December 31, 2014. The impact of the Neal Hot Springs operations on the
Companys reported income attributable to non-controlling entities was an
increase of $963,640 (32.5% increase) from the year ended December 31, 2013 as
compared to the current year ended 2014.
The net (income) or loss attributable to the non-controlling
interest entities is detailed as follows:
|
|
For the Year Ended |
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
|
|
|
Subsidiaries and Non-Controlling |
|
2014 |
|
|
2013 |
|
|
Variance |
|
|
|
|
Interest Entities |
|
$ |
|
|
$ |
|
|
$ |
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oregon USG Holdings LLC interest held by Enbridge
Inc. |
|
(3,915,952) |
|
|
(2,848,081) |
|
|
1,067,871 |
|
|
37.5 |
|
Raft River Energy I LLC interest held by Raft River I
Holdings, LLC |
|
452,193 |
|
|
656,469 |
|
|
204,276 |
|
|
31.1 |
|
Gerlach Geothermal LLC interest held by Gerlach Green
Energy, LLC |
|
181,173 |
|
|
7,542 |
|
|
(173,631) |
|
|
# |
|
|
|
(3,282,586) |
|
|
(2,184,070) |
|
|
1,098,516 |
|
|
50.3 |
|
% - represents the percentage
of change from 2013 to 2014. # - variance percentage that is
extremely high or undefined.
-84-
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, 2014:
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
Neal Hot |
|
|
San |
|
|
|
|
|
Activities and |
|
|
Consolid- |
|
Statement of Operations |
|
Springs |
|
|
Emidio |
|
|
Raft River |
|
|
Corporate |
|
|
ated |
|
Element |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
Net income from
plant operations |
|
11,683,339 |
|
|
2,548,355 |
|
|
(104,714) |
|
|
898,942 |
|
|
15,025,922 |
|
Expenses/income |
|
1,893,459 |
|
|
2,060,561 |
|
|
92,411 |
|
|
(4 )6,390,194 |
|
|
10,436,625 |
|
Net income (loss) |
|
9,789,880 |
|
|
487,794 |
|
|
(197,125) |
|
|
(5,491,252) |
|
|
4,589,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
(3,740,000) |
|
|
(186,000) |
|
|
75,000 |
|
|
2,098,000 |
|
|
(1,753,000) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
3,740,000 |
|
|
186,000 |
|
|
(75,000) |
|
|
8,209,000 |
|
|
12,060,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-controlling interests |
|
(1 )(3,915,952) |
|
|
- |
|
|
(2 )452,193 |
|
|
(3 )181,173 |
|
|
(3,282,586) |
|
Net income attributable
to U.S. Geothermal |
|
5,873,928 |
|
|
487,794 |
|
|
255,068 |
|
|
4,996,921 |
|
|
11,613,711 |
|
(1) |
The non-controlling interests for Neal Hot Springs
represents a 40% interest for our joint venture partner,
Enbridge. |
|
|
(2) |
The non-controlling interests 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 interests for our exploration
activities represents an approximately 39% interest for our joint venture
partner at Gerlach, GGE Development. |
|
|
(4) |
Major costs included in Exploration Activities and
Corporate for the year ended December 31, 2014
include: |
|
|
Salaries and wages |
|
$ 1,858,423 |
|
|
|
Stock based compensation |
|
1,339,496 |
|
|
|
Corporate administration
|
|
1,136,849 |
|
|
|
Professional fees |
|
986,742 |
|
|
|
Exploration costs |
|
508,500 |
|
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.
-85-
Liquidity and Capital Resources
During the calendar year ended December 31, 2014, the operating
projects of U.S. Geothermal have generated significant available cash (after
debt service and reserves) to fund our development activities and corporate
costs. Neal Hot Springs has distributed $7.2 million in equity; San Emidio has
generated $1.4 million in net cash; Raft River has paid $0.2 million in REC
income. In addition, cash received by corporate as a result of management fees,
royalties and lease income totaled $1.1 million. We believe our cash and
liquid investments at December 31, 2014 are adequate to fund our general
operating activities through December 31, 2015. 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.
The recent financial credit crisis has not impacted the ability
of our customers, Idaho Power Company and Sierra Pacific Power (NV Energy), to
pay for their power. This power is sold under long-term contracts at fixed
prices to large utilities. The status of the credit and equity markets could
delay our project development activities while we seek to obtain economic credit
terms or a favorable equity market price to further the drilling and
construction activities.
On December 12, 2014, the Company completed the acquisition of
Earth Power Resources Inc. (EPR) for a total of six hundred ninety-two
thousand seven hundred sixty-nine (692,769) shares of U.S. Geothermal stock that
were issued in exchange for all outstanding shares of EPR stock. In addition to
the shares issued, $42,934 in cash was also provided at close to allow EPR to
pay outstanding obligations. The transaction was unanimously approved by EPR
Shareholders. The assets acquired from EPR include geothermal leases covering
26,017 acres in Nevada, representing three projects that have an energy
potential estimated in the range of 158 to 359 megawatts. Also included is EPRs
complete geothermal resource database of new project opportunities located
throughout the western United States, which EPR had compiled over its nearly 40
years of geothermal exploration experience. Under the terms of the agreement,
fifty percent (50%) of the new stock issued for the acquisition will be held in
reserve by the Company for 6 months to cover any potential undisclosed claims
against EPR. The non-reserved 50% of new stock will be delivered to the EPR
shareholders upon surrender of their EPR share certificates, but trading of the
new USG shares is restricted under SEC Rule 144 for a period of 6 months
On April 21, 2014, the Company completed the acquisition of Ram
Power Corp.s (Ram) Geysers project for a total of $6.4 million in cash. The
Ram subsidiaries included in the acquisition are Western GeoPower, Inc., Skyline
Geothermal Holding, Inc., and Etoile Holdings Inc., which in turn includes all
membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The
acquired Ram subsidiaries possess the full development interest in the project.
These interests include all geothermal leases (covering 3,809 acres),
development design plans, and permits for a proposed up to 38.5gross megawatt
power plant, and includes land and geothermal mineral rights ownership of the
Mayacamas property purchased by Ram in 2010. This property contains four
existing geothermal wells immediately available for production or injection and
one historic well available for use after reworking. Finally, the acquisition
includes a 50% undivided interest in the geothermal mineral rights relating to
the property that contains the 5th existing well also purchased by Ram in 2010.
The other 50% interest in this property is contained within an acquired
leasehold interest.
-86-
On February 4, 2014, a replacement shelf registration statement
filed on Form S-3 with the SEC became effective. The replacement shelf
registration statement was filed as routine course of business due to the
impending expiration of the Companys existing shelf registration statement
that, under SEC rules, would have expired on December 1, 2013. The Company may
use the replacement shelf registration statement to offer and sell from time to
time for a period of three years in one or more public offerings up to $50
million of common stock, warrants, or units consisting of any combination
thereof. The terms of any securities offered under the replacement shelf
registration statement, and the intended use of the resulting net proceeds, will
be established at the times of any future offerings and will be described in
prospectus supplements filed at such times with the SEC. The Company has no
immediate plans to sell any additional stock under the replacement shelf
registration statement at this time, but wishes to preserve the option in
support of its future growth and development of its projects as well as
strategic acquisition opportunities.
Following the receipt of the Section 1603 Federal Investment
Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit
funds, and after the receipt and disbursement of all remaining construction
reserve funds, which was finalized on January 27, 2014, the final ownership
interest in the Neal Hot Springs project was calculated in accordance with the
terms of the partnership agreement. Ownership interest in the project is final
with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final
agreement, U.S. Geothermal received a $6.2 million cash distribution from the
partnership.
Under the terms of the DOE loan agreement, project profits are
distributed to the equity partners semi-annually (February and August),
following Final Completion, which was achieved on August 1, 2013. U.S.
Geothermals share of this first distribution received March 5, 2014 was $4.6
million, out of a total distribution to the partners of $7.7 million, which
represents profits generated from the project since initial operation began in
November 2012. U.S. Geothermals share of the distribution received August 19,
2014 was $2.6 million, out of a total distribution to the partners of $4.3
million.
Under the Loan Guarantee Agreement at Neal Hot Springs with the
Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank
subject to certain procedural restrictions on the use of the funds. The
waterfall of funds out of the Revenue account is processed semi-annually. On
December 31, 2014, $16.7 million in USG Oregon LLC funds were deposited at PNC
Bank, and were unavailable for immediate corporate needs.
For projects under construction before the end of 2010 and
online before the end of 2014, a project was eligible to take a 30% ITC in lieu
of the PTC. The ITC was able to be converted into a cash grant within the first
90 days of operation of the plant. Phase I at San Emidio attained commercial
operation on May 25, 2012. An application was submitted in July 2012 electing to
take the ITC cash grant in lieu of the PTC. The United States Department of
Treasury notified the Company that it would allow $10.65 million in cash grant.
The cash grant proceeds were received on November 10, 2012 and used to repay the
Ares Capital bridge loan facility, with the remaining balance payable to USG
Nevada LLC. An additional $1.05 million of cash grant items were subsequently
approved and paid in March 2013. For the Neal Hot Springs project, an
application was submitted in the first quarter 2013 electing to take the ITC
cash grant, in lieu of the PTC, for approximately $35.9 million from U.S.
Treasury and the funds would be used to fund reserves required under the DOE
Loan Guarantee Agreement and return funds to our partner in the project,
Enbridge. Due to federal sequestration in early 2013, the ITC cash grant amount
received in April 2013 was reduced by 8.7% to $32.7 million.
-87-
In July 2010, the Company applied to the Oregon Department of
Energy for the Business Energy Tax Credit (BETC), which allows an income tax
credit for up to $20 million in qualifying expenditures for a renewable energy
project. The Neal Hot Springs project completed final certification for the
credit and sold it to a pass-through partner, monetized at a cash value of $7.36
million (less a broker fee) in November 2013.
On May 21, 2012, the Company entered into a purchase agreement
(the Purchase Agreement) with Lincoln Park Capital Fund, LLC (LPC), pursuant
to which the Company has the right to sell to LPC up to $10,750,000 in shares of
the Companys common stock, (Common Stock), subject to certain limitations and
conditions set forth in the Purchase Agreement and imposed by the Companys
board of directors and pricing committee thereof. Pursuant to the Purchase
Agreement LPC initially purchased $750,000 in shares of Common Stock at $0.38
per share. Following this initial purchase, on any business day and as often as
every other business day over the 36-month term of the Purchase Agreement, and
up to an aggregate amount of an additional $10,000,000 (subject to certain
limitations) in shares of Common Stock, the Company has the right, from time to
time, at its sole discretion and subject to certain conditions to direct LPC to
purchase up to 250,000 shares of Common Stock, which amount may be increased in
accordance with the Purchase Agreement if the closing sale price of Common Stock
on the NYSE MKT exceeds certain specified levels. The purchase price of shares
of Common Stock pursuant to the Purchase Agreement will be based on prevailing
market prices of Common Stock at the time of sales without any fixed discount,
and the Company will control the timing and amount of any sales of Common Stock
to LPC. No sales of Common Stock under the Purchase Agreement will be made
through the TSX. The Purchase Agreement contains customary representations,
warranties and agreements of the Company and LPC, limitations and conditions to
completing future sale transactions, indemnification rights and other
obligations of the parties. There is no upper limit on the price per share that
LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC
shall not have the right or the obligation to purchase any shares of Common
Stock if the purchase price of those shares, determined as set forth in the
Purchase Agreement, would be below $0.25 per share. The Company has the right to
terminate the Purchase Agreement at any time, at no cost or penalty. Actual
sales of shares of Common Stock to LPC under the Purchase Agreement will depend
on a variety of factors to be determined by the Company from time to time,
including (among others) market conditions, the trading price of the Common
Stock and determinations by the Company as to available and appropriate sources
of funding for the Company and its operations. As consideration for entering
into the Purchase Agreement, the Company has issued to LPC 651,819 shares of
Common Stock. The Company will not receive any cash proceeds from the issuance
of these 651,819 shares. As of December 31, 2014, the Company has sold LPC an
aggregate of 4,625,506 shares of common stock pursuant to the Purchase Agreement
for net proceeds of approximately $1,343,639 (net of $86,911 broker and legal
fees). On December 21, 2012, the Company and LPC entered into an Amendment No. 1
to the Purchase Agreement (the Amendment) to reduce the total amount that can
be purchased under the Purchase Agreement, including amounts already purchased,
from $10,750,000 to $6,500,000.
-88-
In September 2010, Oregon USG Holdings, LLC (a wholly owned
subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a
strategic and financial partnership to finance the Neal Hot Springs project
located in eastern Oregon. A component of these agreements included a $5 million
convertible promissory note, which converted. The DOE guaranteed project loan
was treated as an equity contribution by Enbridge to the project. The agreements
also provided for additional equity contributions of $13.8 million from Enbridge
that when combined with the $5 million convertible promissory note earned
Enbridge a 20% direct ownership in the project. As a result of cost overruns for
the project, and at the election of the Company, an additional payment
obligation of up to $8 million was contributed by Enbridge that increased their
direct ownership in the project by 1.5 percentage points for each $1 million
contributed. Added to their base 20% ownership, additional payments increased
Enbridges ownership to 27.5% . An additional $6 million cost overrun facility
was established by Enbridge to cover costs that resulted from unexpected poor
results from injection well drilling. The additional investment by Enbridge
increased their ownership in USG Oregon LLC based on running a project financial
model and determining what percentage of the forecasted project income would be
allocated to Enbridge to arrive at a predetermined rate of return for the
additional investment. In February 2014, the final ownership interest in the
Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40%
for Enbridge. As a result of the final agreement, U.S. Geothermal Inc. received
an approximate $6.2 million cash distribution from the partnership.
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 Companys geothermal
resources, and through possible mergers with or acquisitions of operating power
plants and geothermal or other renewable energy properties.
-89-
Critical Accounting Policies
The discussion and analysis of our financial condition and
results of operations are based upon the consolidated financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States of America. The preparation of these financial
statements requires us to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. Certain accounting policies
involve judgments and uncertainties to such an extent that there is reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been made. We evaluate our
estimates and assumptions on a regular basis. We base our estimates on
historical experience and various other assumptions that are believed to be
reasonable under the circumstances, the results of which form the basis for the
financial statements.
Cash and Cash Equivalents
The Company considers cash
deposits and highly liquid investments to be cash and cash equivalents for
financial reporting presentation on the consolidated balance sheet and statement
of cash flows. The Company subscribes to the accounting standards that define
cash equivalents as highly liquid, short-term instruments that are readily
convertible to known amounts of cash, which are generally defined investments
that have original maturity dates of less than three months. With the large
value of funds invested in short-term deposits, small variations in short term
interest rates may materially affect the value of cash equivalents. Investments
in government obligations accumulate higher interest, but the principal balance
is not insured by the FDIC.
Property, Plant and Equipment
During the development
stage of operations, the Company has purchased and otherwise acquired geothermal
properties for the production of power. The geothermal properties include:
drilled wells, power plant components, power plant support components, land,
land rights, surface water rights, and geothermal water rights. The 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
Companys 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 Companys
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.
-90-
Stock-Based Compensation
The Company awards stock
options for compensation to non-employees for services performed and/or services
performed above and beyond expectations. After the services have been completed,
the awards are made at the discretion of the Board of Directors. The fair value
of the options are determined on the date the options are awarded according to
several factors that include the exercise price of the option, the current price
of the underlying share, the expected life of the options and the expected
volatility of the stock. Generally speaking, a longer life and higher expected
volatility yields a higher value of the option. In accordance with appropriate
accounting guidance, the Company amortizes the value of these options as
operating expense during the period in which they vest. Stock options awarded to
Company employees are also valued on the date they are awarded. However, the
value of these options are capitalized and expensed over the vesting period. The
current vesting period for all options is eighteen months. The nature of the
services provided determines whether the value will be expensed or added to the
value of a Company asset. To date, no services have been provided directly
related to the construction of property and equipment, thus, all services have
been charged to operations.
Contractual Obligations
As of December 31, 2014, 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 |
$ 17,611,937 |
$ 899,579 |
$ 1,830,587 |
$ 1,608,300 |
$ 13,273,471 |
Capital Leases |
20,919 |
20,919 |
- |
- |
- |
Plant Loan (1) |
30,182,333 |
471,091 |
1,237,375 |
1,252,502 |
27,221,365 |
Plant Loan, DOE(2) |
66,974,611 |
3,419,927 |
6,627,950 |
6,505,003 |
50,421,731 |
Note Payable, Settlement Agreement (3)
|
1,487,266
|
390,051
|
853,886
|
243,329
|
-
|
Note Payable, Auto Loans (4) |
68,412 |
9,919 |
22,359 |
26,225 |
9,909 |
(1) |
Plant loan with Prudential Capital Group scheduled for to
be repaid over the next 24 years. |
(2) |
Plant loan with the Department of Energy scheduled to be
repaid over the next 21 years. |
(3) |
Loan agreement that originated with a settlement
agreement with SAIC Constructors LLC scheduled to be repaid over the next
five years. |
(4) |
Three auto loans to be repaid in five
years. |
Off Balance Sheet Arrangements
As of December 31, 2014, the Company does not have any off
balance sheet arrangements.
-91-
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk
Interest Risk on Investments
At December 31, 2014,
the Company held investments of $30,515,067 in money market accounts. These are
highly liquid investments that are subject to risks associated with changes in
interest rates. The money market funds are invested in governmental obligations
with minimal fluctuations in interest rates and fixed terms.
Foreign Currency Risk
|The Company is subject to a
limited amount of foreign currency risks associated with cash deposits
maintained in Canadian currency. The Company has utilized and it is continuing
to utilize the Canadian markets for raising capital. By proper timing of the
transactions and then maintenance of adequate operating funds in other financial
resources, the Company has been able to mitigate some of the risks surrounding
foreign currency exchanges. At fiscal year end, the Company did not hold any
deposits in Canadian currency. Also, the Canadian currency exchange rate has
been reasonably consistent over the past fiscal year. As a matter of standard
operating practice, the Company does not maintain large balances of Canadian
currency; and, substantially, all operating transactions are conducted in U.S.
dollars.
A long-term liability has been established to reflect the fair
value of the stock options payable. The strike price on the Companys stock
option grants since April 2007 has been stated U.S. dollars.
Commodity Price Risk
The Company is exposed to risks
surrounding the volatility of energy prices. These risks are impacted by various
circumstances surrounding the energy production from natural gas, nuclear,
hydro, solar, coal and oil. The Company has been able to mitigate, to a certain
extent, this risk by entering into long-term PPAs for the Raft River, Neal Hot
Springs and San Emidio power plants. These types of arrangement will be the
model for power purchase contracts planned for future power plants.
Item 8. Financial Statements and Supplementary
Data
The information required hereunder is set forth under Report
of Independent Registered Public Accounting Firm, Consolidated Balance
Sheets, Consolidated Statements of Operations, Consolidated Statements of
Comprehensive Income (Loss) and Stockholders Equity (Deficit), Consolidated
Statements of Cash Flows, and Notes to Consolidated Financial Statements
included in the consolidated financial statements that are a part of this
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.
-92-
U.S. GEOTHERMAL INC.
________
Consolidated Financial Statements
December 31, 2014
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. as of December 31, 2014 and 2013, and the related
consolidated statements of operations, stockholders equity, and cash flows for
each of the periods then ended. U.S. Geothermal, Inc.s management is
responsible for these financial statements. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. The company
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the companys internal control
over financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. In our opinion, the financial statements
referred to above present fairly, in all material respects, the financial
position of U.S. Geothermal, Inc. as of December 31, 2014 and 2013, and the
results of its operations and its cash flows for each of the periods then ended,
in conformity with accounting principles generally accepted in the United States
of America.
MartinelliMick PLLC
Spokane, WA
March 13, 2015
U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS
|
|
December 31, |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
Cash and cash equivalents
(note 2) |
$ |
12,994,975 |
|
$ |
28,736,934 |
|
Restricted cash and bonds (note 3) |
|
3,320,781
|
|
|
3,081,020 |
|
Trade accounts receivable
|
|
3,774,133 |
|
|
4,106,806 |
|
Deferred
income tax asset (note 7) |
|
1,803,000
|
|
|
- |
|
Other current assets |
|
1,550,359 |
|
|
1,079,262 |
|
Total current assets |
|
23,443,248 |
|
|
37,004,022 |
|
|
|
|
|
|
|
|
Investment in equity
securities (note 4) |
|
- |
|
|
42,174 |
|
Restricted cash and bond reserves (note
3) |
|
18,690,096 |
|
|
18,815,145 |
|
Property, plant and
equipment, net of accumulated depreciation (note 5) |
|
166,859,446 |
|
|
161,583,938 |
|
Intangible assets, net of accumulated
amortization (note 6) |
|
15,417,514 |
|
|
15,320,018 |
|
Net deferred income tax
asset (note 7) |
|
8,504,000 |
|
|
- |
|
|
|
|
|
|
|
|
Total
assets |
$ |
232,914,304 |
|
$ |
232,765,297 |
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
Accounts payable and
accrued liabilities |
$ |
1,886,947 |
|
$ |
1,626,687 |
|
Related
party accounts payable |
|
5,195 |
|
|
3,089 |
|
Current portion of
capital lease obligations (note 8) |
|
20,919 |
|
|
48,118 |
|
Current
portion of notes payable (note 9) |
|
4,336,271 |
|
|
4,127,170 |
|
Total current liabilities |
|
6,249,332 |
|
|
5,805,064 |
|
|
|
|
|
|
|
|
Long-term Liabilities: |
|
|
|
|
|
|
Long-term
portion of capital lease obligations (note 8) |
|
- |
|
|
20,921 |
|
Asset retirement
obligations (note 14) |
|
1,400,000 |
|
|
- |
|
Notes
payable, less current portion (note 9) |
|
94,376,351 |
|
|
99,226,423 |
|
Total
long-term liabilities |
|
95,776,351 |
|
|
99,247,344 |
|
|
|
|
|
|
|
|
Total
liabilities |
|
102,025,683 |
|
|
105,052,408 |
|
|
|
|
|
|
|
|
Commitments and Contingencies (note
14) |
|
- |
|
|
- |
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY |
|
|
|
|
|
|
Capital stock (authorized:
250,000,000 common shares with a $0.001
par value; issued and outstanding
shares at December 31, 2014 and
2013 were: 107,018,029 and
102,094,542; respectively) |
|
107,018
|
|
|
102,094 |
|
Additional paid-in capital |
|
103,669,371 |
|
|
100,381,207 |
|
Accumulated other
comprehensive loss |
|
- |
|
|
(27,321) |
|
Accumulated deficit |
|
(19,284,860) |
|
|
(30,898,571) |
|
|
|
84,491,529 |
|
|
69,557,409 |
|
|
|
|
|
|
|
|
Non-controlling interests
(note 15) |
|
46,397,092 |
|
|
58,155,480 |
|
Total
stockholders equity |
|
130,888,621 |
|
|
127,712,889 |
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity |
$ |
232,914,304 |
|
$ |
232,765,297 |
|
The accompanying notes are an integral part of these
consolidated financial statements.
-F-1-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF
OPERATIONS
|
|
For the Year Ended December 31, |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
Plant Revenues: |
|
|
|
|
|
|
Energy sales |
$ |
30,596,261 |
|
$ |
26,986,049 |
|
Energy credit sales |
|
372,521 |
|
|
384,885 |
|
Total plant operating revenues |
|
30,968,782 |
|
|
27,370,934 |
|
|
|
|
|
|
|
|
Plant Expenses: |
|
|
|
|
|
|
Plant production expenses |
|
9,701,506
|
|
|
7,704,871 |
|
Depreciation and
amortization |
|
6,241,354 |
|
|
6,454,151 |
|
Total plant operating expenses |
|
15,942,860 |
|
|
14,159,022 |
|
|
|
|
|
|
|
|
Net Income from Plant
Operations |
|
15,025,922 |
|
|
13,211,912 |
|
|
|
|
|
|
|
|
Expenses (Income): |
|
|
|
|
|
|
Corporate
administration |
|
1,136,849 |
|
|
881,880 |
|
Professional and management fees |
|
986,742
|
|
|
1,284,936 |
|
Salaries and wages
|
|
1,858,423 |
|
|
2,135,945 |
|
Stock based compensation |
|
1,339,496
|
|
|
756,935 |
|
Travel and
promotion |
|
199,894 |
|
|
202,060 |
|
Exploration costs |
|
508,500
|
|
|
39,482 |
|
Interest expense
|
|
4,060,133 |
|
|
3,895,890 |
|
Other (income) expenses |
|
346,588 |
|
|
(115,865) |
|
Total expenses (income) |
|
10,436,625 |
|
|
9,081,263 |
|
|
|
|
|
|
|
|
Net Income Before Income Tax Expense
|
|
4,589,297 |
|
|
4,130,649 |
|
|
|
|
|
|
|
|
Net Income Tax (Expense) Benefit (note
7): |
|
|
|
|
|
|
Income taxes |
|
(1,753,000) |
|
|
(1,578,000) |
|
Change in deferred
tax assets and liabilities |
|
12,060,000 |
|
|
1,578,000 |
|
Net income tax (expense) benefit |
|
10,307,000 |
|
|
- |
|
|
|
|
|
|
|
|
Net Income |
|
14,896,297 |
|
|
4,130,649 |
|
|
|
|
|
|
|
|
Net income attributable to the non-controlling interests |
|
(3,282,586) |
|
|
(2,184,070) |
|
|
|
|
|
|
|
|
Net Income Attributable to
U.S. Geothermal Inc. |
|
11,613,711 |
|
|
1,946,579 |
|
|
|
|
|
|
|
|
Other Comprehensive Income
(Loss): |
|
|
|
|
|
|
Unrealized
income (loss) on investment in equity securities |
|
27,321 |
|
|
(23,377) |
|
|
|
|
|
|
|
|
Comprehensive Income Attributable to U.S. Geothermal
Inc. |
$ |
11,641,032 |
|
$ |
1,923,202 |
|
|
|
|
|
|
|
|
Basic Net Income Per Share Attributable to
U.S. Geothermal Inc. |
$ |
0.11 |
|
$ |
0.02 |
|
Diluted Net Income Per Share Attributable to
U.S. Geothermal Inc. |
$ |
0.09 |
|
$ |
0.02 |
|
|
|
|
|
|
|
|
Weighted Average Number of
Shares Outstanding for Basic Calculations |
|
104,273,319 |
|
|
101,795,364 |
|
Weighted Average Number of Shares, Stock Options and
Warrants Outstanding for Diluted Calculations |
|
126,006,172 |
|
|
123,497,883 |
|
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, |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
Operating Activities:
|
|
|
|
|
|
|
Net Income |
$ |
14,896,297 |
|
$ |
4,130,649 |
|
Adjustments to reconcile net
income to total cash provided by operating activities: |
|
|
|
|
|
|
Depreciation and amortization |
|
6,367,817 |
|
|
6,575,266 |
|
Stock based compensation |
|
1,339,496
|
|
|
756,935 |
|
Stock based officer bonus |
|
- |
|
|
100,000 |
|
Gain on software refund |
|
(13,239) |
|
|
- |
|
Loss
on disposal of geothermal water rights |
|
451,299 |
|
|
- |
|
Loss on sale of securities |
|
27,967
|
|
|
- |
|
Change in deferred tax assets and liabilities |
|
(10,307,000) |
|
|
- |
|
Net changes in: |
|
|
|
|
|
|
Trade accounts receivable, operating |
|
332,673 |
|
|
(809,9160 |
|
Accounts payable and accrued liabilities |
|
178,158
|
|
|
128,868 |
|
Prepaid expenses and other |
|
(471,097) |
|
|
(240,158) |
|
Total cash provided by operating activities |
|
12,802,371 |
|
|
10,641,644 |
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
Purchases of property,
plant and equipment |
|
(3,746,083 |
|
|
(13,868,842) |
|
Company
acquisitions |
|
(6,842,281) |
|
|
- |
|
Proceeds from ITC cash
grants receivable |
|
- |
|
|
40,113,741 |
|
Proceeds
from sale of equities held for investment |
|
41,528
|
|
|
- |
|
Proceeds from software
refund |
|
31,120 |
|
|
- |
|
Net
funding of restricted cash reserves and bonds |
|
(4,712) |
|
|
(17,474,465) |
|
Total cash
provided (used) by investing activities |
|
(10,520,428) |
|
|
8,770,434 |
|
|
|
|
|
|
|
|
Financing Activities: |
|
|
|
|
|
|
Issuance
of share capital |
|
1,634,918
|
|
|
- |
|
Contributions from
non-controlling interest |
|
7,360 |
|
|
7,460 |
|
Distributions to non-controlling interest |
|
(15,048,334) |
|
|
(117,2480 |
|
Proceeds from debt
obligations |
|
- |
|
|
16,570,400 |
|
Principal
payments on notes payable and other obligations |
|
(4,569,726) |
|
|
(19,999,2570 |
|
Principal payments on
capital leases |
|
(48,120) |
|
|
(45,278) |
|
Total cash
used by financing activities |
|
(18,023,902) |
|
|
(3,583,923) |
|
|
|
|
|
|
|
|
Increase (Decrease) in
Cash and Cash Equivalents |
|
(15,741,959) |
|
|
15,828,155 |
|
|
|
|
|
|
|
|
Cash and Cash Equivalents,
Beginning of Period |
|
28,736,934 |
|
|
12,908,779 |
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Period |
$ |
12,994,975 |
|
$ |
28,736,934 |
|
|
|
|
|
|
|
|
Supplemental
Disclosures: |
|
|
|
|
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
Purchase
of property and equipment on account |
$ |
84,208 |
|
$ |
1,107,189
|
|
Purchase of property and
equipment with notes payable |
|
- |
|
|
745,105 |
|
Company
acquisition by issuance of common stock |
|
318,674
|
|
|
- |
|
Property and equipment
costs reduced by settlement agreements |
|
- |
|
|
4,406,958 |
|
Grants
receivable used to decrease construction costs |
|
- |
|
|
2,770,459 |
|
|
|
|
|
|
|
|
Other Items: |
|
|
|
|
|
|
Interest paid |
|
4,080,396 |
|
|
6,973,502 |
|
The accompanying notes are an integral part of these
consolidated financial statements.
-F-3-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CHANGES
IN STOCKHOLDERS EQUITY
For the Years
Ended December 31, 2014 and 2013
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
Accumulated |
|
|
Non- |
|
|
|
|
|
|
Number of |
|
|
Common |
|
|
Paid-In |
|
|
Accumulated |
|
|
Comprehensive |
|
|
controlling |
|
|
|
|
|
|
Shares |
|
|
Shares |
|
|
Capital |
|
|
Deficit |
|
|
Income (Loss) |
|
|
Interest |
|
|
Totals |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2012
|
|
101,516,764 |
|
$ |
101,516 |
|
$ |
99,524,850
|
|
$ |
(32,845,150) |
|
$ |
(3,944) |
|
$ |
56,081,198
|
|
$ |
122,858,470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-controlling equity
contribution from Gerlach Green Energy, LLC |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
7,460 |
|
|
7,460 |
|
Distributions to non-controlling interest
entity |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(117,248) |
|
|
(117,248) |
|
Stock issued under terms of
employment agreement |
|
577,778 |
|
|
578 |
|
|
99,422 |
|
|
- |
|
|
- |
|
|
- |
|
|
100,000 |
|
Stock compensation |
|
- |
|
|
- |
|
|
756,935 |
|
|
- |
|
|
- |
|
|
- |
|
|
756,935 |
|
Unrealized loss on investment
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(23,377) |
|
|
- |
|
|
(23,377) |
|
Net income |
|
- |
|
|
- |
|
|
- |
|
|
1,946,579 |
|
|
- |
|
|
2,184,070 |
|
|
4,130,649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2013 |
|
102,094,542 |
|
|
102,094 |
|
|
100,381,207 |
|
|
(30,898,571) |
|
|
(27,321) |
|
|
58,155,480 |
|
|
127,712,889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions to non-controlling interest
entities (note 15) |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(15,048,334) |
|
|
(15,048,334) |
|
Non-controlling equity
contribution from Gerlach Green Energy, LLC |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
7,360 |
|
|
7,360 |
|
Stock issued to shareholders of acquired
company (note 16) |
|
692,769 |
|
|
693 |
|
|
317,981 |
|
|
- |
|
|
- |
|
|
- |
|
|
318,674 |
|
Stock issued by the exercise
of employee stock options |
|
1,077,000 |
|
|
1,077 |
|
|
336,544 |
|
|
- |
|
|
- |
|
|
- |
|
|
337,621 |
|
Stock issued by the exercise of stock
purchase warrants |
|
2,594,596 |
|
|
2,595 |
|
|
1,294,703 |
|
|
- |
|
|
- |
|
|
- |
|
|
1,297,298 |
|
Stock compensation |
|
559,122 |
|
|
559 |
|
|
1,338,936 |
|
|
- |
|
|
- |
|
|
- |
|
|
1,339,495 |
|
Unrealized loss and reclassification to net
income |
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
27,321 |
|
|
- |
|
|
27,321 |
|
Net income |
|
- |
|
|
- |
|
|
- |
|
|
11,613,711 |
|
|
- |
|
|
3,282,586 |
|
|
14,896,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2014
|
|
107,018,029 |
|
$ |
107,018 |
|
$ |
103,669,371 |
|
$ |
(19,284,860) |
|
$ |
- |
|
$ |
46,397,092 |
|
$ |
130,888,621 |
|
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, 2014
NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS
U.S. Geothermal Inc. 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, manages and operates power plants that utilize geothermal
resources to produce energy. The Companys operations have been, primarily,
focused in the Western United States of 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) |
Etoile Holdings Inc. (incorporated in the
Bahamas); |
|
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); and |
|
xx) |
Earth Power Resources Inc. (incorporated in
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 statements of operations
will consolidate the subsidiarys full operations, and will separately disclose
the elimination of the non-controlling interests allocation of profits and
losses.
-F-5-
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following are summarized accounting policies considered to
be significant by the Companys management:
Accounting Method
The Companys consolidated financial statements are prepared
using the accrual basis of accounting in accordance with generally accepted
accounting principles in the United States of America (U.S. GAAP) and have
been consistently applied in the preparation of the consolidated financial
statements.
Use of Estimates
The preparation of consolidated financial statements in
accordance with generally accepted accounting principles requires the use of
estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities known to exist as
of the date the consolidated financial statements are published, and the
reported amounts of revenues and expenses during the reporting period.
Uncertainties with respect to such estimates and assumptions are inherent in the
preparation of the Companys consolidated financial statements; accordingly, it
is possible that the actual results could differ from these estimates and
assumptions and could have a material effect on the reported amounts of the
Companys consolidated financial position and consolidated results of
operations.
Cash and Cash Equivalents
The Company considers all unrestricted cash, short-term
deposits, and other investments with original maturities of no more than ninety
days when acquired to be cash and cash equivalents for the purposes of the
statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs
with the Department of Energy, all funds for USG Oregon LLC are deposited into
PNC Bank subject to certain procedural restrictions on the use of the funds. The
waterfall of funds out of the Revenue account is processed semi-annually. At
December 31, 2014, $3.8 million in USG Oregon LLC funds were deposited at PNC
Bank in the Revenue account and $271,000 in Oregon USG Holdings LLC funds were deposited at Umpqua
Bank, and were unavailable for immediate corporate needs. Discussion regarding
restricted cash is included in Note 3.
Accounts Receivable Allowance for Doubtful
Accounts
Trade Accounts Receivable
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, 2014 and 2013, there were no
balances that were over 90 days past due and no balance in allowance for
doubtful accounts was recognized.
Grant Accounts Receivable
For receivables from grants from Federal or State agencies, the
Company records the receivable amounts net of the funds expected to be received.
Therefore, no allowance accounts are considered to be necessary for receivables
from grants at December 31, 2014 and 2013.
Concentration of Credit Risk
The Companys 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, 2014, the Companys
total cash balance, excluding money market funds, was $4,487,085, and bank
deposits amounted to $4,577,004. The primary difference was due to outstanding
checks and deposits. Of the bank deposits, $3,156,637 was not covered by or was
in excess of FDIC insurance guaranteed limits. At December 31, 2014, the
Companys money market funds invested, primarily, in government backed
securities totaled $30,515,067 and were not subject to deposit insurance.
-F-6-
Equity Securities
The Company determines the appropriate classification of
marketable securities at the time of purchase and reevaluates this designation
as of each balance sheet date. The Company classifies these securities as either
held-to-maturity, trading, or available-for-sale. All marketable securities and
restricted investments were classified as available-for-sale securities. The
Company classifies its investments as available for sale because it does not
intend to actively buy and sell for short-term profits. The Company's
investments are subject to market risk, primarily interest rate and credit risk.
The fair value of investments is determined using observable or quoted market
prices for those securities.
Available-for-sale securities are carried at fair value, with
unrealized gains and losses included as a component of accumulated other
comprehensive income (loss). Realized gains and losses, declines in value judged
to be other than temporary and interest on available-for-sale securities are
included in net income. The cost of securities sold is based on the specific
identification method whereby the gain or loss is calculated based upon the cost
of specifically identified securities for each sales transaction.
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 projects 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 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. 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.
-F-7-
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. |
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 its long-term assets annually for
impairment and when circumstances/events occur that may impact the fair value of
the assets. An impairment loss would be recognized if the carrying amount of a
capitalized asset is not recoverable and exceeds its fair value. The most recent
assessment was performed based upon financial conditions and assumptions as of
December 31, 2014, and there have not been any significant changes in financial
conditions and assumptions subsequent to that assessment date. Management
believes that there have not been any circumstances that have warranted the
recognition of losses due to the impairment of long-lived assets.
Stock Options Granted to Employees and
Non-employees
The Company follows financial accounting standards that require
the measurement of the value of employee services received in exchange for an
award of an equity instrument based on the grant-date fair value of the award.
For employees, directors and officers, the fair value of the awards are expensed
over the vesting period. The current vesting period for all such options is
eighteen months.
Non-employee stock-based compensation is granted at the Board
of Directors discretion to reward select consultants for exceptional
performance. Prior to issuance of the awards, the Company was not under any
obligation to issue the stock options. Subsequent to the award, the recipient
was not obligated to perform any services. Therefore, the fair value of these
options was expensed on the grant date, which was also the measurement date.
-F-8-
Under the fair value recognition provisions, share-based
compensation cost is measured at the grant date based on the value of the award
and is recognized as expense over the vesting period. Determining the fair value
of share-based awards at the grant date requires judgment. In addition, judgment
is also required in estimating the amount of share-based awards that are
expected to be forfeited. If actual results differ significantly from these
estimates, stock-based compensation expense and our results of operations could
be materially impacted.
Stock Based Compensation Granted to Employees
The Company recognizes the value of common stock granted to
employees and directors over the periods in which the services are received. The
value of those services is based upon the estimated fair value of the common
stock to be awarded. Estimated fair value is adjusted each reporting period. At
the end of each vesting period, estimated fair value is adjusted to fair market
value. The adjustment is reflected in the reporting period in which the vesting
occurs.
Earnings Per Share
The Company follows financial accounting standards, which
provides for calculation of "basic" and "diluted" earnings per share. Basic
earnings per share includes no dilution and is computed by dividing net income
available to common shareholders by the weighted average common shares
outstanding for the period. Diluted earnings per share reflect the potential
dilution of securities that could share in the earnings of an entity similar to
fully diluted earnings per share. Both basic and diluted were presented for the
calculation of the income per share for the periods that reported income. Stock
equivalents were not included in the calculation for the periods that reported
losses since their inclusion would be considered anti-dilutive. Total common
stock equivalents on a fully diluted basis at December 31, 2014 and 2013 were
126,744,104 (126,006,172 annual weighted average) and 124,494,963 (123,497,883
annual weighted average); respectively.
Financial Instruments
The Companys 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
managements 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.
The Companys functional currency is the U.S. dollar. Monetary
items are converted into U.S. dollars at the rate prevailing at the balance
sheet date. Resulting gains and losses are generally included in determining net
income for the period in which exchange rates change.
Revenue
Revenue Recognition
Energy Sales
The energy sales revenue is recognized
when the electrical power generated by the Companys 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 an inventory item
held for sale, and 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
statement of operations.
-F-9-
Revenue Source
All of the Companys
operating revenues (energy sales and energy credit sales) originate from energy
production from its interests in geothermal power plants located in the states
of Idaho, Oregon and Nevada.
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.
Reclassification
Certain amounts in the prior period financial statements have
been reclassified to conform to the current period presentation. These
reclassifications had no effect on reported income, total assets, or
stockholders equity as previously reported.
Recent Accounting Pronouncements
Management has considered all recent accounting pronouncements.
The following pronouncements were deemed applicable to our financial statements:
Stock Compensation
In June 2014, FASB
issued Accounting Standards Update No. 2014-12 (Update 2014-12),
Compensation-Stock Compensation, Accounting for Share-Based Payments When the
Terms of an Award Provide That a Performance Target Could Be Achieved after the
Requisite Service Period (Topic 718). Update 2014-12 provides guidance on
how to account for share-based payment awards that require a specific
performance target to be achieved in order for the employees to become eligible
to vest in the awards. Update 2014-12 is effective for annual periods and
interim periods within those annual periods beginning after December 15, 2015.
Management is still evaluating the applicability and possible impact this update
may have on the accounting treatment and its financial statement presentation.
Presentation of Property, Plant and Equipment
In April 2014, FASB issued Accounting Standards Update No. 2014-08
(Update 2014-08), Presentation of Financial Statements (Topic 205) and
Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations
and Disclosures of Disposals of Components of an Entity. Update 2014-08
provides guidance to address the issues surrounding the reporting of
discontinued operations and enhance the convergence of the FASBs and the
International Accounting Standard Boards reporting requirements for
discontinued operations. Update 2014-08 is effective for annual periods and
interim periods within those annual periods beginning after December 15, 2015.
Management is still evaluating the applicability and possible impact this update
may have on the accounting treatment and its financial statement presentation.
-F-10-
Business Combinations
In December
2014, FASB issued Accounting Standards Update No. 2014-18 (Update 2014-18),
Accounting for Identifiable Intangible Assets in Business Combination,
Business Combinations (Topic 805). Update 2014-18 provides modifications
to the evaluation of variable interest entities that may impact consolidation of
reporting entities. Update 2014-18 is effective for fiscal year beginning after
December 15, 2015, and the effective date of adoption depends on the timing of
that first in-scope transaction. If the first in-scope transaction occurs in the
first fiscal year beginning after December 12, 2015, the elective adoption will
be effective for that fiscal years annual financial reporting and all interim
and annual periods thereafter. The focus of this Update addresses the types of
intangible assets that the Company, typically, has not acquired or does not seek
to acquire; however, Management will continue to evaluate the possible impact
that this Update may have on the accounting treatment of applicable elements and
the financial presentation of these elements.
Consolidation
In February 2015, FASB
issued Accounting Standards Update No. 2015-02 (Update 2015-02), Amendments
to the Consolidation Analysis, Consolidation (Topic 810). Update
2015-02 provides modifications to the evaluation of variable interest entities
that may impact consolidation of reporting entities. Update 2015-02 is effective
for public business entities for fiscal years, and for interim periods within
those fiscal years, beginning after December 15, 2015. The Company currently
consolidates variable interest entities and may create or acquire variable
interest entities for future endeavors. Management is still evaluating the
possible impact this update may have on the financial presentation of the
Companys 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 |
|
|
2014 |
|
|
2013 |
|
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 |
|
|
188,930 |
|
|
19,848 |
|
Bureau of Land Management ,
Geothermal Rights Lease Bond |
|
|
10,000 |
|
|
- |
|
U.S. Department of Energy, Debt Service
Reserve |
|
|
2,151,851 |
|
|
2,191,172 |
|
State of California Division
of Oil, Gas and Geothermal Resources, Well Cash Bond |
|
|
100,000 |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
$ |
3,320,781 |
|
$ |
3,081,020 |
|
Long-term restricted cash and bond reserves:
|
|
|
December 31, |
|
Restricting Entities/Purpose |
|
|
2014 |
|
|
2013 |
|
Nevada Energy, PPA Security
Bond |
|
$ |
1,468,898
|
|
$ |
1,468,898
|
|
Prudential Capital Group, Debt Service
Reserves |
|
|
1,594,605 |
|
|
1,594,437 |
|
Prudential Capital Group,
Maintenance Reserves |
|
|
604,529 |
|
|
751,183 |
|
Prudential Capital Group, Well Reserves |
|
|
212,298 |
|
|
53,072 |
|
U.S. Department of Energy,
Operations Reserves |
|
|
270,000 |
|
|
270,000 |
|
U.S. Department of Energy, Debt Service
Reserves |
|
|
2,582,606 |
|
|
2,668,179 |
|
U.S. Department of Energy,
Short Term Well Field Reserves |
|
|
4,505,150 |
|
|
4,501,191 |
|
U.S. Department of Energy, Long-Term Well
Field Reserves |
|
|
4,761,927 |
|
|
4,507,391 |
|
U.S. Department of Energy,
Capital Expenditure Reserves |
|
|
2,690,083 |
|
|
3,000,794 |
|
|
|
|
|
|
|
|
|
|
|
$ |
18,690,096 |
|
$ |
18,815,145 |
|
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. Other future costs of environmental remediation
cannot be reasonably estimated and have not been recorded. 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, 2014 and 2013. As described in note 16, the Geysers acquisition
included a short term well bond of $100,000 and the Earth Power Resources Inc.
acquisition included a short term geothermal lease rights bond of $10,000.
-F-12-
NOTE 4 INVESTMENT IN EQUITY SECURITIES
During the quarter ended March 31, 2014, all of the Companys
holdings of equity securities (150,000 shares of Alterra Power Corp, a publicly
traded renewable energy company) were sold for $41,528, which resulted in a
realized loss of $27,967. The net change of $27,321 was reclassified from other
comprehensive income to net income as a result of the sale.
NOTE 5 - PROPERTY, PLANT AND EQUIPMENT
During the year ended December, 2014, the Company continued
development activities for San Emidio, Nevada and the Guatemala projects. Two
new exploration wells for the San Emidio Phase II project were drilled, one
exploration well drilled in 2013 was abandoned, and one other well drilled in
2013 was placed into production during the year for approximately $2.03 million.
A portion of the drilling and development costs were offset by grant proceeds of
$632,210. The new production well was connected to the existing Phase I power
plant and is producing fluid to the plant as part of a long term test of the
South Zone reservoir. During the year, costs that exceeded $924,000 were
incurred at Guatemala for the construction of nine temperature gradient
wells.
On December 12, 2014, the Company completed an acquisition of
Earth Power Resources Inc. See Note 16 for details. After acquisition, the
Company incurred approximately $133,000 on the drilling of a new production
well.
Effective April 22, 2014, the Company acquired a group of
companies (The Geysers, California) that included long-term assets that totaled
$7.74 million (land of $1.6 million, well and drilling construction in progress
of $6.14 million). See note 16 for acquisition details. After acquisition, the
Company incurred development costs of approximately $259,000 for design and
study work for a new power plant, transmission line and well field.
During the year ended December, 2013, the Company determined
that the project located in the Republic of Guatemala was economically viable
and began capitalizing drilling costs that amounted to over $1.7 million. At
Neal Hot Springs, an agreement was reached with a major contractor that resulted
in the reduction of project costs and related retainage of $2.26 million.
Additional costs of approximately $7.8 million were incurred at the Neal Hot
Springs power plant to finalize construction costs. The remaining balance of the
ITC cash grant for San Emidio relating to previously disputed expenditures of
approximately $1.05 million was collected. On February 15, 2013, the Company
signed a settlement agreement with SAIC (the general contractor and construction
loan holder) that reduced the construction liability including construction
costs and accrued interest by approximately $2.14 million for the San Emidio,
Nevada project. Costs that totaled approximately $817,000 were capitalized for a
phase II monitoring well at San Emidio.
-F-13-
Property, plant and equipment, at cost, are summarized as
follows:
|
|
|
December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
Land |
$ |
3,211,010
|
|
$ |
1,603,509
|
|
|
Power production plant |
|
162,076,367 |
|
|
161,868,687 |
|
|
Grant proceeds for power
plants |
|
(52,965,236) |
|
|
(52,965,236) |
|
|
Wells |
|
67,621,167 |
|
|
67,620,661 |
|
|
Grant proceeds for wells |
|
(3,464,555) |
|
|
(3,464,555) |
|
|
Furniture and equipment |
|
1,796,807 |
|
|
1,462,312 |
|
|
|
|
178,275,560 |
|
|
176,125,378 |
|
|
Less: accumulated depreciation |
|
(27,068,836) |
|
|
(20,895,943) |
|
|
|
|
151,206,724 |
|
|
155,229,435 |
|
|
Construction in progress |
|
15,652,722 |
|
|
6,354,503 |
|
|
|
|
|
|
|
|
|
|
|
$ |
166,859,446 |
|
$ |
161,583,938 |
|
Depreciation expense charged to plant operations and
administrative costs for the years ended December 31, 2014 and 2013, was
$6,186,132 and $6,393,581; respectively.
Changes in Construction in Progress are summarized as follows:
|
|
|
For the Year Ended December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
Beginning balances |
$ |
6,354,503
|
|
$ |
2,877,994
|
|
|
Development/construction
|
|
3,730,371 |
|
|
3,694,978 |
|
|
Grant
reimbursements and rebates |
|
(632,210) |
|
|
(33,325) |
|
|
Acquisition (note 16) |
|
6,200,058 |
|
|
- |
|
|
Transfers
into production |
|
- |
|
|
(185,144) |
|
|
Ending balances |
$ |
15,652,722 |
|
$ |
6,354,503 |
|
-F-14-
Construction in Progress, at cost, consisting of the following
projects/assets by location are as follows:
|
|
|
December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
Raft River, Idaho: |
|
|
|
|
|
|
|
Unit II,
power plant, substation and transmission lines |
$ |
750,493 |
|
$ |
750,493 |
|
|
Unit II, well construction |
|
2,127,547 |
|
|
2,121,502 |
|
|
|
|
2,878,040 |
|
|
2,871,995 |
|
|
San Emidio, Nevada: |
|
|
|
|
|
|
|
Unit II,
power plant, substation and transmission lines |
|
383,536 |
|
|
3,910 |
|
|
Unit II, well construction * |
|
3,133,873 |
|
|
1,753,299 |
|
|
|
|
3,517,409 |
|
|
1,757,209 |
|
|
Neal Hot Springs, Oregon: |
|
|
|
|
|
|
|
Power
plant and facilities |
|
6,477 |
|
|
- |
|
|
|
|
|
|
|
|
|
|
The Geysers, California (note 16): |
|
|
|
|
|
|
|
Power plant and facilities |
|
319,988 |
|
|
- |
|
|
Well construction
|
|
6,139,421 |
|
|
- |
|
|
|
|
6,459,409 |
|
|
- |
|
|
Crescent Valley, Nevada: |
|
|
|
|
|
|
|
Well
construction |
|
133,058 |
|
|
- |
|
|
|
|
|
|
|
|
|
|
El Ceibillo, Republic of Guatemala: |
|
|
|
|
|
|
|
Well Construction |
|
2,649,829 |
|
|
1,725,299 |
|
|
Plant and
facilities |
|
8,500 |
|
|
- |
|
|
|
|
2,658,329 |
|
|
1,725,299 |
|
|
|
|
|
|
|
|
|
|
|
$ |
15,652,722 |
|
$ |
6,354,503 |
|
*- Consists of four wells at December
31, 2014. The wells represent efforts to develop a well field to be utilized for
Phase II. As of the date of these financial statements, the results of the wells
are not sufficient to indicate the existence of a well field that would support
another power plant. Two wells are being utilized to target a potential resource
area. One well is currently being utilized/flow tested by the Phase I power
plant. One well has been capped and abandoned. Management is still actively
pursuing the Phase II project. If the project is abandoned, the cost of the
wells that have no future economic value will be removed.
-F-15-
NOTE 6 INTANGIBLE ASSETS
During the quarter ended June 30, 2014, the Company acquired a
group of companies that included geothermal water rights located at The Geysers
in Northern California that amounted to $278,872 (see note 16 for details).
On December 12, 2014, the Company completed an acquisition of
Earth Power Resources Inc. The acquisition included 26,017 acres of geothermal
water rights in located in the Crescent Valley area in the State of Nevada
valued at $451,608 on the acquisition date (see note 16 for details).
During the year ended December 31, 2014, the Company abandoned
the Granite Creek, Nevada area and released the geothermal water and mineral
rights originally purchased for $451,299.
Intangible assets, at cost, are summarized by project location
as follows:
|
|
December 31, |
|
|
|
2014 |
|
|
2013 |
|
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 |
|
(1,117,434) |
|
|
(935,749) |
|
|
|
4,333,123 |
|
|
4,514,808 |
|
Inactive: |
|
|
|
|
|
|
Raft
River, Idaho: |
|
|
|
|
|
|
Surface water rights |
|
146,343 |
|
|
146,343 |
|
Geothermal water and mineral rights |
|
1,251,540 |
|
|
1,251,540 |
|
|
|
|
|
|
|
|
Granite
Creek, Nevada: |
|
|
|
|
|
|
Geothermal water and mineral rights |
|
- |
|
|
451,299 |
|
|
|
|
|
|
|
|
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 (note 16) |
|
451,608 |
|
|
- |
|
|
|
|
|
|
|
|
The
Geysers, California: |
|
|
|
|
|
|
Geothermal water rights (note 16) |
|
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) |
|
|
|
11,084,391 |
|
|
10,805,210 |
|
|
|
|
|
|
|
|
|
$ |
15,417,514 |
|
$ |
15,320,018 |
|
Amortization expense was charged to plant operations for the
years ended December 31, 2014 and 2013 that amounted to $181,685 and $181,685;
respectively.
-F-16-
Estimated aggregate amortization expense for the next five
years is as follows:
|
|
Projected |
|
|
|
Amounts |
|
Years ending December 31,
|
|
|
|
2015 |
$ |
181,685 |
|
2016 |
|
181,685 |
|
2017 |
|
181,685 |
|
2018 |
|
181,685 |
|
2019 |
|
181,685 |
|
|
|
|
|
|
$ |
908,425 |
|
NOTE 7 INCOME TAXES
To produce the estimated income tax assets and liabilities,
several estimates are required than include: current and future federal and
State income tax rates, State apportionment factors, future earnings, the
Companys tax positions, financial elements/terms used for stock option
valuation, and availability of tax credits and other benefits. Federal and State
income tax law is constantly changing and is subject to inherent uncertainties
due different interpretations and tax positions. Although Management believes
that its estimates are reasonable, no assurance can be given that the final tax
outcome of these matters will not be different than that which is reflected in
our tax provisions. Ultimately, the actual tax benefits to be realized will be
based upon future taxable earnings levels, which are very difficult to
predict.
Income taxes are recorded based upon the liability method.
Under this approach, deferred income taxes are recorded to reflect the tax
consequences in future years of differences between the tax basis of assets and
liabilities and their financial reporting amounts at each year-end.
At December 31, 2014, the Company had net deferred tax assets
calculated at an expected rate, noted in the table below, of approximately
$12,102,000 (December 31, 2013 - $10,435,000). As of December 31, 2013, the
Company recognized the net deferred income tax asset to the extent of the impact
on current book earnings. Effective December 31, 2014, Company management
believes that historical, current and expected earnings are sufficient to meet
the more likely than not standard to enable the Company to recognize the net
deferred tax asset. As allowable under accounting standards, the Company elects
to fully remove the valuation allowance as of December 31, 2014.
The Companys significant temporary timing differences that
impact deferred income tax assets and liabilities are stock compensation and
book to tax depreciation. The recognition of employee stock compensation has
different rules that impact both the value and the timing of recognized
compensation costs. Typically, employee stock compensation costs are higher and
are recognized before compensation costs are allowable for income tax purposes.
The book value of the deferred stock compensation asset, related to stock
options, is reduced when the options are exercised, forfeited or expire.
Differences in book to tax depreciation costs, generally, result in a deferred
tax liability. Allowable depreciation expenses for income tax purposes utilize
shorter asset lives and are calculated using accelerated methods (i.e., MACRS).
Also, the Company has both earned and acquired NOLs available to offset current
and future earnings.
For financial reporting purposes the Company reports its
operations as fully consolidated entity; however, for tax purposes the entities
that have multiple ownership interests report their activities as separate
entities. Some portions of the tax differences created by the structure of the
reporting entities are limited to the consolidated Company as a whole. These
differences, calculated with the estimated income tax rate are summarized as
follows:
-F-17-
|
|
December 31, 2014 |
|
|
|
Consolidated |
|
|
Adjustments |
|
|
Net Available |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
|
Net operating loss carry forward
|
$ |
47,696,000 |
|
$ |
(17,096,000) |
|
$ |
30,600,000 |
|
Stock based
compensation |
|
1,518,000 |
|
|
- |
|
|
1,518,000 |
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
|
Depreciation and
amortization |
|
(44,940,000) |
|
|
23,129,000 |
|
|
(21,811,000) |
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset |
$ |
4,274,000 |
|
$ |
6,033,000 |
|
$ |
10,307,000 |
|
The significant components of the net deferred tax asset
calculated with the estimated effective income tax rate were as follows:
|
|
|
December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
Current deferred tax assets:
|
|
|
|
|
|
|
|
Net operating loss
carry forward |
$ |
1,730,000 |
|
$ |
- |
|
|
Stock based compensation |
|
73,000 |
|
|
28,000 |
|
|
|
|
|
|
|
|
|
|
Long-term deferred tax assets: |
|
|
|
|
|
|
|
Net operating loss carry forward |
|
30,623,000 |
|
|
28,478,000 |
|
|
Stock based
compensation |
|
1,445,000 |
|
|
1,089,000 |
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
Depreciation and amortization |
|
(1,397,000) |
|
|
(4,331,000) |
|
|
|
|
|
|
|
|
|
|
Long-term liabilities: |
|
|
|
|
|
|
|
Depreciation and amortization |
|
(20,414,000) |
|
|
(14,829,000) |
|
|
|
|
|
|
|
|
|
|
Net deferred income tax asset
|
|
12,060,000 |
|
|
10,435,000 |
|
|
|
|
|
|
|
|
|
|
Deferred tax asset recognized and utilized in
current period |
|
(1,753,000) |
|
|
(1,578,000) |
|
|
|
|
|
|
|
|
|
|
Deferred tax asset valuation allowance |
|
- |
|
|
(8,857,000) |
|
|
|
|
|
|
|
|
|
|
Net deferred tax asset |
$ |
10,307,000 |
|
$ |
- |
|
The current portion of the deferred tax asset is based upon an
estimate of the earnings for the year ended December 31, 2015.
When calculating the effective tax rate, the federal income tax
rate was used in addition to the applicable State income tax rates as deductible
for federal income taxes. At year end, the Company held interests in the States
of Idaho, Oregon, Nevada and California. The calculation of the average State
income tax rate was based upon State apportionment factors that included
operating revenues, payroll costs, and property costs. The Company, also, has
interests in the Republic of Guatemala; however, the income tax effect of these
interests were minimal for the years ended December 31, 2014 and 2013.
-F-18-
The Companys estimated effective income tax rate is as
follows:
|
|
|
For the Years Ended December 31, |
|
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
|
|
U.S. Federal statutory rate
|
|
34.0% |
|
|
34.0% |
|
|
Average State and foreign income tax, net of
federal tax effect |
|
3.7 |
|
|
4.2 |
|
|
Production tax credits |
|
- |
|
|
- |
|
|
Net
effective tax rate |
|
37.7% |
|
|
38.2% |
|
At December 31, 2014, the Company had net income tax operating
loss carry forwards of approximately $81,166,000 ($74,550,000 in December 31,
2013), which expire in the years 2023 through 2034. Approximately $76,837,000 of
the operating losses were generated by the Company; the residual were acquired.
On April 22, 2014, the Company purchased a group of companies (see note 16 for
details). Federal and applicable state net operating losses that totalled
approximately $30 million were included in the acquisition. These NOLs are
scheduled to expire in the years ending 2028 through 2033. The use of these net
operating losses is restricted by the Companys basis 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
$4,329,000 at December 31, 2014.
The net change in the deferred tax asset valuation allowance
account is detailed as follows:
|
|
For the Year Ended December 31, |
|
|
|
2014 |
|
|
2013 |
|
|
|
|
|
|
|
|
Change in net operating loss
|
$ |
5,588,000
|
|
$ |
16,258,000
|
|
Change in estimated effective tax rate |
|
(45,000) |
|
|
614,000 |
|
Net change in difference
between book and tax stock compensation costs |
|
407,000 |
|
|
251,000 |
|
Change in estimated deferred tax asset
recognized and utilized in current period |
|
(1,753,000) |
|
|
(1,578,000) |
|
Change in period book to
income tax depreciation |
|
(2,747,000) |
|
|
(17,518,000) |
|
Recognition of net operating loss |
|
(10,307,000) |
|
|
- |
|
|
|
|
|
|
|
|
Net change
in deferred tax valuation allowance |
$ |
(8,857,000) |
|
$ |
(1,973,000) |
|
At December 31, 2014, Raft River Energy I LLC has a book-to-tax
difference of $38.7 million due to the acceleration of intangible drilling costs
and depreciation. By contract, 99% percent of this book-to-tax difference has
been allocated to the non-controlling interest and would not be available to the
consolidated group to offset future tax liabilities. At December 31, 2014, USG
Oregon LLC has a book-to-tax difference of $57.5 million due to the acceleration
of depreciation.
Accounting for Income Tax Uncertainties and Related
Matters
The Company may be assessed penalties and interest
related to the underpayment of income taxes. Such assessments would be treated
as a provision of income tax expense on the financial statements. For the years
ended December 31, 2014 and 2013, and the nine months ended December 31, 2012,
no income tax expense has been realized as a result of operations and no income
tax penalties and interest have been accrued related to uncertain tax positions.
The Company files income tax returns in the U.S. federal jurisdiction and in the
States of Idaho, California and Oregon. These filings are subject to a three
year statute of limitations. The Companys evaluation of income tax positions
included the year ended December 31, 2014 and 2013, and the nine months ended
December 31, 2012. No filings are currently under examination. No adjustments
due to tax uncertainties have been made to reduce the estimated income tax
benefit at year end. Any valuations relating to these income tax provisions will
comply with U.S. Generally Accepted Accounting Principles.
-F-19-
NOTE 8 - CAPITAL LEASE OBLIGATIONS
Effective May 10, 2012, the Company entered into two capital
lease obligations for the purchase of a boom lift and a telehandler from
Caterpillar Financial Services Corporation. The boom lift contract is payable in
36 monthly payments of $1,094 that began on June 11, 2012 and has an effective
annual interest rate of 5.985% . The telehandler contract is payable in 36
monthly payments of $3,155 that began on June 11, 2012 and has an effective
annual interest rate of 6.14% . Both contracts with Caterpillar Financial
Services Corporation have bargain purchase options at the end of the contracts
scheduled for May 2015. The scheduled future lease payments for the two
contracts for the year ended December 31, 2015 total $21,249. At December 31,
2014, all of the lease obligations of $20,921 (less imputed interest of $328)
were current. At December 31, 2014, the net book value of the equipment under
capital lease amounted to $34,755 ($155,000, less $120,245 accumulated
amortization).
NOTE 9 NOTES PAYABLE
U.S. Department of Energy
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). The U.S. Treasurys Federal
Financing Bank, as lender for the Project, issues payments direct to vendors.
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 be 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.
The loan advances began August 31, 2011 and the last advance was taken on July
31, 2013. 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. On August 12, 2013, proceeds of the ITC cash grant were
distributed in accordance with the loan agreement, with $11,870,137 of the
proceeds being used to prepay the Project loan, $11,167,473 of proceeds being
used to fund a series of Project reserves, and balance of $9,711,930 being
distributed as equity to the project owners. After the loan prepayment, the
remaining final loan balance was $70,386,576. The loan principal is scheduled to
be paid over 21.5 years 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 are scheduled to start at $1,709,963 and are expected to be
reduced to $1,626,251 on February 10, 2017. The loan balance at December 31,
2014 totaled $66,974,610 (estimated current portion $3,419,927).
-F-20-
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, 2014 |
|
|
(16,083,355) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loan balance at December 31, 2014 |
|
$ |
66,974,610 |
|
|
|
|
* - Individual tranches have been
fully extinguished.
SAIC Constructors LLC
Effective August 27,
2010, the Companys wholly owned subsidiary (USG Nevada LLC) signed a
construction loan agreement with SAIC Constructors LLC (SAIC). The new 10.0
net megawatt power plant was considered complete and operational for financial
reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC
signed a settlement agreement with SAIC that defined the terms of three separate
debt components to settle the obligations incurred under the construction loan
agreement. As of December 31, 2013, two components of the settlement agreement
were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada
USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary
of the Company), that further defined the terms of the remaining debt component
of $2 million. This remaining obligation will be repaid in quarterly
installments of $119,382, including interest at 7.0% per annum that began on
July 31, 2013 and is scheduled to be repaid by September 2018. The loan balance
at December 31, 2014 totaled $1,487,266 (estimated current portion
$390,051).
Prudential Capital Group
On September 26,
2013, the Companys wholly owned subsidiary (USG Nevada LLC) entered into a note
purchase agreement with the Prudential Capital Groups related entities
(Prudential) 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. All amounts owing under the notes and the note purchase agreement or any related
financing document are secured by USG Nevada LLCs 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, 2014, the balance of the
loan was $30,182,333 (estimated current portion $471,091).
Auto Loans
On August 21, 2014, the Companys
wholly owned subsidiaries (U.S. Geothermal Services, LLC, USG Nevada LLC and
Raft River Energy I, Inc.) purchased three trucks with down payments that
totaled $47,000 and three separate loan agreements with Chrysler Capital. The
loans require total monthly payments of $1,257, including interest at an average
rate of 7.9% per annum until September 2020. The notes are secured by the
vehicles. At December 31, 2014, the loan balances totaled $68,412 (estimated
current portion $9,919).
-F-21-
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 |
|
2015 |
|
$ |
4,336,271
|
|
2016 |
|
|
4,422,738 |
|
2017 |
|
|
4,344,834 |
|
2018 |
|
|
4,093,067 |
|
2019 |
|
|
3,962,127 |
|
Thereafter |
|
|
77,553,585 |
|
|
|
|
|
|
|
|
$ |
98,712,622 |
|
NOTE 10 - CAPITAL STOCK
The Company is authorized to issue 250,000,000 shares of common
stock. All shares have equal voting rights, are non-assessable and have one vote
per share. Voting rights are not cumulative and, therefore, the holders of more
than 50% of the common stock could, if they choose to do so, elect all of the
directors of the Company.
On December 12, 2014, the Company issued 692,769 shares of
common stock to the shareholders of acquired company (Earth Power Resources Inc.
EPR). Under the terms of the Acquisition agreement, 50% of the issued shares
will be held in reserve by the Company to cover potential undisclosed
liabilities against EPR. The remaining non-reserved shares will be delivered to
EPR shareholders upon surrender of their EPR share certificates. Trading of the
non-reserve shares will be restricted for six months under SEC Rule 144. See
note 16 for acquisition details.
On September 3, 2014, the Company issued 2,459,460 shares of
common stock to an investor exercising stock purchase warrants at a price of
$0.50 per share.
On April 2, 2014, the Company issued 559,122 shares of common
stock (restricted shares) at a price of $0.74 per share to employees. The shares
vest on April 2, 2015 and will be priced (currently $0.46 a share) at the date
of vesting.
During the quarter ended June 30, 2014, the Company issued
352,500 shares of common stock as a result of employees and former employees
exercising stock options priced at $0.31 per share.
During the quarter ended March 31, 2014, the Company issued
724,500 shares of common stock as a result of employees and former employees
exercising stock options priced between $0.31 and $0.46 per share.
On March 14, 2014, the Company issued 135,136 shares of common
stock to an investor exercising stock purchase warrants at a price of $0.50 per
share.
During the year ended December 31, 2013, the Company issued
577,778 shares of common stock (300,000 restricted shares) to an employee of the
Company at prices between $0.35 and $0.36 per share under the terms of an
employment agreement.
-F-22-
NOTE 11 - 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, 2014,
the Company can issue stock option grants totaling up to 16,052,704 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. At December 31, 2014, the
Company had 11,808,500 options granted and outstanding.
During the quarter ended December 31, 2014, 40,000 stock
options exercisable at the price of $0.74 issued to an employee were forfeited
due to termination of employment.
On September 23, 2014, 68,000 stock options exercisable at a
price of $1.58 expired without exercise.
During the quarter ended September 30, 2014, 50,000 stock
options exercisable at the price of $0.83 issued to a contractor were forfeited
due to the termination of their contract.
On April 2, 2014, the Company awarded 2,883,500 stock options
at an exercise price of $0.74 expiring on April 2, 2019 to its employees and
directors.
During the quarter ended June 30, 2014, 352,500 stock options
exercisable at the price of $0.31 were exercised by employees and former
employees.
On May 26, 2014, 1,698,250 stock options exercisable at a price
of $0.92 expired without exercise.
During the quarter ended March 31, 2014, 724,500 stock options
exercisable at prices between $0.31 and $0.46 were exercised by employees and
former employees.
On February 22, 2014, 30,000 stock options exercisable at a
price of $0.46 issued to employees were forfeited due to the termination of
employment.
On September 25, 2013, 95,000 stock options exercisable at a
price of $1.78 expired without exercise.
On September 1, 2013, the Company granted 15,000 stock options
to an employee exercisable at a price of $0.41 until September 1, 2018.
On July 22, 2013, the Company granted 1,950,000 stock options
to employees exercisable at a price of $0.46 until July 22, 2018.
On May 26, 2013, 6,375 stock options exercisable at a price of
$0.92 were forfeited due to employee termination.
On May 19, 2013, 1,465,000 stock options exercisable at a price
of $2.22 expired without exercise.
On April 19, 2013, the Company granted 1,250,000 stock options
to employees exercisable at a price of $0.35 until April 19, 2023.
-F-23-
The following table reflects the summary of stock options
outstanding at December 31, 2012 and changes for the years ended December 31,
2013 and 2014:
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Weighted |
|
|
|
|
|
|
Number of |
|
|
Exercise |
|
|
Average |
|
|
Aggregate |
|
|
|
shares under |
|
|
Price Per |
|
|
Fair |
|
|
Intrinsic |
|
|
|
options |
|
|
Share |
|
|
Value |
|
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance outstanding, December
31, 2012 |
|
10,239,625 |
|
$ |
0.91 |
|
$ |
0.55 |
|
$ |
5,606,309
|
|
Forfeited/Expired |
|
(1,566,375) |
|
|
2.18 |
|
|
1.20 |
|
|
(1,872,094) |
|
Exercised
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Granted |
|
3,215,000 |
|
|
0.42 |
|
|
0.25 |
|
|
808,500 |
|
Balance outstanding, December
31, 2013 |
|
11,888,250 |
|
|
0.61 |
|
|
0.38 |
|
|
4,542,715 |
|
Forfeited/Expired |
|
(1,886,250) |
|
|
0.53 |
|
|
0.26 |
|
|
(1,251,738) |
|
Exercised
|
|
(1,077,000) |
|
|
0.32 |
|
|
0.16 |
|
|
(171,134) |
|
Granted |
|
2,883,500 |
|
|
0.74 |
|
|
0.40 |
|
|
1,153,400 |
|
Balance outstanding, December
31, 2014 |
|
11,808,500 |
|
$ |
0.62 |
|
$ |
0.36 |
|
$ |
4,273,243 |
|
The fair value of each option award is estimated on the date of
grant using the Black-Scholes option-pricing model using the assumptions noted
in the following table. Expected volatilities are based on historical volatility
of the Companys stock. The Company uses historical data to estimate option
volatility within the Black-Scholes model. The expected term of options granted
represents the period of time that options granted are expected to be
outstanding, based upon past experience and future estimates and includes data
from the Plan. The risk-free rate for periods within the expected term of the
option is based upon the U.S. Treasury yield curve in effect at the time of
grant. The Company currently does not foresee the payment of dividends in the
near term.
The fair value of the stock options granted was estimated using
the Black-Scholes 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, |
|
|
|
|
2014 |
|
|
2013 |
|
|
Dividend yield |
|
0 |
|
|
0 |
|
|
Expected volatility |
|
81-100% |
|
|
71-81% |
|
|
Risk free interest rate |
|
0.69-0.82% |
|
|
0.27-0.82% |
|
|
Expected life (years) |
|
2.94 |
|
|
4.63 |
|
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 Companys stock
options.
-F-24-
The following table summarizes information about the stock
options outstanding at December 31, 2014:
|
OPTIONS OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAINING |
|
|
NUMBER OF |
|
|
|
|
|
EXERCISE |
|
|
NUMBER OF |
|
|
CONTRACTUAL |
|
|
OPTIONS |
|
|
|
|
|
PRICE |
|
|
OPTIONS |
|
|
LIFE (YEARS) |
|
|
EXERCISABLE |
|
|
INTRINSIC VALUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.86 |
|
|
1,300,000 |
|
|
0.70 |
|
|
1,300,000 |
|
$ |
752,207
|
|
|
0.83 |
|
|
2,540,000 |
|
|
1.43 |
|
|
2,540,000 |
|
|
1,244,600 |
|
|
0.60 |
|
|
100,000 |
|
|
1.70 |
|
|
100,000 |
|
|
36,072 |
|
|
0.31 |
|
|
1,865,000 |
|
|
2.65 |
|
|
1,865,000 |
|
|
290,128 |
|
|
0.46 |
|
|
1,895,000 |
|
|
3.56 |
|
|
1,421,250 |
|
|
345,222 |
|
|
0.41 |
|
|
15,000 |
|
|
3.67 |
|
|
11,250 |
|
|
2,259 |
|
|
0.35 |
|
|
1,250,000 |
|
|
8.30 |
|
|
1,250,000 |
|
|
338,000 |
|
|
0.74 |
|
|
2,843,500 |
|
|
4.25 |
|
|
1,421,750 |
|
|
574,464 |
|
$ |
0.62 |
|
|
11,808,500 |
|
|
3.52 |
|
|
9,909,250 |
|
$ |
3,582,952 |
|
The following table summarizes information about the stock
options outstanding at December 31, 2013:
|
OPTIONS OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAINING |
|
|
NUMBER OF |
|
|
|
|
|
EXERCISE |
|
|
NUMBER OF |
|
|
CONTRACTUAL |
|
|
OPTIONS |
|
|
|
|
|
PRICE |
|
|
OPTIONS |
|
|
LIFE (YEARS) |
|
|
EXERCISABLE |
|
|
INTRINSIC VALUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
0.92 |
|
|
1,698,250 |
|
|
0.40 |
|
|
1,698,250 |
|
$ |
1,200,208
|
|
|
1.58 |
|
|
68,000 |
|
|
0.73 |
|
|
68,000 |
|
|
26,435 |
|
|
0.86 |
|
|
1,300,000 |
|
|
1.70 |
|
|
1,300,000 |
|
|
752,207 |
|
|
0.83 |
|
|
2,590,000 |
|
|
2.43 |
|
|
2,590,000 |
|
|
1,269,100 |
|
|
0.60 |
|
|
100,000 |
|
|
2.70 |
|
|
100,000 |
|
|
36,072 |
|
|
0.31 |
|
|
2,917,000 |
|
|
3.65 |
|
|
2,187,750 |
|
|
340,332 |
|
|
0.46 |
|
|
1,950,000 |
|
|
4.56 |
|
|
487,500 |
|
|
118,414 |
|
|
0.41 |
|
|
15,000 |
|
|
4.67 |
|
|
3,750 |
|
|
753 |
|
|
0.35 |
|
|
1,250,000 |
|
|
9.30 |
|
|
625,000 |
|
|
169,000 |
|
$ |
0.61 |
|
|
11,888,250 |
|
|
3.43 |
|
|
9,060,250 |
|
$ |
3,912,521 |
|
-F-25-
A summary of the status of the Companys nonvested stock
options outstanding at December 31, 2012 and changes during the years ended
December 31, 2013 and 2014 are presented as follows:
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
|
Average Grant |
|
|
Average |
|
|
|
|
Number of |
|
|
Date Fair Value |
|
|
Grant Date |
|
|
|
|
Options |
|
|
Per Share |
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested, December 31, 2012
|
|
2,212,750 |
|
$ |
0.31 |
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
3,215,000 |
|
|
0.42 |
|
|
0.25 |
|
|
Vested
|
|
(2,599,750) |
|
|
0.35 |
|
|
0.23 |
|
|
Forfeited/Expired |
|
- |
|
|
- |
|
|
- |
|
|
Nonvested, December 31, 2013
|
|
2,828,000 |
|
|
0.39 |
|
|
0.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
2,132,625 |
|
|
0.74 |
|
|
0.40 |
|
|
Vested
|
|
(3,031,375) |
|
|
0.38 |
|
|
0.19 |
|
|
Forfeited/Expired |
|
(30,000) |
|
|
0.46 |
|
|
0.24 |
|
|
Nonvested, December 31, 2014
|
|
1,899,250 |
|
$ |
0.65 |
|
$ |
0.36 |
|
As of December 31, 2014, there was $433,322 of total
unrecognized compensation cost related to nonvested share-based compensation
arrangements granted under the Plan. That cost is expected to be recognized over
a weighted-average period of 1.5 years. The total fair value of options vested
at December 31, 2014 and December 31, 2013 was $1,115,391 and $683,143,
respectively.
Stock Compensation Plan (Restricted Shares)
On April 19, 2013, the Company granted an officer and director
300,000 common shares valued at $0.35 per share, which were distributed at the
end of a one-year vesting period. The recipient meets 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. These shares
were issued in July 2013 to the recipient and held by the Company until vested.
The total fair value of options at the grant date was $105,000 and the
recognized cost through December 31, 2014 was $31,208.
On April 2, 2014, the Company issued 559,122 shares of Company
stock at a price of $0.46 that fully vest on April 2, 2015 to its employees and
directors. The total estimated fair value is $257,196 and the recognized cost
through December 31, 2014 was $192,897.
Stock Purchase Warrants
At December 31, 2014, the outstanding broker warrants and share
purchase warrants consisted of the following:
|
|
|
|
|
|
|
Broker |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Warrant |
|
|
Share |
|
|
Warrant |
|
|
|
|
|
Broker |
|
|
Exercise |
|
|
Purchase |
|
|
Exercise |
|
|
Expiration Date |
|
|
Warrants |
|
|
Price |
|
|
Warrants |
|
|
Price |
|
|
September 16, 2015 |
|
|
246,285 |
|
$ |
1.25 |
|
|
4,104,757 |
|
$ |
1.25 |
|
|
May 23, 2017 |
|
|
255,721 |
|
|
0.44 |
|
|
- |
|
|
- |
|
|
December 21, 2017 |
|
|
- |
|
|
- |
|
|
3,310,812 |
|
|
0.50 |
|
On September 3, 2014, share purchase warrants that totaled
2,459,460 were exercised by an investor at the warrant exercise price of
$0.50.
-F-26-
On March 14, 2014, 135,136 share purchase warrants were
exercised by an investor at the warrant exercise price of $0.50.
On February 2013, 500,000 stock purchase warrants at an
exercise price of $5.00 expired without exercise.
NOTE 12 FAIR VALUE MEASUREMENT
Current 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. Active markets are those in which transactions
for the asset or liability occur with sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 Pricing inputs are other than quoted prices in active
markets included in Level 1, which are either directly or indirectly observable
as of the reporting date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These models are primarily
industry-standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors, and current
market and contractual prices for the underlying instruments, as well as other
relevant economic measures. Substantially all of these assumptions are
observable in the marketplace throughout the full term of the instrument, can be
derived from observable data or are supported by observable levels at which
transactions are executed in the marketplace.
Level 3 Pricing inputs include significant inputs that are
generally unobservable from objective sources. These inputs may be used with
internally developed methodologies that result in managements best estimate of
fair value. Level 3 instruments include those that may be more structured or
otherwise tailored to the Companys needs.
Financial assets and liabilities are classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. The Companys assessment of the significance of a particular
input to the fair value measurement requires judgment, and may affect the
valuation of fair value assets and liabilities and their placement within the
fair value hierarchy levels.
The following table discloses by level within the fair value
hierarchy the Companys assets and liabilities measured and reported on its
Consolidated Balance Sheet as of December 31, 2014 at fair value on a recurring
basis:
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market accounts * |
$ |
30,515,067 |
|
$ |
30,515,067 |
|
$ |
- |
|
$ |
- |
|
* - Money market accounts include
both restricted and unrestricted funds.
As allowed by current financial reporting standards, the
Company has elected not to implement fair value recognition and reporting for
all non-financial assets and non-financial liabilities, except for those that
are recognized or disclosed at fair value in the financial statements on a
recurring basis, that is, at least annually.
-F-27-
NOTE 13 - RELATED PARTY TRANSACTIONS
At December 31, 2014 and 2013 the amounts of $5,195 and $3,089;
respectively, were payable to the officers of the Company for routine expense
reimbursement. These amounts are unsecured and due on demand.
The Company paid directors fees for the years ended December
31, 2014 and 2013 totalled $115,300 and $99,000; respectively.
NOTE 14 - COMMITMENTS AND CONTINGENCIES
Operating Lease Agreements
The Company has entered into several lease agreements with
terms expiring up to December 1, 2034 for geothermal properties in Neal Hot
Springs, Oregon; Washoe County, Nevada; Eureka County, Nevada; The Geysers,
California; Raft River, Idaho and the Republic of Guatemala. The Company
incurred total lease expenses for the years ended December 31, 2014 and 2013, of
$579,815 and $286,923; respectively. The Company believes that it is in
compliance with all of the following lease terms.
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.
Gerlach
The Gerlach Geothermal LLC assets are
comprised of two BLM geothermal leases and one private lease totaling 3,615
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.
Granite Creek
The Company has three geothermal lease
contracts with the BLM for the Granite Creek properties. The lease contracts are
for approximately 2,443.7 acres of land and geothermal water rights located in
North Western Nevada. The lease contracts have primary terms of 10 years. Per
federal regulations applicable for the contracts, the lessee has the option to
extend the primary lease term another 40 years if the BLM does not need the land
for any other purpose and the lessee is maintaining production at commercial
quantities. The leases state annual lease payments of $2,444, not including
processing fees, and expire October 2017. During the quarter ended December 31,
2014, management terminated the Granite Creek project and will relinquish its
lease contracts and the accompanying rights to the area. The carrying value of
the contracts of $451,299 has been eliminated from the financial statements.
-F-28-
Raft River Energy I LLC
The Company has entered into
several lease contracts for approximately 1,298 acres of land and geothermal
water rights located in the Raft River area located in Southern Idaho. The
contracts have stated terms that range from 5 to 30 years with expiration dates
that range from May 2015 to December 2034. The annual contracted lease payments
are scheduled to total $44,450 for the year ended December 31, 2015.
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.
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). The annual contracted lease payments are scheduled to total $274,000
for the year ended December 31, 2015.
Crescent Valley, Nevada
On December 12, 2014, the
Company acquired Earth Power Resources Inc. that holds 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. The annual contracted lease payments are
scheduled to total $70,898 for the year ended December 31, 2015.
Office Lease
Park Center Boulevard
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 year ended
December 31, 2014, the office lease costs totaled $115,830.
Tyrell Lane
Under the contract, the lease payments
were due in monthly installments of $6,535. The contract ended January 31, 2014.
The total office lease costs incurred under the contract and the prior contract
for year ended December 31, 2013 totaled $78,423.
-F-29-
Contracted Lease Obligation Schedule
The following is the total contracted lease operating
obligations (operating leases, BLM lease agreements and office leases) for the
next five years:
Year Ending |
|
|
|
|
December 31, |
|
|
Amount |
|
|
|
|
|
|
2015 |
|
$ |
899,579
|
|
2016 |
|
|
930,463 |
|
2017 |
|
|
900,124 |
|
2018 |
|
|
865,753 |
|
2019 |
|
|
742,547 |
|
Thereafter |
|
|
13,273,471 |
|
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 Companys 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.
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, 2014, the Company has
funded a security deposit of $1,468,898.
USG Oregon LLC
In December of 2009, the Companys
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. The approximate 25-year levelized price is $117.65 per megawatt
hour.
-F-30-
Asset Retirement Obligations (AROs)
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 $800,000. Obligations related to
decommissioning four existing wells were estimated to total $600,000. These
obligations are based upon the expected future value of the remedy or settlement
and the values have not been calculated at discounted rates. At December 31,
2014, the Company has not considered it necessary to specifically fund these
obligations. Since management is still evaluating the development plan for this
project that could eliminate or significantly reduce these obligations, no
charges directly associated the asset retirement obligations have been charged
to operations. All of the obligations are considered to be long-term at December
31, 2014.
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 or not significantly more
than the assets estimated salvage values. Therefore, as of December 31, 2014,
no retirement obligations have been recognized.
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. Subsequent to June 30,
2013, the Company began matching 50% of the employees contribution up to 6%.
Prior to June 30, 2013, the plan required the Company to match 25% of the
employees 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 $97,785 and $60,425 for the years ended December 31, 2014
and 2013, respectively.
NOTE 15 JOINT VENTURES/NON-CONTROLLING INTERESTS
Non-controlling interests included on the consolidated balance
sheets of the Company are detailed as follows:
|
|
December 31, |
|
|
|
2014
|
|
|
2013
|
|
|
|
|
|
|
|
|
Gerlach Geothermal LLC interest held by
Gerlach Green Energy, LLC |
$ |
230,539 |
|
$ |
404,352 |
|
Oregon USG Holdings LLC interest held by Enbridge Inc. |
|
24,818,443 |
|
|
35,926,826 |
|
Raft River Energy I LLC interest held by
Raft River I Holdings, LLC |
|
21,348,110 |
|
|
21,824,302 |
|
|
$ |
46,397,092 |
|
$ |
58,155,480 |
|
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 owns a 60% interest and GGE owns 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 first three quarters of the current year, contributions were
made to Gerlach by the Company and GGE that totaled $11,040 and $7,360;
respectively. These contributions maintained the existing ownership interests of
the two partners in Gerlach. During the fourth quarter of the current year, the
Company contributed $400,000 for the projects drilling costs that were not
proportionally matched by GGE. These contributions effectively reduced GGEs
ownership interest to 32.65%, and increased the Companys interest to 67.35% as
of December 31, 2014.
-F-31-
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 Gerlachs operations are reflected in the
statement of operations with the elimination of the non-controlling interest
identified.
Oregon USG Holdings LLC
In September
2010, the Companys subsidiary, Oregon USG Holdings LLC (Oregon Holdings),
signed an Operating Agreement with Enbridge Inc. (Enbridge) for the right to
participate in the Companys 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 Companys 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 year ended December 31, 2014,
distributions were made to the Company and Enbridge that totaled $12,388,606 and
$15,024,334; respectively.
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 LLCs operations are reflected in the statement of
operations 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 Raft River I Holdings, LLC a
subsidiary of the Goldman Sachs Group, Inc. An Operating Agreement governs the
rights and responsibilities of both parties. At fiscal year end, the Company had
contributed approximately $17.9 million in cash and property, and RREI has
contributed approximately $34.1 million in cash. Profits and losses are
allocated to the members based upon contractual terms. For income tax purposes,
Raft River I Holdings, LLC receives a greater proportion of the share of losses
and other income tax benefits. This includes the allocation of production tax
credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to
the Company during the first 10 years of production. During the initial years of
operations, Raft River I Holdings, LLC will receive a larger allocation of cash
distributions.
The consolidated financial statements reflect 100% of the
assets and liabilities of RREI, and report the current non-controlling interest
of Raft River I Holdings LLC. The full results of Raft River Energy I LLCs
operations are reflected in the statement of operations with the elimination of
the non-controlling interest identified.
Effective May 17, 2011, a repair services agreement (RSA) was
executed between RREI and U.S. Geothermal Services, LLC for the purpose of
funding repairs of two underperforming wells. The agreement defined terms of the
RSA repair costs and RSA repair management fees that would be funded by the
loan. The outstanding loan balance will accrue interest at 12.0% per annum. The
RSA payments will be made preferentially from project cash flow at a rate of 90%
of increased cash created by the repairs and cash availability on a quarterly
basis. The repairs were completed in January 2012. Based upon the financial
conditions applicable to the loan, RREI did not make any payments during the
year ended December 31, 2012. As of December 31, 2012, the loan balance amounted
to $2,136,150. During the years ended December 31, 2014 and 2013, RREI made
principal payments on the loan of $1,003,833 and $755,288; respectively. The
balance of the loan at December 31, 2014 and 2013 was $377,029 and $1,380,862;
respectively. The loan balance and related interest effects are fully eliminated
during the consolidation process.
-F-32-
NOTE 16 ACQUISITIONS
Ram Powers Geysers Project
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 hold all interests in the
Geysers Project located in Northern California for a total of $6.78 million
($6.4 million purchase price, plus $0.38 million in other acquisition costs).
The acquisition included Rams subsidiaries: Western GeoPower, Inc., Skyline
Geothermal Holdings, Inc., and Etoile Holdings, Inc. which includes all
membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The
assets acquired included 4 production/injection wells, restricted cash, land and
geothermal water rights. The Company assumed the on-going liabilities of the
companies which included an asset retirement obligations with estimated value of
$1.4 million. The Company will evaluate whether to construct a power plant or
sell the steam to one of the existing power companies in the area. The total
acquisition cost was allocated as follows:
|
|
|
Acquisition Costs |
|
|
Assets: |
|
|
|
|
Restricted cash, short
term well bond |
$ |
100,000 |
|
|
Land |
|
1,603,516 |
|
|
Geothermal water rights
|
|
278,872 |
|
|
Construction in progress: |
|
|
|
|
Wells
and casing |
|
6,139,420 |
|
|
Plant and facilities |
|
60,637 |
|
|
|
|
8,182,445 |
|
|
Liabilities: |
|
|
|
|
Asset retirement
obligations |
|
(1,400,000) |
|
|
Net acquisition cost |
$ |
6,782,445 |
|
Earth Power Resources Inc. (EPR)
On October
16, 2014, the Company signed an Agreement and Plan of Merger with EPR. The
transaction was approved by EPR shareholder approval on November 18, 2014. The
Acquisition was completed on December 12, 2014. Under the terms of the
Agreement, the EPR shareholders received a total of 692,769 shares of U.S.
Geothermal Inc. common shares and $42,934 in cash in exchange for all
outstanding shares of EPR stock. Under the terms of the Acquisition agreement,
50% of the issued shares will be held in reserve by the Company to cover
potential undisclosed liabilities against EPR. The remaining non-reserved shares
will be delivered to EPR shareholders upon surrender of their EPR share
certificates. Trading of the non-reserve shares will be restricted for 6 months
under SEC Rule 144. Acquired assets include geothermal leases covering 26,017
acres in the State of Nevada representing three potential projects. A loan of
$100,000 was made from the Company to EPR to fund operating costs that were due
prior to the acquisition. The loan accrues interest at a rate of 7.0% per annum
and is due on December 11, 2019.
-F-33-
The total acquisition cost was allocated as follows:
|
|
|
Acquisition Costs |
|
|
Assets: |
|
|
|
|
Restricted cash, bond |
$ |
10,000 |
|
|
Geothermal water rights |
|
451,608 |
|
|
|
|
461,608 |
|
|
Liability: |
|
|
|
|
Note payable,
intercompany |
|
(100,000) |
|
|
Net acquisition cost |
$ |
361,608 |
|
NOTE 17 - SUBSEQUENT EVENTS
The Company has evaluated events and transactions that have
occurred after the balance sheet date through March 16, 2015, which is
considered to be the issuance date. No events were identified for disclosure.
-F-34-
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 Companys management, with the
participation of the Chief Executive Officer and the Chief Financial Officer, of
the effectiveness of the Companys disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act 1934 as of
December 31, 2014. 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, 2014.
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
The Companys 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 Companys principal executive and principal financial
officers, or persons performing similar functions, and effected by the Companys
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 Companys internal control over financial
reporting includes those policies and procedures that:
- pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets
of the Company;
- provide reasonable assurance that transactions are recorded as necessary
to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the
Company are being made only in accordance with authorizations of management
and directors of the Company; and
- provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the Companys assets that
could have a material effect on the financial statements.
-93-
The Companys management assessed the effectiveness of the
Companys internal control over financial reporting as of December 31, 2014. 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, 2014, the Companys internal control over
financial reporting is effective based on those criteria.
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, 2014, that materially affected, or are reasonably likely to
materially affect, the Companys internal control over financial reporting.
Item 9B. Other Information
None.
-94-
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 five directors: Dennis J. Gilles, Douglas J. Glaspey, Paul
A. Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up
of Mr. Larkin, Dr. Mink 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 56, serves as the Chief
Executive Officer and a director of the Company. 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. As Senior Vice President of
Calpine Corporation, Mr. Gilles managed the Companys 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 30 years of experience in
the natural resource industry and his many years of senior management and
director experience.
Douglas J. Glaspey: Age 62, 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 35 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. Glaspeys qualifications to serve as a director of
the Company include his over 35 years of experience in the natural resource
industry and his many years of senior management and director experience.
-95-
Kerry D. Hawkley: Age 61, serves as the Chief
Financial Officer and Corporate Secretary of the Company. He has served as the
Companys 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 35 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.
Paul Larkin: Age 64, 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., and Westbridge Energy Corp. Mr. Larkins
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.
Dr. Leland Roy Mink: Age 74,
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.
John H. Walker: Age 66, 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 an 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.
Walkers qualifications to serve as a director of the Company include his many
years of senior leadership and management experience in international business
development.
-96-
Jonathan Zurkoff: Age 59, 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, 2014 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.
-97-
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, 2014. 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 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 managements most significant compensation
opportunities.
The three primary components of total direct compensation for
our senior executives are:
-98-
- annual cash incentive bonus opportunity; and
- stock options and restricted stock.
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 Boards 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 Companys
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 Nevada
Geothermal Power, Ram Power, 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.
-99-
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, 2014,
stock option grants to executive officers represented approximately 52% of the
total stock option grants to all employees. During the year ended December 31,
2014, stock option grants to executive officers represented approximately 25% 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.
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 Companys 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.
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 Companys common stock and cash to cover the tax
impact of the stock bonus. Mr. Gilles was also granted 300,000 restricted shares
of the Companys common stock, and a non-qualified stock option to acquire a
total of 1,250,000 shares of the Companys common stock at a price of $0.35 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
Companys 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 Companys 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 Companys board of directors and its
Compensation and Benefits Committee. On April 18, 2014, Mr. Gilles was granted
400,000 stock options to acquire shares of the Companys common stock at an
exercise price of $0.74, a cash bonus of $150,000 and 325,000 shares of
restricted stock 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 Companys board of
directors. Mr. Gilles and his immediate family will be eligible to participate
in the Companys 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 will be 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 Companys office in Boise, Idaho and his home. In addition,
Mr. Gilles has received cost reimbursement for a single relocation for costs of
$34,260.
-100-
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 Companys common
stock and any unvested restricted shares of the Companys 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 Companys contribution to the monthly cost of the medical and dental
benefits provided to Mr. Gilles under the employment agreement.
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 Companys common stock and
any unvested restricted shares of the Companys 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 Companys contribution to the
monthly cost of the medical and dental benefits provided to Mr. Gilles under the
employment agreement.
-101-
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 Companys 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
$220,000 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
Companys 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. Glaspeys 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.
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 months
written notice and Mr. Glaspey may terminate the employment agreement upon 60
days written notice.
In the event that Mr. Glaspeys 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 $439,992). The terms cause,
good reason and change of control are defined in the employment agreement.
-102-
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 Companys 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
$175,000 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
Companys 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. This salary may be
adjusted annually on the anniversary date of the employment agreement and is
currently $179,375 per annum. 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 months
written notice and Mr. Hawkley may terminate the employment agreement upon 60
days written notice.
In the event that Mr. Hawkleys 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 $262,440). The terms cause,
good reason and change of control are defined in the employment agreement.
-103-
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 Companys Executive Vice President,
Finance. The employment agreement, as twice amended, is effective December 31,
2010, and will remain in effect until March 31, 2015 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 $192,000 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 months
written notice.
In the event that Mr. Zurkoffs 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 $288,000). The terms cause,
good reason and change of control are defined in the employment agreement.
-104-
The employment agreement also includes covenants by Mr. Zurkoff
with respect to the treatment of confidential information and non-competition,
and provides for equitable relief in the event of breach.
Summary Compensation Table
The following table shows the compensation for the last two
years awarded to or earned by our Chief Executive Officer and each of our three
other most highly compensated executive officers (collectively, our Named
Executive Officers).
Name and principal position(s) |
Year
Ended |
Salary
(1) ($) |
Bonus
(2) ($) |
Option
Awards (3) ($) |
All other
compensation (4) ($) |
Total
($) |
|
Dennis J. Gilles, Chief Executive Officer
(effective 4/19/13) |
12/31/13 |
261,250 |
142,811 |
442,978 |
34,303 |
881,342 |
12/31/14 |
399,500 |
150,000 |
167,378 |
108,406 |
825,284 |
|
Daniel J. Kunz, Former Chief Executive Officer
(retired effective 4/19/13) |
12/31/13 |
94,726 |
0 |
0 |
0 |
94,726 |
12/31/14 |
0 |
0 |
0 |
0 |
0 |
|
Douglas J. Glaspey, President and Chief Operating
Officer |
12/31/13 |
215,000 |
10,000 |
39,245 |
1,035 |
262,280 |
12/31/14 |
220,000 |
22,000 |
92,058 |
1,035 |
335,093 |
|
Kerry D. Hawkley, Chief Financial Officer |
12/31/13 |
163,000 |
10,000 |
32,704 |
0 |
205,704 |
12/31/14
|
178,282
|
17,500
|
73,228
|
0
|
269,010 |
Jonathan Zurkoff, Treasurer and Executive Vice
President |
|
|
|
|
|
|
12/31/13 |
192,000 |
27,000 |
30,364 |
0 |
249,364 |
12/31/14 |
192,000 |
20,000 |
69,729 |
0 |
281,729 |
(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 and restricted stock are valued at the
grant date in accordance with FASB ASC Topic 718. |
|
|
(4) |
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, 2014 by our Named Executive Officers.
-105-
|
|
|
|
|
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 |
|
|
($) |
|
|
Date |
|
|
(#) |
|
|
($) |
|
Douglas J. Glaspey |
|
100,000 |
|
|
0 |
|
|
0.86 |
|
|
9/10/15 |
|
|
0 |
|
|
0 |
|
Kerry D. Hawkley |
|
50,000 |
|
|
0 |
|
|
0.86 |
|
|
9/10/15 |
|
|
0 |
|
|
0 |
|
Jonathan Zurkoff |
|
145,000 |
|
|
0 |
|
|
0.86 |
|
|
9/10/15 |
|
|
0 |
|
|
0 |
|
Dennis J. Gilles |
|
100,000 |
|
|
0 |
|
|
0.60 |
|
|
9/12/16 |
|
|
0 |
|
|
0 |
|
Douglas J. Glaspey |
|
165,000 |
|
|
0 |
|
|
0.83 |
|
|
6/13/16 |
|
|
0 |
|
|
0 |
|
Kerry D. Hawkley |
|
95,000 |
|
|
0 |
|
|
0.83 |
|
|
6/13/16 |
|
|
0 |
|
|
0 |
|
Jonathan Zurkoff |
|
146,000 |
|
|
0 |
|
|
0.83 |
|
|
6/13/16 |
|
|
0 |
|
|
0 |
|
Dennis J. Gilles |
|
100,000 |
|
|
0 |
|
|
0.31 |
|
|
8/24/17 |
|
|
0 |
|
|
0 |
|
Douglas J. Glaspey |
|
190,000 |
|
|
0 |
|
|
0.31 |
|
|
8/24/17 |
|
|
0 |
|
|
0 |
|
Kerry D. Hawkley |
|
150,000 |
|
|
0 |
|
|
0.31 |
|
|
8/24/17 |
|
|
0 |
|
|
0 |
|
Jonathan Zurkoff |
|
150,000 |
|
|
0 |
|
|
0.31 |
|
|
8/24/17 |
|
|
0 |
|
|
0 |
|
Dennis J. Gilles |
|
1,250,000 |
|
|
0 |
|
|
0.35 |
|
|
4/19/23 |
|
|
0 |
|
|
0 |
|
Douglas J. Glaspey |
|
112,500 |
|
|
37,500 |
|
|
0.46 |
|
|
7/22/18 |
|
|
0 |
|
|
0 |
|
Kerry D. Hawkley |
|
93,750 |
|
|
31,250 |
|
|
0.46 |
|
|
7/22/18 |
|
|
0 |
|
|
0 |
|
Jonathan Zurkoff |
|
93,750 |
|
|
31,250 |
|
|
0.46 |
|
|
7/22/18 |
|
|
0 |
|
|
0 |
|
Dennis J. Gilles |
|
200,000 |
|
|
200,000 |
|
|
0.74 |
|
|
4/2/19 |
|
|
325,000 |
|
|
149,500 |
|
Douglas J. Glaspey |
|
110,000 |
|
|
110,000 |
|
|
0.74 |
|
|
4/2/19 |
|
|
29,730 |
|
|
13,676 |
|
Kerry D. Hawkley |
|
87,500 |
|
|
87,500 |
|
|
0.74 |
|
|
4/2/19 |
|
|
23,649 |
|
|
10,879 |
|
Jonathan Zurkoff |
|
87,500 |
|
|
87,500 |
|
|
0.74 |
|
|
4/2/19 |
|
|
27,027 |
|
|
12,432 |
|
|
(1)The $0.74 options unexercisable at December 31, 2014
will fully vest on October 2, 2015. |
|
The $0.46 options unexercisable at December 31, 2013 fully vested on January 22, 2015.
|
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 Companys common stock and any unvested restricted shares
of the Companys 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 Companys contribution to the monthly cost of the medical and dental
benefits provided to Mr. Gilles under the employment agreement.
-106-
Mr. Glaspeys employment agreement provides that if within
twelve months following a change of control Mr. Glaspeys 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. Hawkleys employment agreement provides that if within
twelve months following a change of control Mr. Hawkleys 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. Zurkoffs employment agreement provides that if within
twelve months following a change of control Mr. Zurkoffs 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.
Director Compensation
The following table summarizes the compensation paid to our
directors during the year ended December 31, 2014.
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 |
44,700 |
0 |
41,844 |
0 |
0 |
0 |
86,544 |
|
Paul A. Larkin |
45,500 |
0 |
41,844 |
0 |
0 |
0 |
87,344 |
|
Leland L. Mink |
37,600 |
0 |
41,844 |
0 |
0 |
0 |
79,444 |
(1) |
Stock options are valued at the grant date in accordance
with FASB ASC Topic 718. |
-107-
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.
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 Companys equity compensation plans as of
December 31, 2014.
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
|
11,808,500
|
$0.62
|
4,244,204
|
Equity compensation plans not approved by security holders |
Nil
|
Nil
|
Nil
|
Total |
11,808,500 |
$0.62 |
4,244,204 |
Security Ownership of Certain Beneficial Owners and
Management
The following table sets forth certain information regarding
beneficial ownership of the Companys common stock, as of March 6, 2015 by each
person known by us to be the beneficial owner of more than 5% of the Companys
outstanding common stock. The percentage of beneficial ownership is based on
107,063,029 shares of the Companys common stock outstanding as of March 6,
2015.
-108-
|
|
Amount and Nature |
|
|
Name and Address of Beneficial Owner |
|
of Beneficial |
|
Percent of |
|
|
Ownership |
|
Class |
Sprott Inc. |
|
|
|
|
200 Bay Street, Suite 2700, PO Box 27 |
|
|
|
|
Toronto, ON, Canada M5J 2J1 |
|
5,911,281 (1)
|
|
5.52%
|
(1) |
As of December 31, 2014, based on information set forth
in a Schedule 13G/A filed with the SEC on January 12, 2015 by Sprott Inc.,
which has sole voting and dispositive power over 5,911,281 shares of the
Companys 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 Companys common stock, as of December 31, 2014, by each of our
directors, Named Executive Officers and directors and executive officers as a
group. The percentage of beneficial ownership is based on 107,063,029 shares of
the Companys common stock outstanding as of March 6, 2015.
|
|
Amount and |
|
|
|
|
Nature |
|
|
Name of Beneficial Owner |
|
of Beneficial |
|
Percent of |
|
|
Ownership |
|
Class |
Dennis J. Gilles |
|
2,502,778 (1) |
|
2.34% |
Douglas J. Glaspey |
|
1,322,187 (2) |
|
1.24% |
Kerry D. Hawkley |
|
574,899 (3) |
|
* |
Paul A. Larkin |
|
664,825 (4) |
|
* |
Leland L. Mink |
|
438,378 (5) |
|
* |
John H. Walker |
|
441,657 (6) |
|
* |
Jonathan Zurkoff |
|
744,277 (7) |
|
* |
|
|
|
|
|
All directors and executive officers as a
group (7 persons) |
|
6,689,001 (8) |
|
6.25% |
* |
Less than 1% of the Companys outstanding
common stock |
|
|
(1) |
Includes 1,650,000 options exercisable within
60 days of March 6, 2015. |
(2) |
Includes 677,500 options exercisable within 60
days of March 6, 2015. |
(3) |
Includes 426,250 options exercisable within 60
days of March 6, 2015. |
(4) |
Includes 360,000 options exercisable within 60
days of March 6, 2015. |
(5) |
Includes 360,000 options exercisable within 60
days of March 6, 2015. |
(6) |
Includes 360,000 options exercisable within 60
days of March 6, 2015. |
(7) |
Includes 622,250 options exercisable within 60
days of March 6, 2015. |
(8) |
Includes 4,456,000 options exercisable within
60 days of March 6, 2015. |
-109-
Item 13. Certain Relationships and Related Transactions,
and Director Independence
Related Person Transactions
Since January 1, 2012, 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 Companys 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 Companys 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 six directors: Dennis J.
Gilles, Douglas J. Glaspey, Paul A. Larkin, Leland L. Mink and John H. Walker. A
majority of the Board, made up of Mr. Gilles, Mr. Larkin, Dr. Mink 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
Boards 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.
Item 14. Principal Accountant Fees and
Services
Audit Fees
The aggregate fees billed to the Company by MartinelliMick PLLC
for the years ended December 31, 2014, and 2013 for the audit of the Companys
annual financial statements and reviews of the financial statements included in
the Companys Quarterly Reports on Form 10-Q, were $200,000 and $138,202;
respectively.
-110-
Audit-Related Fees
The aggregate fees billed to the Company by MartinelliMick PLLC
for the year December 31, 2013, for assurance and related services that are
reasonably related to the performance of the audit or review of the Companys
financial statements and are not reported under Audit Fees above, was $97,702.
No fees were specified for this area for the year ended December 31, 2014. The
fees billed to the Company for the financial statement audits of the Companys
two subsidiaries USG Oregon LLC and USG Nevada LLC for the years ended December
31, 2014 and 2013 were $47,943 and $32,701; respectively. MartinelliMick PLLC
billed the Company fees for audit and review services related to the submission
of the application for the ITC cash grant for the year ended December 31, 2013
that amounted $20,000. No ITC cash grant audit and review services were
performed during the year ended December 31, 2014.
The fees billed to the Company by MartinelliMick, PLLC for the
year ended March 31, 2013, for assurance and related services related to the
submitted an application to Oregon Department of Energy for a Business Energy
Tax Credit (BETC) for qualified construction purchases and are not reported
under Audit Fees above, was $18,500. No BETC tax credit fees review services
were performed during the year ended December 31, 2014.
The aggregate fees billed to the Company by Hein &
Associates LLP for the years ended December 31, 2014 and 2013, for assurance and
related services that are reasonably related to the performance of the audit or
review of the Companys financial statements and are not reported under Audit
Fees above, were $97,365 and $80,171; respectively. The services comprising
such fees related to compliance with the Sarbanes Oxley Act of 2002. Since the
Company does not employ an internal audit staff, Hein & Associates LLP
performed the internal audit function for verification of compliance with
internal controls and procedures.
Tax Fees
The aggregate fees billed to the Company by Hein &
Associates LLP for the years ended December 31, 2014 and 2013, for professional
services rendered for tax compliance, tax advice, and tax planning were $56,630
and $31,415; respectively. The services comprising such fees related to tax
compliance, including the preparation of and assistance with federal, state and
local income tax returns, foreign and other tax compliance. MartinelliMick PLLC
did not render any professional services relating to tax compliance, tax advice,
or tax planning during the years ended December 31, 2014 and 2013.
All Other Fees
The Company was not billed by MartinelliMick PLLC LLP for any
other services during years ended December 31, 2014 and 2013. Hein &
Associates provided other consulting services for the year ended December 31,
2013 that amounted to $9,190.
-111-
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, 2014 and 2013, including services related to the
Audit-Related Fees and Tax Fees described above, were approved by the Audit
Committee under its pre-approval policies.
-112-
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 |
|
Certificate of Incorporation of U.S.
Geothermal Inc., as amended. |
3.2 |
|
Certificate of Domestication of Non-U.S. Corporation
(Incorporated by reference to exhibit 3.2 to the registrants Form SB-2
registration statement as filed on July 8, 2004) |
3.3 |
|
Certificate of Amendment of Certificate of Incorporation
(changing name of U.S. Cobalt Inc. to U.S. Geothermal Inc.) (Incorporated
by reference to exhibit 3.3 to the registrants Form SB-2 registration
statement as filed on July 8, 2004) |
3.4 |
|
Second Amended and Restated Bylaws of U.S. Geothermal
Inc. (Incorporated by reference to exhibit 3.4 to the registrants Form
8-K as filed on October 18, 2010) |
3.5 |
|
Plan of Merger of U.S. Geothermal Inc. and EverGreen
Power Inc. (Incorporated by reference to exhibit 3.5 to the registrants
Form SB-2 registration statement as filed on July 8, 2004) |
3.6 |
|
Amendment to Plan of Merger (Incorporated by reference to
exhibit 3.6 to the registrants Form SB-2 registration
statement as filed on July 8, 2004) |
4.1 |
|
Form of Stock Certificate (Incorporated by reference to
exhibit 4.1 to the registrants 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys Form 8-K filed on February
28, 2011) |
-113-
4.10 |
|
Form of Subscription Agreement used in
March 2011 registered offering (Incorporated by reference to Exhibit 10.1
to the Companys Form 8-K filed on February 28, 2011) |
4.11 |
|
Form of Compensation Warrant (Incorporated by reference
to Exhibit 4.1 to the Companys Form 8-K filed on May 22, 2012) |
4.12 |
|
Form of Warrant Certificate used in December 2012
registered offering (incorporated by reference to exhibit 4.1 to the
Companys 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants Form 10-KSB annual report
as filed on June 29, 2006) |
10.12 |
|
Employment Agreement dated April 1, 2011 with Kerry D.
Hawkley (Incorporated by reference to exhibit 99.2 to the registrants
Form 8-K as filed on April 6, 2011) |
10.13 |
|
Employment Agreement dated April 1, 2011 with Douglas J.
Glaspey (Incorporated by reference to exhibit 99.1 to the registrants
Form 8-K as filed on April 6, 2011) |
10.14 |
|
Amended and Restated Stock Option Plan of U.S. Geothermal
Inc. dated September 29, 2006. (Incorporated by reference to
exhibit 10.23 to the registrants Form SB-2 registration statement as
filed on October 2, 2006.) |
-114-
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 registrants Amendment No. 2 to Form SB-2
registration statement as filed on January 10, 2005) |
10.16 |
|
Engineering, Procurement and Construction Agreement dated
December 5, 2005 between U.S. Geothermal Inc. and Ormat Nevada Inc.
(Incorporated by reference to exhibit 10.28 to the registrants 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
registrants 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 registrants 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 registrants Form SB-2
as filed on September 29, 2006). |
10.20 |
|
Transmission Agreement dated June 24, 2005 between
Department of Energys Bonneville Power Administration - Transmission
Business Line and U.S. Geothermal Inc. (Incorporated by reference to
exhibit 10.27 to the registrants 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 registrants 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 registrants 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
registrants 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 registrants 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 registrants 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 registrants 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 registrants 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 registrants Form S-1 as filed on
March 26, 2010) Asset Purchase Agreement dated as of March 31, 2008,
between U.S. Geothermal Inc., |
-115-
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 registrants
Form 8-K current report as filed on April 7, 2008) |
10.30 |
|
Water Rights Purchase Agreement Michael B. Stewart and
U.S. Geothermal Inc. dated March 31, 2008 (Incorporated by reference as
exhibit 99.2 to the registrants Form 8-K current report as filed on April
7, 2008). |
10.31 |
|
Power Purchase Agreement dated as of December 11, 2009,
between Idaho Power Company and USG Oregon LLC (Incorporated by reference
to Exhibit 10.43 to the Companys 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 registrants 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 registrants Form 10-Q/A quarterly report as filed on March 3,
2010) |
10.34 |
|
Engineering, Procurement and Construction Contract, dated
as of August 27, 2010, between USG Nevada LLC and Benham Constructors LLC
August 27, 2010. (Incorporated by reference to exhibit 99.1 to the
registrants Form 8-K as filed on November 8, 2010) * |
10.35 |
|
Amended and Restated Change in Control Guaranty made and
entered into as of October 13, 2010, by U.S. Geothermal Inc., in favor of
Benham Constructors, LLC. (Incorporated by reference to exhibit 99.2 to
the registrants Form 8-K as filed on November 8, 2010) |
10.36 |
|
Credit Addendum to Engineering, Procurement and
Construction Contract, dated as of August 27, 2010, between USG Nevada LLC
and Benham Constructors LLC August 27, 2010. (Incorporated by reference to
exhibit 99.3 to the registrants Form 8-K as filed on November 8, 2010)
|
10.37 |
|
Amended and Restated Limited Liability Company Agreement
made and entered into as of September 7, 2010, by and among Oregon USG
Holdings LLC, U.S. Geothermal Inc., and Enbridge (U.S.) Inc. (Incorporated
by reference to exhibit 99.4 to the registrants Form 8-K as filed on
November 8, 2010) * |
10.38 |
|
Conditional Guaranty Agreement, entered into as of
September 7, 2010, by US Geothermal Inc. to Enbridge (U.S.) Inc.
(Incorporated by reference to exhibit 99.5 to the registrants Form 8-K as
filed on November 8, 2010) |
10.39 |
|
2009 Stock Incentive Plan of the Registrant (Incorporated
by reference to Appendix A to the Companys definitive proxy statement on
Schedule 14A as filed on November 6, 2009)** |
10.40 |
|
Loan Guarantee Agreement dated as of February 23, 2011,
among USG Oregon LLC, U.S. Department of Energy, and PNC Bank N.A.
(Incorporated by reference to exhibit 99.2 to the registrants Form 8-K as
filed on August 31, 2011) |
10.41 |
|
Equity Pledge Agreement dated as of February 23, 2011,
among Oregon USG Holdings LLC, USG Oregon LLC, and PNC Bank, N.A.
(Incorporated by reference to exhibit 99.3 to the registrants Form 8-K as
filed on August 31, 2011) |
-116-
10.42 |
|
Future Advance Promissory Note dated February 23, 2011,
among USG Oregon LLC and Federal Financing Bank (Incorporated by reference
to exhibit 99.4 to the registrants Form 8-K as filed on August 31, 2011)
|
10.43 |
|
Note Purchase Agreement dated as of February 23, 2011
among the Federal Financing Bank, USG Oregon LLC, and the Secretary of
Energy, acting though the Department of Energy (Incorporated by reference
to exhibit 99.2 to the registrants Form 8-K as filed on September 15,
2011) |
10.44 |
|
Financing Agreement dated November 9, 2011, between USG
Nevada LLC and Ares Capital Corporation (incorporated by reference to
Exhibit 10.1 to the registrants Form 8-K filed on November 16, 2011)
|
10.45 |
|
Purchase Agreement dated May 21, 2012, between U.S.
Geothermal Inc. and Lincoln Park Capital Fund, LLC ( incorporated by
reference to Exhibit 10.1 to the Registrants From 8-K as filed on May 22,
2012) |
10.46 |
|
Amendment No. 1 to the Purchase Agreement with Lincoln
Park Capital Fund, LLC, dated December 21, 2012 (incorporated by reference
to exhibit 10.1 to the Companys Form 8-K filed on December 21, 2012)
|
10.47 |
|
Form of Subscription Agreement used in December 2012
registered offering (incorporated by reference to exhibit 10.1 to the
Companys Form 8-K filed on December 21, 2012) |
13.1 |
|
Audited Consolidated Financial Statements of U.S.
Geothermal Inc. as of March 31, 2014. |
21.1 |
| f
Subsidiaries of the Registrant |
23.1 |
|
Consent of MartinelliMick, PLLC |
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.
-117-
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.
|
|
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U.S. Geothermal Inc. |
|
|
|
|
|
|
|
(Registrant) |
|
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|
|
|
|
|
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March 16, 2015 |
|
|
|
|
|
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 16, 2015 |
Dennis J. Gilles |
|
|
|
|
|
|
Chief Financial Officer (Principal Financial
and |
|
/s/ Kerry Hawkley
|
Accounting Officer) |
March 16, 2015 |
Kerry Hawkley |
|
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|
|
|
/s/ Douglas J. Glaspey |
President, Chief Operating Officer and
Director |
March 16, 2015 |
Douglas J. Glaspey |
|
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/s/ John H. Walker
|
Chairman and Director |
March 16, 2015 |
John H. Walker |
|
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/s/ Paul A. Larkin
|
Director |
March 16, 2015 |
Paul A. Larkin |
|
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/s/ Leland L. Mink
|
Director |
March 16, 2015 |
Leland R. Mink |
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|
-118-
Exhibit 21.1
LIST OF SUBSIDIARIES
U.S. Geothermal Inc. (incorporated in the
State of Idaho)
U.S. Geothermal Services, LLC (organized
in the State of Delaware)
Nevada USG Holdings, LLC (organized in
the State of Delaware)
USG Nevada LLC (organized in the State of
Delaware)
Nevada North USG Holdings, LLC (organized
in the State of Delaware)
USG Nevada North LLC (organized in the
State of Delaware)
USG Gerlach LLC (organized in the State
of Delaware)
Gerlach Geothermal, LLC (organized in the
State of Delaware)
Oregon USG Holdings, LLC (organized in
the State of Delaware)
USG Oregon LLC (organized in the State of
Delaware)
U.S. Geothermal Guatemala, S.A.
(organized in Guatemala)
Raft River Energy I LLC (organized in the
State of Delaware)
Geysers USG Holdings Inc. (incorporated
in the State of Delaware)
Western GeoPower, Inc. (incorporated in
the State of California)
Etoile Holdings Inc. (incorporated in the
Bahamas)
Mayacamas Energy LLC (organized in the State of California)
Skyline Geothermal Holding, Inc.
(incorporated in the State of Delaware)
Skyline Geothermal LLC (organized in the
State of Delaware)
Earth Power Resources Inc. (incorporated
in the State of Delaware)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-164394), Form S-8 (No. 333-141262), Form S-3 (No. 333-165728), Form S-3 (No. 333-170202) and Form S-3 (333-192611) of our audit report dated March 13, 2015, with respect to the consolidated financial statements of U.S. Geothermal Inc. included in the Annual Report (Form 10-K) for the year ended December 31, 2014.
MartinelliMick PLLC
March 13, 2015
Exhibit 31.1
CERTIFICATION
I, Dennis J. Gilles certify that: |
|
|
1. |
I have reviewed this report on Form 10-K of
U.S. Geothermal, Inc.; |
|
|
2. |
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this report; |
|
|
3. |
Based on my knowledge, the financial
statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this report; |
|
|
4. |
The registrants other certifying officer and I
are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a- 15(f) and 15d-15(f)) for the registrant and have:
|
|
a. |
designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
|
|
|
b. |
designed such internal control over financial reporting,
or caused such internal control over financial reporting to be designed
under our supervision, 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; |
|
|
|
|
c. |
evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on
such evaluation; and |
|
|
|
|
d. |
disclosed in this report any change in the registrants
internal control over financial reporting that occurred during the
registrants most recent fiscal quarter (the registrants fourth fiscal
quarter in the case of an annual report) that has materially affected, or
is reasonably likely to materially affect, the registrants internal
control over financial reporting; and |
5. |
The registrants other certifying officer and I have
disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrants auditors and the audit committee
of the registrants board of directors (or persons performing the
equivalent functions): |
|
a. |
all significant deficiencies and material
weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrants
ability to record, process, summarize and report financial information;
and |
|
|
|
|
b. |
any fraud, whether or not material, that
involves management or other employees who have a significant role in the
registrants internal control over financial reporting.
|
Date: March 16, 2015 |
|
|
/s/ Dennis J.
Gilles
|
Dennis J. Gilles |
Chief Executive Officer |
Exhibit 31.2
CERTIFICATION
I, Kerry D. Hawkley certify that: |
|
|
1. |
I have reviewed this report on Form 10-K of
U.S. Geothermal, Inc.; |
|
|
2. |
Based on my knowledge, this report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this report; |
|
|
3. |
Based on my knowledge, the financial
statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods
presented in this report; |
|
|
4. |
The registrants other certifying officer and I
are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a- 15(f) and 15d-15(f)) for the registrant and have:
|
|
a. |
designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
|
|
|
b. |
designed such internal control over financial reporting,
or caused such internal control over financial reporting to be designed
under our supervision, 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; |
|
|
|
|
c. |
evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on
such evaluation; and |
|
|
|
|
d. |
disclosed in this report any change in the registrants
internal control over financial reporting that occurred during the
registrants most recent fiscal quarter (the registrants fourth fiscal
quarter in the case of an annual report) that has materially affected, or
is reasonably likely to materially affect, the registrants internal
control over financial reporting; and |
5. |
The registrants other certifying officer and I have
disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrants auditors and the audit committee
of the registrants board of directors (or persons performing the
equivalent functions): |
|
a. |
all significant deficiencies and material
weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrants
ability to record, process, summarize and report financial information;
and |
|
|
|
|
b. |
any fraud, whether or not material, that
involves management or other employees who have a significant role in the
registrants internal control over financial reporting.
|
Date: March 16, 2015 |
|
|
|
/s/ Kerry D.
Hawkley
|
Kerry D. Hawkley |
Chief Financial Officer |
Exhibit 32.1
CERTIFICATION
In connection with the report of U.S. Geothermal Inc. (the
Company) on Form 10-K for the year ended December 31, 2014 as filed with the
Securities and Exchange Commission (the Report), I, Dennis J. Gilles, Chief
Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
1. |
The Report fully complies with the requirements of
Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended;
and |
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|
2. |
The information contained in the Report fairly presents,
in all material respects, the financial condition and results of
operations of the Company. |
Date: March 16, 2015 |
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/s/ Dennis J.
Gilles
|
Dennis J. Gilles |
Chief Executive Officer |
Exhibit 32.2
CERTIFICATION
In connection with the report of U.S. Geothermal Inc. (the
Company) on Form 10-K for the year ended December 31, 2014 as filed with the
Securities and Exchange Commission (the Report), I, Kerry D. Hawkley, Chief
Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350,
as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
|
1. |
The Report fully complies with the requirements of
Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as
amended; and |
|
|
|
|
2. |
The information contained in the Report fairly presents,
in all material respects, the financial condition and results of
operations of the Company. |
Date: March 16, 2015 |
|
|
/s/ Kerry D.
Hawkley
|
Kerry D. Hawkley |
Chief Financial Officer |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K/A
(Amendment No. 1)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2014
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) |
Registrants 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
-1-
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 registrants
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 [ ] |
Smaller reporting company [X] |
(Do not check if a smaller reporting company) |
|
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 registrants most recent
second quarter (taking into account the change in fiscal year end), based upon
the closing sale price of the registrants common stock as reported by the NYSE
MKT LLC on June 30, 2014, was $60,979,679
The number of shares outstanding of the registrants common
stock as of March 6, 2015 was 107,063,029.
DOCUMENTS INCORPORATED BY REFERENCE
None.
-2-
EXPLANATORY NOTE
The Registrant is filing this Amendment No. 1 to Form 10-K for
the fiscal year ended December 31, 2014 (Amendment No. 1) to correct an error
on the cover page of the original Form 10-K as filed with the Securities and
Exchange Commission on March 16, 2015 (the Original Form 10-K). The cover page
of the Original Form 10-K showed an incorrect aggregate market value of the
voting and non-voting common equity held by non-affiliates as of the
Registrants most recent second quarter, or June 30, 2014. The correct aggregate
market value of the voting and non-voting common equity held by non-affiliates
at June 30, 2014, was $60,979,679 as indicated on the cover page of this
Amendment No. 1 (rather than the $85,252,768 value at March 21, 2014 as originally shown).
No changes are hereby made to the Registrants financial
statements. Other than the change discussed above and the filing of the
currently dated Section 302 certifications, no changes have been made to the
Original Form 10-K or the exhibits filed therewith. As such, this Amendment No.
1 should be read in conjunction with the Original Form 10-K.
The information contained in this Amendment No. 1 does not
reflect events occurring subsequent to the filing of the Original Form 10-K.
-3-
PART IV
Item 15. Exhibits and Financial Statement
Schedules
The following documents are filed as a part of this Amendment
No. 1:
2. Exhibits. See below.
EXHIBIT INDEX
EXHIBIT NUMBER |
|
EXHIBIT DESCRIPTION |
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 |
-4-
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.
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U.S. Geothermal Inc. |
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(Registrant) |
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March 30, 2015 |
|
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By: |
/s/
Kerry D. Hawkley |
Date |
|
|
Kerry D. Hawkley |
|
|
|
Chief Financial Officer |
-5-
Exhibit 31.1
CERTIFICATION
I, Dennis J. Gilles certify that:
1. |
I have reviewed this report on Form 10-K of U.S.
Geothermal, Inc.; |
|
|
|
2. |
Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this report; |
|
|
|
3. |
Based on my knowledge, the financial statements, and
other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
report; |
|
|
|
4. |
The registrants other certifying officer and I are
responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a- 15(f) and 15d-15(f)) for the registrant and have: |
|
|
|
|
a. |
designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
|
|
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b. |
designed such internal control over financial reporting,
or caused such internal control over financial reporting to be designed
under our supervision, 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; |
|
|
|
|
c. |
evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on
such evaluation; and |
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d. |
disclosed in this report any change in the registrants
internal control over financial reporting that occurred during the
registrants most recent fiscal quarter (the registrants fourth fiscal
quarter in the case of an annual report) that has materially affected, or
is reasonably likely to materially affect, the registrants internal
control over financial reporting; and |
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|
5. |
The registrants other certifying officer and I have
disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrants auditors and
the audit committee of the registrants board of directors (or
persons performing the equivalent functions): |
|
a. |
all significant deficiencies and material weaknesses in
the design or operation of internal control over financial reporting which
are reasonably likely to adversely affect the registrants ability to
record, process, summarize and report financial information; and |
|
|
|
|
b. |
any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial
reporting. |
Date: March 30, 2015
/s/ Dennis J. Gilles________________________
Dennis
J. Gilles
Chief Executive Officer
Exhibit 31.2
CERTIFICATION
I, Kerry D. Hawkley certify that:
1. |
I have reviewed this report on Form 10-K of U.S.
Geothermal, Inc.; |
|
|
|
2. |
Based on my knowledge, this report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this report; |
|
|
|
3. |
Based on my knowledge, the financial statements, and
other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
report; |
|
|
|
4. |
The registrants other certifying officer and I are
responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a- 15(f) and 15d-15(f)) for the registrant and have: |
|
|
|
|
a. |
designed such disclosure controls and procedures, or
caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
|
|
|
b. |
designed such internal control over financial reporting,
or caused such internal control over financial reporting to be designed
under our supervision, 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; |
|
|
|
|
c. |
evaluated the effectiveness of the registrants
disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on
such evaluation; and |
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d. |
disclosed in this report any change in the registrants
internal control over financial reporting that occurred during the
registrants most recent fiscal quarter (the registrants fourth fiscal
quarter in the case of an annual report) that has materially affected, or
is reasonably likely to materially affect, the registrants internal
control over financial reporting; and |
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5. |
The registrants other certifying officer and I have
disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrants auditors and
the audit committee of the registrants board of directors (or
persons performing the equivalent functions): |
|
a. |
all significant deficiencies and material weaknesses in
the design or operation of internal control over financial reporting which
are reasonably likely to adversely affect the registrants ability to
record, process, summarize and report financial information; and |
|
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b. |
any fraud, whether or not material, that involves
management or other employees who have a significant role in the
registrants internal control over financial
reporting. |
Date: March 30, 2015
/s/ Kerry D. Hawkley________________________
Kerry
D. Hawkley
Chief Financial Officer
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