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20549
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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, 2013
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
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84-1472231
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(State or Other Jurisdiction of
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(I.R.S. Employer
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Incorporation or Organization)
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Identification No.)
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390 Parkcenter Blvd, Suite 250
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Boise, Idaho
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83706
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(Address of Principal Executive Offices)
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(Zip Code)
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Registrants Telephone Number, Including Area Code
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208-424-1027
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Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.001 par value
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NYSE MKT LLC
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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
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registrant was required to file such reports), and (2) has been subject to such
filing requirements for at least the past 90 days.
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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).
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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.
[ ]
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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 21, 2014 was 102,714,178.
U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013
U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013
U.S. Geothermal Inc. and Subsidiaries
Form 10-K
INDEX
For the Year Ended December 31, 2013
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;
-6-
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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 for our projects;
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impact of environmental and other governmental regulation, including delays
in obtaining permits;
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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.
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 Region of the United States of America.
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.
On July 5, 2012, the Companys Board of Directors changed the
Companys fiscal year end from March 31 to December 31, beginning December 31,
2012.
-7-
Development of Business
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. The Company currently owns and operates
the following geothermal projects: Raft River, Idaho; San Emidio, Nevada; and
Neal Hot Springs, Oregon. The Company also has property interests in the
Republic of Guatemala, and Gerlach and Granite Creek, Nevada, some of which are
under development or exploration.
On March 5, 2002, Geo-Idaho entered into a letter agreement
with the owner of the Raft River project located in southeastern Idaho, pursuant
to which Geo-Idaho agreed to acquire all of the real property, personal property
and permits that comprised the owners interest in that project.
The Company signed a 20 year power purchase agreement with
Idaho Power on December 29, 2004 to purchase 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 10 MW net,
but has held steady at that level for over a year.
In May 2008, the Company acquired geothermal assets, including
an old 3.6 net megawatt nameplate generating capacity power plant, from Empire
Geothermal Power LLC and Michael B. Stewart, located in Washoe County, Nevada
for approximately $16.6 million, which included certain ground water rights,
plus the Granite Creek geothermal prospect. Financing was secured from the
general contractor for construction of a new power plant in August 2010. The
plant was originally scheduled to be completed by November 2011; however, many
issues delayed the plant from becoming operational as scheduled. The 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 9.0 megawatts
due to higher than expected efficiency. On February 15, 2013, USG Nevada LLC
signed a second settlement agreement with SAIC. The settlement agreement reduced
the construction cost and accrued interest liability incurred under the
construction loan agreement by approximately $1.6 million. The agreement also
defined the remaining liability as consisting of three components. The first
component was a $1.0 million non-interest bearing note that was paid in full in
June 2013. The second component was a $2,000,000 obligation that will be paid in
quarterly installments that are scheduled through 2018. The third component was
a balloon payment of $26,525,000 that was replaced with long-term financing.
Effective May 1, 2013, USG Nevada LLC entered into a third credit addendum with
SAIC. This addendum superseded the prior credit addendum and replaced the third
component of obligation with a new aggregate indebtedness that totaled
$26,350,000. The new obligation consisted of two components. The first component
of $1,350,000 was paid in full as of the effective date of third credit
addendum. The remaining portion of $25,000,000 was replaced by a long-term note
held by Prudential Financial Group that was finalized on September 26, 2013. The
Prudential loan will be repaid with quarterly payments that are scheduled
through 2037. The Company has begun drilling in support of the development of a
second phase of development. The current Power Purchase Agreement allows for
19.9 megawatts, but only 9 megawatts is currently committed, leaving a potential
contacted expansion potential of 11 megawatts.
-8-
On September 5, 2006, the Company announced the acquisition of
property for a geothermal project at Neal Hot Springs, Oregon located in eastern
Oregon near the Idaho border. The property is 8.5 square miles of geothermal
energy and surface rights. On May 5, 2008, the Company announced that drilling
had begun on the first full size production well which was completed on May 23,
2009. In February 2009, the Company submitted an 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 on a drill pad was completed in August
2009. In September 2009, the Company began drilling its major production well,
which was substantially completed on October 15, 2009. In December 2009, USG
Oregon LLC signed a 25-year power purchase agreement with Idaho Power Company
that provides for the sale of up to 25 megawatts. The PPA was approved by the
Idaho PUC in May 2010. The financial closing for the DOE loan guarantee took
place in February 2011 which secured a $96.8 million loan guarantee from the
Department of Energy and a direct loan from the U.S. Treasurys Federal
Financing Bank. The DOE loan is a combined construction and 22 year term loan.
The interest rate on the loan is set at the 22 year treasury rate plus
approximately 37 basis points when each advance is drawn. Enbridge Inc. became
an equity partner in the project in April 2009. In October 2011, USG Oregon LLC
began drawing on the DOE loan. The Company received the Final Conditional
Certificate on December 31, 2012 needed to receive the Oregon Business Energy
Tax Credit (BETC). The Company was able to successfully monetize the BETC on
November 14, 2013. Equity ownership interest in the project has now been
determined with the Company owning 60%, and Enbridge owning 40%. The power plant
became commercially operational on November 16, 2012. The final draw of the DOE
loan occurred on July 31, 2013.
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 power purchase agreement for the El Ceibillo
Project located near Guatemala City in October 2012. The framework of the
agreement outlines a 15 year term to deliver up to 50 megawatts of power at
competitive prevailing energy prices in the region. Geophysics activities and
the drilling of the first exploration well occurred during 2013. A 25 megawatt
flash steam plant is targeted to be in operation in the fourth quarter of 2015.
-9-
Plan of Operations
Our management examines different factors when assessing
potential acquisitions or projects at different stages of development, such as
the internal rate of return of the investment, technical and geological matters
and other relevant business considerations. We evaluate our operating projects
based on revenues and expenses, and our projects under development, based on
costs attributable to each project.
Our business strategy is to identify, evaluate, acquire,
develop and operate geothermal assets and resources economically, safely and
efficiently. We intend to execute this strategy in several steps outlined below:
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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 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 was started prior
to the end of 2013. The second phase of our San Emidio project qualifies for
this credit.
-10-
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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 costly,
technically challenging and requires long lead times before a project will
produce revenue. We believe that geothermal technical and managerial talent is
limited in the industry and that access to capital to develop projects will
not be equally available to all participants. As a result, we believe that
there will be opportunities in the future to pursue acquisitions of geothermal
projects and/or geothermal development companies with attractive project
pipelines.
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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.
Material Acquisitions/Development
A summary of projects under development and additional
properties is as follows:
Projects Under Development
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Estimated
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Target
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Projected
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Capital
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Development
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Commercial
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Required
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Project
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Location
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Ownership
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(Megawatts)
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Operation Date
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($million)
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Power Purchaser
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El Ceibillo Phase I
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Guatemala
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100%
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25
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4
th
Quarter 2015
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$135
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MOU
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San Emidio Phase II
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Nevada
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100%
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11
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4
th
Quarter 2015
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$55
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NV Energy
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Additional Properties
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Project
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Location
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Ownership
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Target Development (Megawatts)
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Gerlach
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Nevada
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60%
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TBD
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Granite Creek
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Nevada
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100%
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TBD
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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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San Emidio Phase III
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Nevada
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100%
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17.2
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Neal Hot Springs II
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Oregon
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100%
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28
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Raft River Unit II
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Idaho
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100%
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26
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Raft River Unit III
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Idaho
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100%
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32
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-11-
Resource Details
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Property Size
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Temperature
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Property
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(square miles)
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(
º
F)
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Depth (Ft)
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Technology
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Raft River
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10.8
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275-302
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4,500-6,000
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Binary
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San Emidio
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35.8
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289-316
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1,500-3,000
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Binary
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Neal Hot Springs
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9.6
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311-347
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2,500-3,000
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Binary
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Gerlach
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5.6
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338-352
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2,000-3,000
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Binary
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Granite Creek
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3.8
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TBD
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TBD
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Binary
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El
Ceibillo
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38.6
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410-526
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1,800-TBD
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Steam
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Neal Hot Springs, Oregon
Neal Hot Springs is located
in Eastern Oregon near the town of Vale, the county seat of Malheur County. The
Neal Hot Springs facility is designed as a 22 megawatt net annual average power
plant, consisting of three separate, 7.33 net megawatt modules. The facility
achieved commercial operation under the terms of the power purchase agreement on
November 16, 2012. Generation from the facility during the fourth quarter of
2013 totaled 53,445 megawatt-hours with an average of 25.62 net megawatts per
hour of operation. Plant availability was 94.7% during the quarter as plant
operations continue to improve. Generation for the year was 155,430
megawatt-hours with annual plant availability of 83.1% .
On June 27, 2013, the Company accepted substantial completion
by the EPC contractor of all three of the Neal Hot Springs units. Final
completion of the project was achieved on July 31, 2013.
On February 26, 2009, the Company submitted a loan application
for the Neal Hot Springs project to the DOEs Energy Efficiency, Renewable
Energy and Advanced Transmission and Distribution Solicitation loan guarantee
program under Title XVII of the Energy Policy Act of 2005. The financial closing
for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8
million loan guarantee from the Department of Energy and a direct loan from the
U.S. Treasurys Federal Financing Bank. The DOE loan for the project was closed
at final completion and has a balance of $70.4 million that bears an interest
rate of 2.6% over a 22 year term. The construction cost of the project has been
set at $128.1 million. Total project cost, including $11.2 million in reserves,
was $139.3 million, which is $4.3 million less than previously reported due
primarily to the inclusion of unused contingency funds which have since been
released by the project lender.
Over the course of the ongoing construction, the budget was
increased by $14.6 million in equity contributions by the partners. The first
increase of $7.0 million was to cover additional drilling costs and
modifications in plant controls and the cooling mechanism. Enbridge Inc., our
partner at Neal Hot Springs, provided the additional investment in exchange for
increased ownership interest in the project from 20% to a percentage to be
calculated based on an agreed upon financial model. A second budget increase of
$6 million, also provided by Enbridge Inc., was to establish a contingency fund
for potential additional drilling to complete the well field. Each of the
additional investments made by Enbridge Inc. was subject to calculations which
would result in increased ownership interest in the project.
-12-
Subsequent to the end of the quarter, in February 2014, the
final ownership interest in the Neal Hot Springs project was determined to be
60% for U.S. Geothermal and 40% for Enbridge. As a result of the final
agreement, U.S. Geothermal received an approximate $6.2 million cash
distribution from the partnership.
The project received a $32.75 million cash grant under Section
1603 Specified Energy Property in Lieu of Tax Credits from the Treasury
Department. The cash grant, originally approved at $35.4 million, was subject to
an 8.7% reduction due to Federal sequestration ordered by Congress under the
Budget Control Act. The proceeds from the grant were used to: 1) fund $11.2
million in project level cash reserves as required by the terms of the DOE loan,
2) pay down $11.9 million on the DOE loan and 3) the balance of $9.7 million was
distributed to equity investors.
In July 2010, the Company applied to the Oregon Department of
Energy (ODOE) for the Business Energy Tax Credit (BETC), which allows an
income tax credit for up to $20 million in qualifying capital expenditures for a
renewable energy project. The Company received unconditional approval of the
final certificate on March 1, 2013. The BETC was sold to a pass-through tax
partner in November 2013 for approximately $7.36 million.
The PPA for the project was signed on December 11, 2009 with
the Idaho Power Company. The PPA has a 25 year term with a starting average
price for the year 2012 of $96.00 per megawatt-hour and escalates at a variable
percentage annually. On May 20, 2010, the Idaho Public Utilities Commission
approved the PPA with no changes to the terms and conditions. Power generated
during 2013 was paid at an average price of $99.00 per megawatt-hour. The Idaho
Power PPA has a seasonal pricing structure that pays 120% of the average price
for four months (July, August, November, December), 100% of the average price
for five months (January, February, June, September, October) and 73.3% of the
average price for three months (March, April, May). The average price paid under
the PPA for 2014 has increased to $102.78 per megawatt-hour.
San Emidio, Nevada
The Phase I power plant at San
Emidio is located approximately 100 miles north of Reno, Nevada and achieved
commercial operation on May 25, 2012. Generation from the facility during the
fourth quarter 2013 totaled 21,103 megawatt-hours, with an average of 9.72 net
megawatts per hour of operation. Plant availability was 98.3% during the
quarter. Generation for the year was 76,696 megawatt-hours with annual plant
availability of 94.5% .
The Company entered into agreements with Science Applications
International Corporation (SAIC) for a project loan and an engineering
procurement and construction (EPC) contract for the San Emidio Phase I power
plant repower. SAICs design-build subsidiary, SAIC Energy, Environment &
Infrastructure LLC, constructed a new 9.0 net megawatt power plant, replacing
the old 3.6 net megawatt power plant. TAS Energy of Houston, Texas, supplied a
modular power plant to the project. Phase I achieved mechanical completion in
December 2011, and following performance testing of the power plant, which began
in early May 2012, achieved commercial operation on May 25, 2012. SAIC provided
its services under a fixed price contract that included financial guarantees for
the original completion date and power output of the plant. The Phase I plant completed its capacity testing during the first
quarter of 2013, and as a result of the capacity test exceeding the designed
output; the plant was up-rated to 9.0 megawatt net annual average per hour from
the design point basis of 8.6 megawatts.
-13-
Substantial Completion under the contract was achieved February
21, 2013. Final Completion under the terms of the EPC was executed on June 24,
2013.
A final settlement agreement was executed as part of
Substantial Completion and included a fixed total construction loan payable to
the EPC contractor of $29.5 million. Prior to Substantial Completion, the
Company had paid down the loan balance by $1.0 million in three monthly
payments. Upon Substantial Completion, a payment of $1.35 million was made to
SAIC, and the construction loan was extended until November 15, 2013 with a
balance of $25.0 million carrying an interest rate of 10%. Additionally, a $2.0
million, 5 year term, unsecured loan was put in place for the balance of the
construction loan. This loan bears interest at 7% and has a payment obligation
of $119,382 per quarter.
The $25 million construction loan with SAIC was paid off in
September of 2013, and was replaced with long term notes purchased by Prudential
Capital Groups related entities. The notes are for an aggregate of
approximately $30.74 million, have a term of approximately 24 years, and bear a
fixed interest rate of 6.75% per annum. Proceeds from the sale of the notes were
used to repay the SAIC construction loan, fund project reserves, and pay certain
closing expenses, and approximately $2.56 million of the proceeds was
distributed to U.S. Geothermal Inc. to be used for general corporate working
capital purposes, including the further development of Phase II at San
Emidio.
The Phase II expansion was delayed due to the extended time
required to get Phase I online, and is still dependent on successful development
of additional production and injection well capacity. The cost of development
for Phase II is estimated at approximately $55 million. We expect that
approximately 75% of the Phase II development may be funded by project loans,
with the remainder funded through equity financing.
On June 1, 2011, an amended and restated PPA was signed with
Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9
megawatts of electricity on an annual average basis. The PPA has a 25 year term
with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate.
Power generated during 2013 was paid at the price of $90.27 per megawatt-hour.
The average price paid under the PPA for 2014 has increased to $91.17 per
megawatt-hour.
The electrical output from both Phase I and Phase II may 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. If Phase II cannot
achieve commercial operation under a proposed milestone schedule by December
2015, a new PPA would need to be negotiated and signed before financing and
construction could begin. A Small Generator Interconnection Agreement for 16
megawatts of transmission capacity was executed with Sierra Pacific Power
Company on December 28, 2010. Subsequent to the end of the year, 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.
-14-
On October 30, 2009, the Company was awarded $3.77 million in
Recovery Act funding for the exploration and development of its San Emidio
geothermal power project using advanced geophysical exploration techniques. This
award was categorized under the Innovative Exploration and Drilling Projects
section of the American Recovery and Reinvestment Act. The project at San Emidio
has applied innovative, seismic and satellite imagery techniques along with
state-of-the-art structural modeling, to locate large aperture fractures that
represent high-productivity geothermal drilling targets. Two zones along the 4.5
mile long San Emidio fault structure were identified as high quality targets for
drilling during the first phase of the DOE program, a South Zone and a North
Zone. The first phase was completed in 2011.
The second stage of the DOE program is a 50-50 cost shared
drilling plan that followed up on the South Zone targets identified in the first
stage. In order to meet construction targets for Phase II plant construction,
the drilling stage of the program commenced prior to DOE approval, and two
observation wells were completed by the Company. The proposed drilling program
was approved by the DOE in early November 2011. One of the first two wells was
deepened and three additional wells have been completed in the South Zone under
the 50-50 cost share grant.
The DOE cost shared drilling program continues with the further
resource identification in the South Zone and the addition of the resource
identification in the North Zone. The North Resource Area, has an additional
five observation/temperature gradient wells and one production well planned as
part of the cost share drilling program. Drilling began on well OW-12 on
September 2, 2013. The well was completed on October 23, 2013 to a depth of
3,643 feet and is being evaluated in relation to the San Emidio reservoir model.
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 is planned
for the spring or early summer. The results from both wells will be used to
determine the continuing resource development plan in support of the Phase II
plant construction.
In addition, permitting was initiated with the Bureau of Land
Management 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). Subsequent to the end of the quarter, a seismic program was carried out
covering three lines in the South Zone to provide additional data for targeting
the next drill holes.
Raft River, Idaho
The Raft River project is located
in Southern Idaho, near the town of Malta, and achieved commercial operation in
January 2008. Generation from the facility during the fourth quarter 2013
totaled 21,742 megawatt-hours, with an average of 9.85 net megawatts per hour of
operation. Plant availability was 99.2% during the quarter. Generation for the
year was 77,552 megawatt-hours with annual plant availability of 96.5% .
The PPA for the project was signed on September 24, 2007 with
the Idaho Power Company. The PPA has a 25 year term with a starting average
price for the year 2007 of $52.50 that escalates at 2.1% per year. Power
generated during 2013 was paid at an average price of $59.47 per megawatt-hour.
The Idaho Power PPA has a seasonal pricing structure that pays 120% of the
average price for four months (July, August, November, December), 100% of the
average price for five months (January, February, June, September,
October) and 73.5% of the average price for three months (March, April, May).
The average price paid under the PPA for 2014 has increased to $60.72 per
megawatt-hour. In addition to the price paid for energy, Raft River currently
receives $4.75 per megawatt-hour under a separate contract for the sale of
Renewable Energy Credits.
-15-
The DOE $11.4 million cost-shared, thermal fracturing program
began the first stage of injection in June 2013 and continued until September
when the second stage was started. Four, 300 foot deep seismic monitoring wells
were completed in the area around well RRG-9 and seismic geophones were
installed. Seismic monitoring will be conducted for the duration of the thermal
fracturing program. Injection continued through the fourth quarter from power
plant injectate at an approximate temperature of 140°F. Flow in to the well has
seen a moderate increase indicating that additional permeability is developing.
The program has continued through the winter with low level injection going in
to the well with a high pressure injection phase planned for spring 2014.
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 totaling $991,417.
Republic of Guatemala
A geothermal energy rights
concession located 14 kilometers southwest of Guatemala City was awarded to U.S.
Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April
2010. The concession has a 5 year term for the development and construction of a
power plant. Discussions are being held with the Guatemalan Ministry of Energy
and Mines to allow a new schedule based on the current status of the project.
There are 24,710 acres (100 square kilometers) in the concession which is at the
center of the Aqua and Pacaya twin volcano complex.
An office and staff are located in Guatemala City and a 17.2
acre plant site has been leased on land adjacent to the existing wells.
Discussions are taking place with several interested parties for the potential
sale of an equity interest in the El Ceibillo project. El Ceibillo, the first
development target on the concession, is located near the town of Amatitlan, in
a developed industrial zone immediately adjacent to the highway that connects
Guatemala City to the Port of San Jose on the Pacific coast.
During the first phase of drilling on well EC-1, the well 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). Due to the high temperature
gradient found in the lower section of the well, the decision was made to deepen
the well, and a second phase of drilling commenced on August 21, 2013. The final
depth of the well, reached on September 15, 2013 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 the data was provided to a third party consulting group with
specific expertise in volcanic geothermal resources for analysis and evaluation.
Planning is underway for another round of drilling to further delineate the El
Ceibillo resource. Subsequent to the end of the year, a temperature gradient
(TG) drilling program was initiated with a series of 200 meter (656 foot) deep
wells planned for the first quarter of 2014. Nine TG wells have been completed
and the results are being evaluated.
-16-
In early September 2013, the Guatemalan Ministry of the
Environment and Natural Resources (MARN) issued the Environmental License for
the construction and operation of the planned, first phase, 25 megawatt power
plant at the El Ceibillo site. The license is based on the Environmental Impact
Assessment Study that was submitted in December 2012, describing the initial
design of the 25 megawatt facility, and requires the submittal of final design
specifications for review by MARN prior to starting physical construction of the
plant. Additionally, the license requires compliance with all legal and
regulatory requirements under Guatemalan law, submittal of an air quality
monitoring plan, and that final design comply with the strict guidelines for
noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an
environmental bond of $344,850 Quetzals (approximately US $45,000) was posted
with the Ministry of Environment and Natural Resources.
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 binding Memorandum of Understanding (MOU) was signed on
October 18, 2012 with one of the largest power brokers in Central America. The
MOU establishes the framework for a PPA that includes a 15-year term for an
initially estimated 25 megawatts of power generation up to a maximum of 50
megawatts of power generation. The MOU includes a project power price that the
Company believes is competitive with the prevailing energy prices in the region.
Several conditions precedent must be met before the PPA is negotiated and
becomes effective, including confirming the geothermal reservoir by an
independent reservoir engineer, obtaining all required permits and
authorizations, and securing a project finance commitment.
The MOU may be terminated (i) as a result of the bankruptcy of
any of the parties, (ii) on January 1, 2015, unless such date is extended by
mutual agreement, because the construction of the project has not been initiated
and/or the commercial operation date has been moved beyond the date set out in
the PPA framework, or (iii) if the geothermal resource found lacks the
conditions to sustain a long-term commercial production that allows electric
power to be produced under the necessary conditions of profitability.
The El Ceibillo geothermal project area had nine previous wells
drilled into the geothermal concession drilled in the 1990s and having depths
ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had
adequate flow and temperature to support a direct use application. Six of the
wells had measured reservoir temperatures in the range of 365°F to 400°F and had
high conductive gradients that indicated rapidly increasing temperature with
depth.
-17-
Fluid samples and mineralization from the wells indicated the
existence of a high permeability reservoir below or near the existing well
field.
Gerlach Joint Venture
The Gerlach Joint Venture,
located adjacent to the town of Gerlach in Washoe County, Nevada is made up of
both private and BLM geothermal leases. The Peregrine well, a historic
exploration slim hole that encountered a lost circulation zone at a depth of 975
feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a
12.5 inch diameter well. Lost circulation was confirmed with three zones through
the 900 to 1,024 foot interval. The well was stopped at 1,070 feet total depth.
Temperature surveys and a short clean out flow test were conducted on the well.
The well flowed at an estimated 300-400 gallons per minute and the flowing
temperature was 208°F. Geochemistry indicates an average potential source
temperature of 374°F for the Gerlach site.
Drilling commenced on observation well 18-10a on October 30,
2011. The upper section of the well was drilled to 826 feet deep and an 8 inch
liner was cemented in place. The well was secured and the drill rig was moved
back to San Emidio. Temperature measurements in the well have provided the
highest measured temperature in the field to date at 268°F within 160 of
surface and a temperature gradient of 6.4°F per 100 in the bottom section of
the hole. There are two previously identified lost circulation targets at 1,600
and 2,800 deep that will be targeted when drilling is resumed.
Drilling resumed on well 18-10a on April 14, 2012 and was
stopped on April 18, 2012 at 1,943 feet deep. Circulation was lost in minor
zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an
isothermal temperature profile at 241°F which may indicate that higher
temperature fluid does not occur below the 18-10a well site.
A plan and budget has been developed to deepen well 18-10a to
intersect the lost circulation zone at 2,800 feet deep to provide temperature
information on the deep structure. Further work is dependent upon additional
funding from the partners.
Granite Creek, Nevada
The Granite Creek assets are
located about 6 miles north of Gerlach, Nevada along a geologic structure known
to host geothermal features including the Great Boiling Spring and the Fly Ranch
Geyser. A first stage gravity geophysical program was completed in the third
quarter of 2008 and will be used to evaluate the resource potential, and help
determine where to drill temperature-gradient exploration wells.
After a detailed review of the geologic setting, the lease
position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles). One
full lease and portions of the two remaining leases were relinquished to the
Bureau of Land Management.
-18-
Employees
At December 31, 2013, the Company had 46 full-time and 1 part
time employees (13 administrative and project development, and 34 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
under exploration or development are sites located in the Western Region of the
United States of America or in the Republic of Guatemala.
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.
-19-
The reservoir located in Raft River, Idaho is a proven
geothermal resource, and has a 13 net megawatt annual average capacity
geothermal power plant in operation (Raft River Energy I LLC). San Emidio,
Nevada is a proven geothermal resource, and has a 9.0 net megawatt geothermal
plant in operation. Neal Hot Springs, Oregon is a proven geothermal resource and
has a 22 net megawatt annual average geothermal power plant in operation. 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 Patents, Licenses, Permits,
Etc.
Neal Hot Springs.
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.
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.
The significant permits are in place for the
Raft River project and are necessary for continued operations:
|
1.
|
Geothermal well permits for production and injection
wells issued by the Idaho Department of Water Resources.
|
|
2.
|
A Conditional Use Permit for the first two power plants
was issued by the Cassia County Planning and Zoning Commission on April
21, 2005.
|
|
3.
|
The Idaho Department of Environmental Quality issued the
Air Quality Permit to Construct on May 26, 2006.
|
|
4.
|
A Wastewater Reuse Permit issued by the Idaho Department
of Environmental Quality on February 23, 2007 is being renewed with the
agency.
|
-20-
Seasonality of Business
The Company has been producing energy revenues under the terms
of three PPAs. These contracts specify favorable rate periods and levels of
production. The USG Nevada LLC (San Emidio, Nevada) plants contractual terms
provide for premium rates in the months from September to April. 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. 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 development operations;
therefore 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 of
working capital are typically low. The Company is expecting to be significantly
involved in 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 area of operations 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.
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
20% renewable. According to the Department of Energys Energy Efficiency and
Renewable Energy department, utilities in 34 states nationwide are providing
their customers with the opportunity to purchase green, renewable power through
premium pricing programs. As a result, we believe green power is an important
sub-market in the broader electric market, in which many power purchasers are
increasing or committing to increase their investments. Accordingly, the
conventional energy producers do not provide direct competition.
-21-
In the Pacific Northwest there are currently only two
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
baseload generation from geothermal, access to infrastructure for
deliverability, and a low "full life" cost will allow it to successfully compete
for long term power purchase agreements.
Factors that can influence the overall market for our product
include some of the following:
-
number of market participants buying and selling electricity;
-
availability and cost of transmission;
-
availability of low cost natural gas as an alternate fuel source
-
amount of electricity normally available in the market;
-
fluctuations in electricity supply due to planned and unplanned outages of
competitors generators;
-
fluctuations in electricity demand due to weather and other factors;
-
cost of fuel used by generators, which could be impacted by efficiency of
generation technology and fluctuations in fuel supply;
-
environmental regulations that impact us and our competitors;
-
availability of production tax credits and other benefits allowed by tax
law;
-
relative ease or difficulty of developing and constructing new facilities;
and
-
credit worthiness and risk associated with buyers.
Environmental Compliance
Raft River Project
The Raft River project is ideally
suited in a rural agricultural area. The nearest full time resident is located
over one mile south of the plant. The nearest part time resident is located
approximately one half mile north of the plant. Additionally, there are no
unique plant or animal communities in the area and no unique cultural or
environmental constraints.
Since operations have been initiated, key environmental reports
include:
|
1)
|
Monthly production and injection reports which are filed
with the Idaho Water Resources Department (IDWR);
|
|
2)
|
Quarterly ground water monitoring reports which are filed
with the Idaho Water Resources Department;
|
|
3)
|
Annual land application and cooling water quality reports
filed with the Idaho Department of Environmental
Quality.
|
-22-
|
4)
|
Annual Tier II reporting filed with the Idaho Bureau of
Homeland Security, Local Emergency Planning Committee, and the local fire
department.
|
The Companys most significant environmental compliance
investment is associated with water quality monitoring. The Company has added
five years of monthly, quarterly and annual water monitoring data to an already
substantial volume of historical data that was developed by the US Department of
Energy. The IDWR and Idaho Department of Environmental Quality concur with the
Companys findings that there is no impact on water quality from the geothermal
operation. The Companys private lands must be managed on an ongoing basis to
control weeds, manage riparian conditions of Raft River and maintain the
irrigation and fencing infrastructure. In order to facilitate our land
management obligations and minimize our labor and capital costs, the Company has
leased the grazing rights and cropland rights to a local landowner.
In summary, the Raft River project is in compliance with all
environmental permits and water quality monitoring requirements.
Neal Hot Springs
The Neal Hot Springs project is
also well situated in an area with only two nearby residents. There are no
unique plants or animal communities in the area and no unique cultural or
environmental constraints.
Because Neal is an air-cooled plant, the Companys only
environmental reporting 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.
Biannual water monitoring has been conducted since 2008 and will continue under
our ODEQ permitted geothermal water injection program.
As a result of the Department of Energys Loan Guarantee an
independent legal team has been reviewing all regulatory compliance requirements
for the project.
Adjoining rangelands are privately and federally managed. As a
result the Company has no rangeland or cropland management obligation. The
Company is able to focus staff resources on the day to day power plant
operations and management of the plant site.
The Neal project is in compliance with all environmental
permits and water quality monitoring requirements and has received no formal or
informal notices from any local, state, or federal agency. Post construction
reclamation and site clean-up continues to improve the overall appearance of the
project site.
San Emidio
The Companys San Emidio project is
located approximately 14 miles south of Gerlach Nevada and 63 air miles north
northeast of the Reno airport. The project site includes the Companys 9.0
megawatt water cooled power plant and 124,490 square feet of covered industrial
warehouse and offices. The nearest residence is over four miles from the plant
site.
-23-
The Companys regulatory reporting requirements include
quarterly and annual water and discharge reporting to the Department of
Environmental Protection.
San Emidio is in compliance with all environmental and
regulatory requirements and has received no formal or informal notices from any
local, state, or federal agency.
Gerlach and Granite Ranch
No operations are being
conducted on these two 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 region of the United States. The Raft River Energy I
LLC power plant is located in the southeastern part of the State of Idaho. The
Raft River unit 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,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
USG Oregon LLC located in
Eastern Oregon
|
$
|
15,566,409
|
|
$
|
2,329,030
|
|
USG Nevada LLC located in Northwestern Nevada
|
|
6,792,382
|
|
|
2,626,378
|
|
Raft River Energy I LLC
located in Southeastern Idaho
|
|
5,012,143
|
|
|
4,803,537
|
|
|
|
|
|
|
|
|
Total
energy and energy credits sales
|
$
|
27,370,934
|
|
$
|
9,758,945
|
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Available Information
We make available, free of charge through our Internet website
at http://www.usgeothermal.com, our annual report on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934, as soon as reasonably practicable after such material is
electronically filed with or furnished to the SEC. Information on our website is
not incorporated into this report and is not a part of this report.
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Governmental Approvals and Regulation
The Company is subject to federal and state regulation in
respect of the production, sale and distribution of electricity. Federal
legislation includes the Energy Policy Act of 2005, the Federal Power Act, and
the Energy Policy Act of 1992. The Company is defined as an independent power
producer under the rules and regulations of the Federal Energy Regulatory
Commission (FERC). As an independent power producer, the Companys operations
are supported by the Public Utility Regulatory Policies Act (PURPA) which
encourages alternative energy sources such as geothermal, wind, biomass, solar
and cogeneration. The State of Idaho also regulates electricity through the
Idaho Public Utility Commission (IPUC). Regulated utilities have the exclusive
right to distribute and sell electricity within their service area. They may
purchase electricity in the wholesale market from independent producers like the
Company. The IPUC, has the authority to establish rules and regulations
governing the sale of electricity generated from alternative energy sources.
Regulated utilities are required to purchase electricity on an avoided cost
basis from renewable energy facilities, or they may acquire purchased power
through bids or negotiated procedures.
On May 8, 2006, the Company submitted proposals to Idaho Power
in response to their Request for Proposal for Geothermal Power. The Company
was the preferred respondent and entered into power purchase contract
negotiations with Idaho Power. The Raft River Unit I Geothermal Power Plant
started up under a contract based on avoided costs which limited the output of
the plant to 10 average megawatts per month. Through subsequent contract
negotiations, the Company reduced the long-term price of power to Idaho Power,
and is now allowed to deliver as much power in any month as the plant is capable
of producing, up to a maximum hourly output of approximately 16 megawatts. The
annual average output capacity is on the order of 13 megawatts.
Because carbon regulation is anticipated to increase the cost
of power sourced from coal and because there are limited opportunities to
purchase baseload geothermal power, the Company has found that utilities across
the Western United States are eager to discuss PPAs.
On December 11, 2009, the Company signed a 25 megawatt
(maximum) contract with Idaho Power for the full output of the Neal Hot Springs
development in Oregon. The contract has received approval from the Idaho PUC.
The levelized cost of power for the project is $117.55/megawatt hours for 25
years after the plant startup.
On June 1, 2011, the Company announced the signing of a 25 year
power purchase agreement between its wholly owned subsidiary (USG Nevada LLC)
and NV Energy for the purchase of an annual average of up to 19.9 net megawatts
of energy produced from the San Emidio Geothermal Project located in Washoe
County, Nevada. This agreement is still subject to approval by the PUC.
The Company will be required to obtain various federal, state
and county approvals for construction of future geothermal facilities. These
approvals are issued by entities such as the U.S. Fish and Wildlife Service,
U.S. Environmental Protection Agency, State (Nevada, Oregon, Idaho) Departments
of Environmental Quality, Water Resources, State Historic Preservation Offices,
the applicable land management agency, and County Commissioners.
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Environmental Credits
In the past several years, there has been increased demand for
energy generated from geothermal resources in the United States as production
costs for electricity generated from geothermal resources have become
competitive relative to fossil fuel generation. This is partly due to newly
enacted legislative and regulatory incentives, such as production tax credits
and state renewable portfolio standards. State renewable portfolio standards
laws require that an increasing percentage of the electricity supplied by
electric utility companies operating in states with such standards will be
derived from renewable energy resources until certain pre-established goals are
met. We expect increasing demand for energy generated from geothermal and other
renewable resources in the United States as additional states adopt or extend
renewable portfolio standards.
As a green power producer, environmental-related credits,
such as renewable energy credits or carbon credits, are also available for sale
to power companies (to allow them to meet their green power requirements) or
to businesses which produce carbon based pollution. In all of the 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
Production Tax Credit (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 constructed after December 31, 2014 will
not be eligible to use this production tax credit. The federal production tax
credit available for geothermal energy in 2013 was 2.3 cents per kilowatt-hour.
Alternatively, certain projects under construction before the end of 2013, are
eligible to elect to take a 30% Investment Tax Credit (ITC) in lieu of the PTC.
The ITC may be taken after the plant has gone into operation and monetized. Both
PTC and ITC credits require a tax equity partner to monetize.
Renewable Energy Credits.
Renewable Energy Certificates,
or RECs, are tradable environmental commodities that represent proof that 1
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 1 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 MWs
average over the year). Holy Cross Energy began purchasing the renewable energy
credits associated with the Raft River Energy Unit I 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 Raft River Unit I after 2017 and Idaho Power retains the other
51%. We expect to receive a majority of the annual revenue from the ten-year renewable energy credits sales
arrangement with Holy Cross Energy.
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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 power purchase agreements for the existing San Emidio and
Neal Hot Springs power plants require the bundling of power sales and RECs.
Therefore, under these contracts all RECs are delivered with the net power sold
to the utility.
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Item 1A. Risk Factors
Investing in our common stock involves a high degree of
risk. You should carefully consider the following risk factors, as well as the
other information in this 10-K filing and related financial statements, before
deciding whether to invest in shares of our common stock. The occurrence of any
of the following risks, or other risks that are currently unknown or unforeseen
by us, or that we currently believe are not material, could harm our business,
financial condition, results of operation or growth prospects. In that case, you
may lose all or a portion of your investment.
We have organized the following risk factors into categories to
present related risks together. As a consequence of this, it is highly
recommended that you read this entire risk factor section completely. The risks
we have identified have been grouped into the following categories:
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Risks Related to Our Business;
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Risks Related to Our Growth;
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Risks Related to Our Power Purchase Agreements;
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Risks Related to Our Liquidity and Capital Resources;
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Risks Related to Government Regulation;
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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.
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Our geothermal reserves could decline in the future.
Declines greater than those that we expect would reduce our electricity
production levels, which could have a material adverse effect on our ability to
generate revenue.
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:
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significant changes in the characteristic of the geothermal resource;
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drilling in areas in and around our facilities by third parties; and
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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:
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seasonal variations in ambient weather conditions;
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variations in levels of production; and
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the completion of exploration and production projects.
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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:
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well blowouts;
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casing deformation;
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casing corrosion;
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uncontrollable flows of steam and hot water;
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pollution; and
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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.
Pursuant to the terms of our leases with the United States
Bureau of Land Management, which we refer to as 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.
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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.
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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. 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:
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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.
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.
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.
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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.
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.
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Actual costs of construction or operation of a power
plant may exceed estimates used in negotiation of power purchase and power
financing agreements.
If the actual costs of construction or operations
exceed the costs used in our economic model, the Company may not be able to
build the contemplated power plants, or if constructed, may not be able to
operate profitably. The 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 are 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.
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.
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Our drilling operations may be curtailed, delayed or cancelled
as a result of numerous factors, many of which are beyond our control, including
economic conditions, mechanical problems, title problems, weather conditions,
compliance with governmental requirements and shortages or delays of equipment
and services. If our drilling activities are not successful, we could experience
a material adverse effect on our future results of operations and financial
condition.
In addition to the substantial risk that wells drilled will not
be productive, or may decline in productivity after commencement of production,
hazards such as unusual or unexpected geologic formations, pressures, downhole
conditions, mechanical failures, blowouts, cratering, explosions, chemical
corrosion, uncontrollable flows of well fluids, pollution and other physical and
environmental risks are inherent in geothermal exploration and production. These
hazards could result in substantial losses to us due to injury and loss of life,
severe damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations.
Our exploration and development activities may not be
commercially successful.
Exploration activities involve numerous risks,
including the risk that no commercially productive reservoirs will be
discovered. In addition, the future cost and timing of drilling, completing and
producing wells is often uncertain. Furthermore, drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including:
-
unexpected drilling conditions; irregularities in formations; equipment
failures or accidents;
-
compliance with governmental regulations;
-
unavailability or high cost of drilling rigs, equipment or labor;
Our decisions to purchase, explore, develop and exploit
prospects or properties depend in part on data obtained through geophysical and
geological analyses, production data and engineering studies, the results of
which are often uncertain. Because of these factors, we could incur losses as a
result of exploratory drilling expenditures. Poor results from exploration
activities could have a material adverse effect on our future cash flows,
results of operations and financial position.
Our acquisition strategy could fail or present
unanticipated problems for our business in the future, which could adversely
affect our ability to make acquisitions or realize anticipated benefits of those
acquisitions.
Our growth strategy may include acquiring geothermal and
other renewable energy businesses and properties. We may not be able to identify
suitable acquisition opportunities or finance and complete any particular
acquisition successfully.
Furthermore, acquisitions involve a number of risks and
challenges, including:
-
diversion of managements attention;
-
the need to integrate acquired operations;
-
potential loss of key employees of the acquired companies;
-
greater geographic dispersion of employees;
-
the potential that we may make bad acquisitions;
-36-
-
potential lack of operating experience in a geographic market of the
acquired business; and
-
an increase in our expenses and working capital requirements.
Any of these factors could materially and adversely affect our
ability to achieve anticipated levels of cash flows from the acquired businesses
or realize other anticipated benefits of those acquisitions.
Development and expansion are dependent on the ability to
successfully complete drilling activity.
Drilling and exploration are
the main methods of establishing new reserves. However, drilling and exploration
may be curtailed, delayed or cancelled as a result of:
-
availability of equipment, particularly drilling rigs and well casing;
-
lack of acceptable prospective acreage;
-
inadequate capital resources;
-
weather;
-
compliance with governmental regulations; and
-
mechanical difficulties;
-
opposition to development.
Natural gas prices are volatile, and a decline in gas
prices would affect significantly the electricity prices we are able to obtain
future PPA contracts.
Development of our new plants depends on the
prices we are able to negotiate in our long term Power Purchase Agreements
(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:
-
domestic and foreign supply of oil and gas;
-
price and quantity of foreign imports;
-
actions of the Organization of Petroleum Exporting Countries and
state-controlled oil companies relating to oil price and production controls;
-
domestic and foreign governmental regulations;
-
political conditions in or affecting other oil producing and gas producing
countries, including the current conflicts in the Middle East and conditions
in South America and Russia;
-
weather conditions, as evidenced by recent hurricanes;
-
technological advances affecting oil and gas consumption;
-
overall U.S. and global economic conditions; and
-
price and availability of alternative fuels.
Further, oil 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 power purchase agreements, 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.
-37-
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. Our
foreign development is subject to regulation by various foreign governments and
regulatory authorities and are 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 are also
subject to significant political, economic and financial risks, which vary by
country, and include:
-
Changes in government policies or personnel;
-
Changes in general economic conditions;
-
Restrictions on currency transfer or convertibility;
-
Changes in labor relations;
-
Political instability and civil unrest;
-
Changes in the local electricity market;
-
Breach or repudiation of important contractual undertakings by
governmental entities; and
-
Expropriation and confiscation of assets and facilities.
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.
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.
-38-
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 power purchase agreements, will have the right to prematurely terminate
the power purchase agreement 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 power purchase
agreements, the purchaser may have the right to prematurely terminate the power
purchase agreement 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.
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.
-39-
Payments under our power purchase agreements may be
reduced if we are unable to forecast our production adequately
. Under
the terms of certain of our power purchase agreements, 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 power purchase agreements on terms favorable to us, or at all, which
would negatively impact our revenue
. The electrical power generation
industry, of which geothermal power is a sub-component, is highly competitive
and we may not be able to compete successfully or grow our business. We compete
in areas of pricing, grid access and markets. The industry in the Western United
States, in which the Raft River, Neal Hot Springs and San Emidio projects are
located, is complex as it is composed of public utility districts, cooperatives
and investor-owned power companies. Many of the participants produce and
distribute electricity. Their willingness to purchase electricity from an
independent producer may be based on a number of factors and not solely on
pricing and surety of supply. If we cannot enter into power purchase agreements
on terms favorable to us, or at all, it would negatively impact our revenue and
our decisions regarding development of additional properties.
Risks Related to Our Liquidity and Capital
Resources
-40-
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:
-
limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, entering into other renewable
energy businesses, or other purposes;
-
limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt;
-
increasing our vulnerability to general adverse economic and industry
conditions;
-
limiting our ability to or increasing the costs of refinance indebtedness;
and
-
limiting our ability to enter into marketing, hedging, optimization and
trading transactions by reducing the number of counterparties with whom we can
transact and the volume of those transactions.
We have a need for substantial additional financing and
will have to significantly delay, curtail or cease operations if we are unable
to secure such financing.
The Company requires substantial additional
financing to fund the cost of continued expansion of the Raft River (Idaho), San
Emidio (Nevada), Neal Hot Springs (Oregon) projects, and the development of the
Gerlach (Nevada), El Ceibillo (Guatemala) and Granite Creek Ranch (Nevada)
projects. Also, the Company requires funds for other operating activities, and
to finance the growth of our business, including the construction and
commissioning of power generation facilities. We may not be able to obtain the
needed funds on terms acceptable to us or at all. Further, if additional funds
are raised by issuing equity securities, significant dilution to our current
shareholders may occur and new investors may get rights that are preferential to
current shareholders. Alternatively, we may have to bring in joint venture
partners to fund further development work, which would result in reducing our
interests in the projects.
We may be unable to obtain the financing we need to
pursue our growth strategy in the geothermal power production segment, which may
adversely affect our ability to expand our operations.
When we identify
a geothermal property that we may seek to acquire or to develop, a substantial
capital investment will be required. Our continued access to capital, through
project financing or through a partnership or other arrangements with acceptable
terms is necessary for the success of our growth strategy. Our attempts to
secure the necessary capital may not be successful on favorable terms, or at
all.
Market conditions and other factors may not permit future
project and acquisition financings on terms favorable to us. Our ability to
arrange for financing on favorable terms, and the costs of such financing, are
dependent on numerous factors, including general economic and capital market
conditions, investor confidence, the continued success of current projects, the
credit quality of the projects being financed, the political situation in the
state in which the project is located and the continued existence of tax laws
which are conducive to raising capital. If we are unable to secure capital
through partnership or other arrangements, we may have to finance the projects
using equity financing which will have a dilutive effect on our common stock.
Also, in the absence of favorable financing or other capital options, we may
decide not to build new plants or acquire facilities from third parties. Any of these
alternatives could have a material adverse effect on our growth prospects and
financial condition.
-41-
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 at Raft River, Idaho, San Emidio, Nevada, and Neal
Hot Springs, Oregon and development of El Ceibillo, Guatemala 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:
-
make prepayments on or purchase indebtedness in whole or in part;
-
pay dividends to us or make other distributions to us thereby limiting our
ability to use available cash to pay dividends to stockholders, repurchase our
capital stock or make other investments in geothermal projects or other
renewable energy businesses;
-
make certain investments, including capital expenditures;
-
enter into transactions with affiliates;
-
create or incur liens to secure debt;
-
consolidate or merge with another entity, or allow one of our subsidiaries
to do so;
-
lease, transfer or sell assets and use proceeds of permitted asset leases,
transfers or sales;
-
incur dividend or other payment restrictions affecting certain
subsidiaries;
-
engage in certain business activities; and
-
acquire facilities or other businesses
-42-
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.
-43-
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 2013. 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 Bureau
of Land Management, as directed by the Energy Policy Act of 2005, require
competitive auction of all geothermal leases on Federal lands. Competitive
leasing is significantly increasing the cost of obtaining leases on Federal
land, is adding to the capital costs needed to develop geothermal projects, is
increasing the total electrical power prices needed to make a geothermal project
viable and is making it more difficult to acquire additional adjacent lands for
reservoir protection and exploration.
If Federal lands or any Federal involvement are included in any
geothermal development, requirements of the National Environmental Policy Act
("NEPA") will be triggered. Most of the geothermal resources in the United
States are located in the western states, where the Federal Government often is
the largest landowner. If a NEPA action is triggered, such as an Environmental
Impact Statement or Environmental Assessment, a project delay of one to two
years and a cost of $1,000,000 to $2,000,000 or more may be incurred while the
environmental permitting process is completed. NEPA not only can impact the
property where the geothermal resource is located, but includes the siting and
construction of transmission lines. Environmental legislation is evolving in a
manner that means stricter standards, and enforcement, fines and penalties for
non-compliance are more stringent. Environmental assessments of proposed
projects carry a heightened degree of responsibility for companies and
directors, officers and employees. The cost of compliance with changes in
governmental regulations has a potential to reduce the profitability of
operations.
In the states of Idaho, Nevada and Oregon, drilling for
geothermal resources is governed by specific rules. In Nevada drilling
operations are governed by the Division of Minerals (Nevada Administrative Code
Chapter 534A); in Idaho by the Idaho Department of Water Resources (IDAPA 37
Title 03 Chapter 04); and in Oregon by the Division of Oil, Gas and Mineral
Industries (Division 20 Geothermal Regulation). These rules require drilling
permits and govern the spacing of wells, rates of production, prevention of
waste and other matters, and, may not allow or may restrict drilling activity,
or may require that a geothermal resource be unitized (shared) with adjoining
land owners. Such laws and regulations may increase the costs of planning,
designing, drilling, installing, operating and abandoning our geothermal wells,
the power plant and other facilities. State environmental requirements and
permits, such as the Idaho Department of Environmental Quality, Air Quality
Permit to Construct, include public disclosure and comment. It is possible that
a legal protest could be triggered through one of the permitting processes that
would delay construction and increase cost for one of our projects. The state of Oregon has an Energy Facility Siting Council that must
issue a site certificate for any geothermal energy facilities of 35 MWs or
higher.
-44-
Because of these state and federal regulations, we could incur
liability to governments or third parties for any unlawful discharge of
pollutants into the air, soil or water, including responsibility for remediation
costs. We could potentially discharge such materials into the environment:
-
from a well or drilling equipment at a drill site;
-
leakage of fluids or airborne pollutants from gathering systems,
pipelines, power plant and storage tanks;
-
damage to geothermal wells resulting from accidents during normal
operations; and
-
blowouts, cratering and explosions.
Because the requirements imposed by such laws and regulations
are frequently changed, we cannot assure you that laws and regulations enacted
in the future, including changes to existing laws and regulations, will not
adversely affect our business by increasing cost and the time required to
explore and develop geothermal projects. In addition, because our Raft River and
San Emidio 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:
-
actual or anticipated variations in our reserve estimates and quarterly
operating results;
-
changes in electricity prices;
-
changes in our funds from operations or earnings estimates;
-
publication of research reports about us or the exploration and production
industry;
-
increases in market interest rates which may increase our cost of capital;
-45-
-
changes in applicable laws or regulations, court rulings and enforcement
and legal actions;
-
changes in market valuations of similar companies;
-
adverse market reaction to any increased indebtedness we incur in the
future;
-
additions or departures of key management personnel;
-
actions by our stockholders;
-
speculation in the press or investment community;
-
large volume of sellers of our common stock pursuant to our resale
registration statement with a relatively small volume of purchasers; and
-
general market and economic conditions.
The market price of our common stock could be volatile,
which could cause the value of your investment to decline.
Securities
markets worldwide experience significant price and volume fluctuations. This
market volatility, as well as general economic, market or political conditions,
could reduce the market price of our common stock in spite of our operating
performance. In addition, our operating results could fall short of the
expectations of market analysts and investors, and in response, the market price
of our common stock could decrease significantly. You may be unable to resell
your shares of our common stock at or above the initial offering price.
The market for our common stock is volatile, having ranged in
the year ended December 31, 2013, from a low of $0.31 to a high of $0.59 on the
NYSE MKT, and from a low of CDN$0.31 to a high of CDN$0.65 on the TSX. The
trading price of our common stock on the NYSE MKT and on the 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.
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 Securities and Exchange Commission (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.
-46-
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.
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.
-47-
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.
-48-
Item 2. Property
The Company has interests in three areas in the Western United
States. The properties include the Raft River area located in southeastern
Idaho, the Neal Hot Springs area located in eastern Oregon (near the
Idaho/Oregon border), and three properties in northwestern Nevada. The
properties in northwestern Nevada include San Emidio, Gerlach and Granite Creek.
The Company has three commercial power plants. The Neal Hot Springs geothermal
plant achieved commercial operation on November 16, 2012. The San Emidio plant
was acquired in the Empire Acquisition in May 2008. The facility was replaced
with a 9.0 megawatt power plant located on private land. San Emidio Phase 1
achieved commercial operation in early 2012. Raft River Unit I became
commercially operational on January 3, 2008.
REGIONAL LOCATION MAP
-49-
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 geothermal power plant was developed by
USG Oregon LLC, and is currently in operation at this site.
The project has four production wells (NHS-1, 2, 5, and 8) and
nine injection wells (NHS-3, 4, 7, 9, 10, 11, 12, 13, 14) at the project.
Lease/Royalty Terms
Cyprus Gold Exploration
Corporation.
The lease for Cyprus 50% mineral ownership on 4,960 acres
located in Malheur County, Oregon is dated January 24, 2007, has a primary term
of 10 years, and expires January 24, 2017. Annual rental of $4,000 per year was
paid through 2012 and is considered a pre-paid production royalty. The 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 based on electricity delivery under our Idaho
Power Purchase Agreement.
-50-
JR Land and Livestock.
The lease for JR Land and
Livestocks 25% mineral ownership on 4,960 acres located in Malheur County,
Oregon is dated January 24, 2007, has a primary term of 10 years and continues
for as long as royalties are paid. Minimum rental was paid through 2012 and is
considered a pre-paid production royalty. The lease agreement defines a royalty
rate based upon 3% of the gross proceeds for the first 5 years of commercial
production, 4% of gross proceeds for the next 10 years, and 5% of the gross
proceeds thereafter. As of January 2013 USG Oregon LLC began paying monthly
royalties based on electricity delivery under our Idaho Power Purchase
Agreement.
USG Oregon LLC.
USG Oregon LLC owns the remaining
mineral rights for the project. They include a 25% ownership and a 50% ownership
depending on the parcel location.
All power production is committed under a 25 year term power
purchase agreement with Idaho Power Company for purchase of up to 25 megawatts
of electricity that was signed in December 2009. Beginning 2012, the flat energy
price is $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
In 2008, the Company acquired a 3.6 MW operating geothermal
power plant and approximately 30,734.21 acres (48.0 square miles) of geothermal
energy leases and certain ground water rights all located north of Reno, Nevada.
The assets are comprised of two locations: the San Emidio assets and the
Gerlach/Granite Creek assets. The San Emidio assets are located in the San
Emidio Desert, Washoe County, Nevada and include the geothermal power project,
approximately 22,944 acres (35.9 square miles) of geothermal leases, and ground
water rights used for cooling water. The Gerlach assets are comprised of
approximately 3,415 acres (5.3 square miles) of BLM geothermal leases located
about 1 mile north of Gerlach, Nevada. The Granite Creek assets are comprised of
approximately 5,414 acres (8.5 square miles) of BLM geothermal leases located
about 7 miles north of Gerlach, Nevada. The Gerlach and Granite Creek assets are
along a geologic structure known to host geothermal features including the Great
Boiling Spring and the Fly Ranch Geyser.
The 3.6 -MW geothermal power plant produced power from 1987
until December 2011. The power plant was constructed in 1986 with commercial
power generation beginning in 1987. The original plant was replaced with the San
Emidio Phase 1 repower project. A new 8.6 MW facility located on private land
owned by USG Nevada was completed in 2012. Phase 1 repowering was completed
utilizing the existing production and injection wells and achieved commercial
operations in early 2012. USG Nevada is investigating the opportunity for
expansion under Phase II in the northern area of the geothermal field.
All power production is committed under a power purchase
agreement with Sierra Pacific Power Company d/b/a NV Energy for 19.4 megawatts
of electricity. The PPA has a 25 year term with a base price of $89.75 per
megawatt-hour, and a 1 percent annual escalation rate.
-51-
Lease/Royalty Terms
BLM Leases.
At the
closing of the Empire acquisition approximately 21,905 acres of federal (BLM)
geothermal leases and geothermal rights located in the San Emidio Desert were
assigned to USG Nevada. The lease contracts have primary terms of 10 years. Per
federal regulations applicable for the contracts, the lessee has the option to
extend the primary lease term another 10 years, under two extension periods, at
5 years each, as long as the lessee is maintaining production at commercial
quantities. The leases require the lessee to conduct operations in a manner that
minimizes adverse impacts to the environment.
The Company received BLM approval and designation of a
Geothermal Unit and a Participating Area in 2011. The geothermal unit allows
USG to hold all geothermal resources within the valley without the risk of lease
expiration and allows exploration and development costs to be apportioned
between and for the benefit of maintaining all the geothermal leases within the
Unit. The first designated participating area encompasses the currently operated
southern production zone. Royalties are portioned to the mineral owners on a
percentage of ownership within the participating area. The Unit Area and the
Participating Area are key components for long term lease retention and resource
development. The federal royalty is calculated based upon the percentage of
acres of federal geothermal resources within the participating area and
production royalty of 10.0% of the value of the resources prior to production
cost deductions as required by a formula established by the Minerals Management
Service.
-52-
USG evaluated our lease position and several years of new
geologic data and determined that some leases should not be renewed. The 2013
geothermal leases are detailed as follows:
Lease No.
|
Next Renewal Date
|
Acres
|
Annual Rate
|
San Emidio
|
N63004
|
9/30/2018
|
1,280
|
$ 5,120
|
N63005
|
9/30/2018
|
1,279
|
5,116
|
N63006
|
9/30/2018
|
1,920
|
7,680
|
N63007
|
9/30/2018
|
1,920
|
7,680
|
N75233
|
11/1/2016
|
1,868
|
3,738
|
N75552
|
11/1/2017
|
2,560
|
10,240
|
N75555
|
11/1/2017
|
960
|
3,840
|
N75557
|
11/1/2017
|
1,280
|
5,120
|
N75558
|
11/1/2017
|
680
|
2,720
|
N42707
|
Indefinite
|
1,797
|
*
|
N47169
|
12/1/2017
|
3
|
n/a
|
N74196
|
4/30/2017
|
640
|
2,560
|
N57437
|
9/30/2018
|
640
|
2,560
|
Gerlach
|
N55718
|
6/30/2017
|
1,252
|
10,016
|
N75228
|
10/31/2016
|
1521
|
4,328
|
|
|
|
|
* - royalty based.
|
Raft River, Idaho
The Raft River project is in southeastern Idaho, approximately
55 miles southeast of Burley, the county seat of Cassia County. Burley has a
population of about 11,000 and is the local agricultural and manufacturing
center for the region, providing a full range of light to heavy industrial
services.
A commercial airport is located 90 miles to the northeast in
Pocatello, Idaho. Pocatello, population 53,000, is a regional center for
agriculture, heavy industry (mining, phosphate refining), technology and Idaho
State University. Malta, a town with a population of approximately 180, is 12
miles north of the project site where basic services, fuel, and groceries are
available. Year-round access to the project from Burley is via Interstate
Highway 84 south to State Highway 81 south, then east on the Narrows Canyon
Road, an improved county road.
The Raft River project currently consists of ten parcels
(generally referred to as the U.S. Geothermal Property, the Crank Lease, the
Newbold Lease, the Jensen Investments Leases, the Stewart Lease, the Bighorn
Mortgage Lease, the Doman Lease, the Griffin Lease, and the Glover Lease)
comprising 783.93 acres of fee land and 4,736.79 acres of contiguous leased
geothermal rights located on private property in Cassia County, Idaho. All
parcels are defined by legal subdivision or by metes and bounds survey
description. The ten parcels are as follows:
-53-
The U.S. Geothermal Property - Idaho.
The U.S.
Geothermal Property is comprised of four separate properties that total 1,723.93
acres: the Vulcan, Elena Corporation, Dewsnup and the Wilcox Ranch Properties.
The Vulcan Property includes both surface and geothermal rights and consists of
two parcels. The first parcel has a total area of approximately 240 acres and
three geothermal wells (RRGE-1, RRGP-4 and RRGP-5) are located on this parcel.
The second parcel has a total area of approximately 320 acres, and three
additional geothermal wells (RRGE-3, RRGI-6 and RRGI-7) are located on this
parcel. A fourth well, RRGE-2, although located on the property covered by the
Crank lease, was acquired by the Company from a local rancher. The Wilcox Ranch
includes 940 acres of agricultural and range lands adjacent to Raft River that
provides cooling water.
The Elena Property is comprised of surface and geothermal
rights to approximately 100 acres of property, excluding the oil and gas rights
to the property. The property is contiguous to other properties owned or leased
by the Company.
The Dewsnup Property is comprised of the surface and geothermal
rights to approximately 123.93 acres of property, excluding the oil and gas
rights to the property, but including all surface water rights. The property is
contiguous to other properties owned or leased by the Company.
The Crank Lease.
The Crank lease covers approximately
160 acres of mineral and geothermal rights, with right of ingress and egress.
The Newbold Lease.
The Newbold lease covers
approximately 20 acres of both surface and geothermal rights.
The Jensen Investments Leases.
The first Jensen
Investments lease covers approximately 2,954.75 acres of geothermal rights only.
It is contiguous with the Vulcan Property and property covered by the Crank and
Stewart leases. The second Jensen Investments lease covers approximately 44.5
acres of surface and geothermal rights, and is contiguous with property covered
by the first Jensen lease.
The Stewart Lease.
The Stewart Lease covers
approximately 317.54 acres on two adjoining parcels. Parcel 1 contains
approximately 159.04 acres and includes surface and geothermal rights. Parcel 2
contains approximately 158.50 acres and only covers surface rights. The
underlying geothermal rights for Parcel 2 are subject to the first Jensen
Investments Lease.
The Bighorn Mortgage Lease.
The Bighorn Mortgage lease
covers approximately 280 acres of surface and geothermal rights.
The Doman Lease.
The Doman lease covers approximately
640 acres of surface and geothermal rights, excluding oil and gas rights.
The Griffin Lease.
The Griffin lease contains
approximately 160 acres of geothermal rights.
The Glover Lease.
The Glover lease contains
approximately 160 acres of geothermal rights.
-54-
BLM Lease.
The geothermal resources lease agreement with
the United States Department of Interior Bureau of Land Management (BLM) was
entered into on August 1, 2007. The lease is for approximately 1,685 acres of
land located contiguous to the Raft River Property in southeastern Idaho.
Raft River Energy Unit I
Unit I at Raft River became commercially operational on January
3, 2008. As a result of the project financing for Unit I of the Raft River
project, the Company contributed over $17.9 million in cash and property to Raft
River Energy I LLC, the Unit I project joint venture company. Raft River
Holdings, an affiliate of Goldman Sachs Group, contributed approximately $34
million to the project. Property assigned to Raft River Energy by the Company
includes seven production and injection wells, seven monitoring wells, the
Stewart lease, the Crank lease, the Newbold lease, the Doman lease, and the
Glover lease. Permits and contracts have also been assigned to Raft River Energy
for Unit I.
Although significant detail has been provided about each lease
area, the economics of the project is based on the resource. All economic
discussions, including future phases, are based at the project level rather than
at the lease level.
-55-
Lease/Royalty Terms
The Crank lease, the Newbold
lease, the Jensen Investments leases, the Bighorn Mortgage lease, the Doman
lease, the Griffin lease and the Glover lease have royalties payable under the
following terms:
|
(a)
|
Energy produced, saved and used for the generation of
electric power, which is then sold by lessee, has a royalty of ten percent
(10%) of the net proceeds to RREI.
|
|
(b)
|
Energy produced, saved and sold by lessee, then used by
the purchaser for generation of electric power, has a royalty of ten
percent (10%) of the market value.
|
|
(c)
|
Energy produced, which is used for any purpose other than
the generation of electricity has a royalty of five percent (5%) of the
gross proceeds.
|
The Stewart lease has production royalties payable under the
following terms:
|
(a)
|
Energy produced, saved and sold by the lessee, then used
by the purchaser for generation of electric power, has a royalty of ten
percent (10%) of the market value of the electric power.
|
|
(b)
|
Energy produced, saved and used for the generation of
electric power, which is then sold by Lessee, has a royalty of three
percent (3%) of the market value of the electric power.
|
|
(c)
|
Energy produced, which is used for any purpose other than
the generation of electricity has a royalty of five percent (5%) of the
gross proceeds.
|
All of the leases may be extended indefinitely as long as
production is maintained from the lease either individually or as a geothermal
unit. For each lease other than the Crank Lease (see below), once production is
achieved the amounts due annually will be the greater of the production royalty
and the minimum payment for the last year of the primary term. All payments
under the leases are made annually in advance on the anniversary date of the
particular lease. In addition, the following lease and other royalty terms apply
to the individual leases:
The Crank Lease.
The lease agreement with Janice Crank
was originally entered into June 28, 2002, and had a primary term of 5 years.
After U.S. Geothermal Inc. provided evidence to the lessor that the well
(RRGE-2) located on lessors property was not owned by the lessor (but instead
was included in the Vulcan Property), a new lease was entered into on June 28,
2003, which excluded the ownership of RRGE-2, with a four-year initial term.
There is a minimum annual production royalty of $18,000. The minimum amount that
will be payable over the course of the leases is $45,000.
The Newbold Lease
. The Company leases this property
pursuant to a lease agreement with Jay Newbold dated March 1, 2004. The Newbold
lease has a primary term of 10 years (through February 28, 2014) and is extended
indefinitely so long as production from the geothermal field is maintained.
Minimum lease payments are as follows:
-
Years 1-5: $10.00 per acre or $200 per year
-
Years 6-10: $15.00 per acre or $300 per year
-
Extended: $15.00 per acre or $300 per year
The Jensen Investments Leases.
The first Jensen
Investments lease was originally with Sergene Jensen, as lessor, is dated July
11, 2002, and has a primary term of 10 years. In September 2005, the property subject to the lease was conveyed and the lease
was assumed by Jensen Investments, Inc. Minimum lease payments are as follows:
-56-
-
Years 1-5: $2.50 per acre or $7,386.88 per
year
-
Years 6-10: $3.00 per acre or $8,864.25 per year
The minimum amount that will be payable over the course of the
lease is $81,256. The second Jensen Investments lease, with Jensen Investments,
Inc., expires in 2013. Minimum lease payments are as follows:
-
Years 1-5: $2.50 per acre or $111.25 per
year
-
Years 6-10: $3.00 per acre or $133.50 per year
The minimum amount that will be payable over the course of the
lease is $1,224. The Jensen Investments leases are being renewed and
consolidated to reflect the project needs and the term of the power purchase
agreement.
The Stewart Lease.
The Stewart lease, with Reid and Ruth
Stewart, is dated December 1, 2004, and has a primary term of 30 years. Minimum
lease payments are as follows:
-
Year 1: $8,000
-
Year 2: $5,000
-
Year 3-30: $5,000 plus an annual increase of 5% per
year.
The minimum amount that will be payable over the course of the
lease is $319,614.
The Bighorn Mortgage Lease.
The Bighorn Mortgage lease,
with Conrad Irrevocable Trust, is dated July 5, 2005, and has a primary term of
10 years. Minimum lease payments are as follows:
-
Year 1-5: $1,400
-
Year 6-10: $2,100
The minimum amount that will be payable over the course of the
lease is $17,500.
The Doman Lease.
The Doman lease, with Dale and Ronda
Doman, is dated June 23, 2005, and has a primary term of 10 years. Minimum lease
payments are as follows:
-
Year 1-5: $1,600
-
Year 6-10: $3,200
The minimum amount that will be payable over the course of the
lease is $24,000.
The Griffin Lease.
The Griffin lease, with Michael and
Cleo Griffin, Harlow and Pauline Griffin, Douglas and Margaret Griffin, Terry
and Sue Griffin, Vincent and Phyllis Jorgensen, and Alice Mae Griffin Shorts, is
dated June 23, 2005, and has a primary term of 10 years. Minimum lease payments
are as follows:
-
Year 1: $1,600
-
Year 2-5: $800
-
Year 6-10: $1,200
The minimum amount that will be payable over the course of the
lease is $10,800.
-57-
The Glover Lease.
The Glover lease, with Philip Glover,
is dated January 25, 2006, and has a primary term of 10 years. Minimum lease
payments are as follows:
-
Year 1: $2,100
-
Year 2-5: $1,600
-
Year 6-10: $2,400
The minimum amount that will be payable over the course of the
lease is $20,500.
The total minimum amount payable under all of the leases during
their primary terms is $522,393. The above listed lease payments are payable
annually in advance, and are current through the 2012 lease year. The leases can
be renewed for extended periods as long as the power plant continues to produce
power.
BLM Lease.
The lease entered into in August of 2007 has
a primary term of 10 years. After the primary term, the Company has the right to
extend the contract in accordance with regulation 43 CFR subpart 3207. The lease
calls for annual payments of $3,502 including processing fees. The royalty rate
is based upon 10% of the value of the resource at the well head. The amounts are
calculated according to a formula established by Minerals Management Service
(MMS).
Gerlach, Nevada
In May 2008, the Company entered into a joint venture agreement
with Gerlach Green Energy LLC of Nevada and formed a limited liability company
named Gerlach Geothermal LLC. The joint venture owns geothermal rights for 3,615
acres (5.6 square miles) located in northwestern Nevada near the town of
Gerlach. The development target is the Gerlach geothermal system. The BLM
approved and designated a Geothermal Unit. The geothermal unit allows the
Company to hold all geothermal resources within the valley without the risk of
lease expiration and allows exploration and development costs to be allocated
between and for the benefit of maintaining all the geothermal leases within the
Unit. The first designated participating area will be established after the
geothermal resource has been delineated and a production strategy is
implemented. The Unit Area and the Participating Area are key components for
long term lease retention and resource development.
Lease/Royalty Terms
BLM Leases.
The Gerlach
Geothermal LLC assets are comprised of two BLM geothermal leases and one private
lease totaling 3,615 acres. Both BLM leases have a royalty rate that 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.
One BLM lease has an overriding royalty commitment to the original lessor 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.
-58-
Granite Creek, Nevada
The Granite Creek assets are comprised of approximately 2,443
acres (3.8 square miles) of BLM geothermal leases located about 6 miles north of
Gerlach, Nevada along a geologic structure known to host geothermal features
including the Great Boiling Spring and the Fly Ranch Geyser.
Lease/Royalty Terms
BLM Leases.
The Company
has two geothermal leases with the BLM. The leases are for approximately 2,445
acres of land and geothermal water rights located in the northwestern Nevada.
Federal lease N66404 is comprised of 1,563 acres and lease N66403 is 882 acres.
The leases have primary terms of 10 years. Per federal regulations the lessee
has the option to extend the primary lease terms another 40 years as long as the
lessee maintains production in commercial quantities. The leases require an
annual lease payment of $2,443, and have been extended as required by BLM
regulations.
-59-
Republic of Guatemala
The Company successfully acquired a geothermal concession in
the Republic of Guatemala. The concession consists of 24,710 acres (100 square
kilometers) and is located 14 miles southwest of Guatemala City, the capital.
Nine wells with depths ranging from 560 to 2,000 feet (170 to 610 meters) were
drilled in the El Ceibillo resource area within the concession area during the
l990s, with a few of those wells having adequate temperature and flow to support
a direct use application. Six of the wells have measured reservoir temperatures
in the range of 365 to 400°F (185 to 204°C). Fluid sample analysis and the
mineralogy associated with drill cuttings suggest the existence of a deeper,
higher permeability reservoir with temperature potential of 410 to 526°F (210 to
274°C).
Boise Administration Office, Idaho
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 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 $6,418 that is adjusted annually
according to the cost of living index. The contract includes a 5 year extension
option.
-60-
Item 3. Legal Proceedings
As of March 25, 2014, management is not aware of any material
current or pending legal proceedings in which the Company is a party, as
plaintiff or defendant, or which involve any of its properties.
Item 4. Mine Safety Disclosures
Not applicable.
-61-
PART II
Item 5. Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities
NYSE MKT
On
April 14, 2008,
the
Companys
common stock began trading on the NYSE MKT, under
the trade symbol HTM.
The following table sets forth information relating to the
trading of our common stock from January 1, 2012 through December 31, 2013.
Sale Prices on the NYSE MKT
|
|
High
|
Low
|
Year Ended December 31, 2013
|
($)
|
($)
|
First
Quarter
|
0.37
|
0.31
|
Second
Quarter
|
0.43
|
0.32
|
Third
Quarter
|
0.59
|
0.36
|
Fourth Quarter
|
0.50
|
0.37
|
|
|
|
Year Ended December 31, 2012
|
|
|
First
Quarter
|
0.65
|
0.34
|
Second
Quarter
|
0.51
|
0.35
|
Third
Quarter
|
0.39
|
0.30
|
Fourth Quarter
|
0.44
|
0.27
|
TSX
The Companys common stock began trading
on the Toronto Stock Exchange (TSX) on October 1, 2007, under the symbol
GTH. The following table sets forth information relating to the trading of the
Companys common stock on the TSX:
Sale Prices on the TSX
|
|
High
|
Low
|
Year Ended December 31, 2013
|
(CDN$)
|
(CDN$)
|
First
Quarter
|
0.39
|
0.31
|
Second
Quarter
|
0.44
|
0.33
|
Third
Quarter
|
0.65
|
0.36
|
Fourth Quarter
|
0.53
|
0.39
|
|
|
|
Year Ended December 31, 2012
|
|
|
First
Quarter
|
0.63
|
0.34
|
Second
Quarter
|
0.50
|
0.36
|
Third
Quarter
|
0.40
|
0.30
|
Fourth Quarter
|
0.45
|
0.29
|
As of March 21, 2014, we had approximately 16,500 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
-62-
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.
Item 6. Selected Financial Data
|
For the Years Ended
December 31,
|
For the Fiscal Years Ended
March 31,
|
2013
|
2012
|
2012
|
2011
|
2010
|
Operating Revenues
|
$ 27,370,934
|
$9,758,946
|
$ 5,894,113
|
$3,253,545
|
$ 2,579,152
|
Operating Expenses
|
23,240,285
|
14,090,471
|
16,522,690
|
7,292,895
|
8,562,345
|
Income (Loss) from
Continuing
Operations
|
4,130,649
|
(4,331,525)
|
(6,222,129
|
(3,954,416)
|
(5,838,850)
|
Income (Loss) attributable to
U.S.
Geothermal Inc.
|
1,946,579
|
(2,958,567)
|
|
|
|
Income (Loss) per share
attributable
to U.S. Geothermal Inc.
|
0.02
|
(0.03)
|
(0.07)
|
(0.05)
|
(0.09)
|
Cash dividends declared and paid
per
common share
|
-
|
-
|
-
|
-
|
-
|
|
As of December 31,
|
As of March 31,
|
2013
|
2012
|
2012
|
2011
|
2010
|
Total Assets
|
$ 232,765,297
|
$ 240,496,096
|
$ 219,030,868
|
$ 85,322,968
|
$ 65,727,861
|
Total Long-term
Obligations (1)
|
99,247,344
|
104,318,206
|
69,495,470
|
18,326,802
|
2,080,859
|
(1)
|
Long-term obligations represent the stock compensation
payable, a convertible loan, construction 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, 2013 and
2012, long-term obligations did not include stock compensation
payable.
|
-63-
|
Income (loss)
per share
attributable
to
U.S.
Geothermal
Inc.
|
Operating
Revenues
|
Gross Profit
(Loss)
|
Income (Loss)
from
Operations
|
Net Loss
Attributable to
U.S.
Geothermal,
Inc.
|
Fiscal Year Ended March
31,
2011
|
|
|
|
|
|
1
st
Quarter
|
(0.02)
|
752,247
|
752,247
|
(1,491,924)
|
(1,474,560)
|
2
nd
Quarter
|
(0.01)
|
838,688
|
838,688
|
(1,003,950)
|
(966,961)
|
3
rd
Quarter
|
(0.01)
|
852,515
|
852,515
|
(843,584)
|
(825,194)
|
4
th
Quarter
|
(0.01)
|
810,095
|
810,095
|
(699,892)
|
(687,701)
|
Fiscal Year Ended March
31,
2012
|
|
|
|
|
|
1
st
Quarter
|
(0.03)
|
1,397,975
|
(1,110,296)
|
(4,633,355)
|
(2,341,024)
|
2
nd
Quarter
|
(0.01)
|
1,689,609
|
(336,683)
|
(1,467,778)
|
(922,043)
|
3
rd
Quarter
|
(0.02)
|
1,647,442
|
(1,876,779)
|
(2,534,598)
|
(1,315,339)
|
4
th
Quarter
|
(0.01)
|
1,159,087
|
(1,061,775)
|
(2,415,858)
|
(1,643,723)
|
Year Ended December 31,
2012
|
|
|
|
|
|
1
st
Quarter
|
(0.01)
|
1,159,087
|
(1,061,775)
|
(2,415,858)
|
(1,643,723)
|
2
nd
Quarter
|
(0.01)
|
1,280,949
|
(52,235)
|
(1,827,157)
|
(930,870)
|
3
rd
Quarter
|
(0.00)
|
2,019,749
|
270,012
|
(836,581)
|
(766,100)
|
4
th
Quarter
|
(0.01)
|
5,299,161
|
966,804
|
748,072
|
382,126
|
Year Ended December 31,
2013
|
|
|
|
|
|
1
st
Quarter
|
0.01
|
7,086,990
|
4,102,509
|
2,235,079
|
1,388,523
|
2
nd
Quarter
|
(0.01)
|
4,973,076
|
1,012,227
|
(1,966,627)
|
(1,376,359)
|
3
rd
Quarter
|
0.00
|
5,760,495
|
2,461,352
|
186,198
|
(28,137)
|
4
th
Quarter
|
0.02
|
9,550,373
|
5,635,824
|
3,675,999
|
1,962,552
|
Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations
The following is a list of projects that are in operation,
under development or under exploration. Projects in operation have producing
geothermal power plants. Projects under development have at least a geothermal
resource discovery or may have wells in place, but require the drilling of new
or additional production and injection wells in order to supply enough
geothermal fluid sufficient to operate a commercial power plant. Projects under
exploration do not have a geothermal resource discovery occurrence yet, but have
significant thermal and other physical evidence that warrants the expenditure of
capital in search of the discovery of a geothermal resource. Due to inflation
and marketplace increases in the costs of labor and construction materials,
previous estimates of property development costs may be low.
-64-
For the year ended December 31, 2013, the Company was focused
on:
|
1)
|
Operating and optimizing Neal Hot Springs, San Emidio and
Raft River power plants;
|
|
2)
|
Closing the sale of the Business Energy Tax Credit for
Neal Hot Springs;
|
|
3)
|
Drilling of well OW-12 and reworking well 61-21 for San
Emidio Phase II;
|
|
4)
|
Testing and evaluating well EC-1 at El
Ceibillo;
|
|
5)
|
Permitting new wells at San Emidio; and
|
|
6)
|
The evaluation of potential new geothermal projects and
acquisition opportunities.
|
Projects Under Development
|
|
|
|
|
|
Estimated
|
|
|
|
|
Target
|
Projected
|
Capital
|
|
|
|
|
Development
|
Commercial
|
Required
|
|
Project
|
Location
|
Ownership
|
(Megawatts)
|
Operation Date
|
($million)
|
Power Purchaser
|
El Ceibillo Phase I
|
Guatemala
|
100%
|
25
|
4
th
Quarter 2015
|
$135
|
MOU
|
San Emidio Phase II
|
Nevada
|
100%
|
11
|
4
th
Quarter 2015
|
$55
|
NV Energy
|
Additional Properties
|
Project
|
|
Location
|
|
Ownership
|
|
Target Development (Megawatts)
|
Gerlach
|
|
Nevada
|
|
60%
|
|
TBD
|
Granite Creek
|
|
Nevada
|
|
100%
|
|
TBD
|
El Ceibillo Phase II
|
|
Guatemala
|
|
100%
|
|
25
|
San Emidio Phase III
|
|
Nevada
|
|
100%
|
|
17.2
|
|
|
|
|
|
|
|
Neal Hot Springs II
|
|
Oregon
|
|
100%
|
|
28
|
Raft River Unit II
|
|
Idaho
|
|
100%
|
|
26
|
Raft River Unit III
|
|
Idaho
|
|
100%
|
|
32
|
Resource Details
|
|
|
Property Size
|
|
|
|
|
|
|
Property
|
|
(square miles)
|
|
Temperature (
º
F)
|
|
Depth (Ft)
|
|
Technology
|
Raft River
|
|
10.8
|
|
275-302
|
|
4,500-6,000
|
|
Binary
|
San Emidio
|
|
35.8
|
|
289-316
|
|
1,500-3,000
|
|
Binary
|
Neal Hot Springs
|
|
9.6
|
|
311-347
|
|
2,500-3,000
|
|
Binary
|
Gerlach
|
|
5.6
|
|
338-352
|
|
2,000-3,000
|
|
Binary
|
Granite Creek
|
|
3.8
|
|
TBD
|
|
TBD
|
|
Binary
|
El Ceibillo
|
|
38.6
|
|
410-526
|
|
1,800-TBD
|
|
Steam
|
Projects in Operation
|
|
|
|
|
|
|
Generating
|
|
|
|
Contract
|
Project
|
|
Location
|
|
Ownership
|
|
Capacity (megawatts)
|
|
Power Purchaser
|
|
Expiration
|
Raft River (Unit I)
|
|
Idaho
|
|
JV
(2)
|
|
13.0
(1)
|
|
Idaho Power
|
|
2032
|
San Emidio (Unit I)
|
|
Nevada
|
|
100%
|
|
9.0
|
|
Sierra Pacific
|
|
2038
|
Neal Hot Springs
|
|
Oregon
|
|
JV
(3)
|
|
22.0
|
|
Idaho Power
|
|
2036
|
(1)
|
Based on the designed annual average net output. The
actual output of the Raft River Unit I plant currently is approximately
10.0 megawatts.
|
(2)
|
As part of the financing package for Unit I of the Raft
River project, we have contributed $16.5 million in cash and approximately
$1.4 million in property to Raft River Energy I LLC, the Unit I project
joint venture company. Raft River I Holdings, LLC, a subsidiary of The
Goldman Sachs Group, contributed $34 million to finance the construction
of the project.
|
(3)
|
In September 2010, the 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. Enbridges equity interest in the project is
40%.
|
-65-
Neal Hot Springs, Oregon
Neal Hot Springs is located
in Eastern Oregon near the town of Vale, the county seat of Malheur County. The
Neal Hot Springs facility is designed as a 22 megawatt net annual average power
plant, consisting of three separate, 7.33 net megawatt modules. The facility
achieved commercial operation under the terms of the power purchase agreement on
November 16, 2012. Generation from the facility during the fourth quarter of
2013 totaled 53,445 megawatt-hours with an average of 25.62 net megawatts per
hour of operation. Plant availability was 94.7% during the quarter as plant
operations continue to improve. Generation for the year was 155,430
megawatt-hours with annual plant availability of 83.1% .
On June 27, 2013, the Company accepted substantial completion
by the EPC contractor of all three of the Neal Hot Springs units. Final
completion of the project was achieved on July 31, 2013.
On February 26, 2009, the Company submitted a loan application
for the Neal Hot Springs project to the DOEs Energy Efficiency, Renewable
Energy and Advanced Transmission and Distribution Solicitation loan guarantee
program under Title XVII of the Energy Policy Act of 2005. The financial closing
for the DOE loan guarantee took place on February 23, 2011 which secured a $96.8
million loan guarantee from the Department of Energy and a direct loan from the
U.S. Treasurys Federal Financing Bank. The DOE loan for the project was closed
at final completion and has a balance of $70.4 million that bears an interest
rate of 2.6% over a 22 year term. The construction cost of the project has been
set at $128.1 million. Total project cost, including $11.2 million in reserves,
was $139.3 million, which is $4.3 million less than previously reported due
primarily to the inclusion of unused contingency funds which have since been
released by the project lender.
Over the course of the ongoing construction, the budget was
increased by $14.6 million in equity contributions by the partners. The first
increase of $7.0 million was to cover additional drilling costs and
modifications in plant controls and the cooling mechanism. Enbridge Inc., our
partner at Neal Hot Springs, provided the additional investment in exchange for
increased ownership interest in the project from 20% to a percentage to be
calculated based on an agreed upon financial model. A second budget increase of
$6 million, also provided by Enbridge Inc., was to establish a contingency fund
for potential additional drilling to complete the well field. Each of the
additional investments made by Enbridge Inc. was subject to calculations which
would result in increased ownership interest in the project.
Subsequent to the end of the year, in February 2014, the final
ownership interest in the Neal Hot Springs project was determined to be 60% for
U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S.
Geothermal received an approximate $6.2 million cash distribution from the
partnership.
The project received a $32.75 million cash grant under Section
1603 Specified Energy Property in Lieu of Tax Credits from the Treasury
Department. The cash grant, originally approved at $35.4 million, was subject to
an 8.7% reduction due to Federal sequestration ordered by Congress under the
Budget Control Act. The proceeds from the grant were used to: 1) fund $11.2
million in project level cash reserves as required by the terms of the DOE loan,
2) pay down $11.9 million on the DOE loan and 3) the balance of $9.7
million was distributed to equity investors.
-66-
In July 2010, the Company applied to the Oregon Department of
Energy (ODOE) for the Business Energy Tax Credit (BETC), which allows an
income tax credit for up to $20 million in qualifying capital expenditures for a
renewable energy project. The Company received unconditional approval of the
final certificate on March 1, 2013. The BETC was sold to a pass-through tax
partner in November 2013 for approximately $7.36 million.
The PPA for the project was signed on December 11, 2009 with
the Idaho Power Company. The PPA has a 25 year term with a starting average
price for the year 2012 of $96.00 per megawatt-hour and escalates at a variable
percentage annually. On May 20, 2010, the Idaho Public Utilities Commission
approved the PPA with no changes to the terms and conditions. Power generated
during 2013 was paid at an average price of $99.00 per megawatt-hour. The Idaho
Power PPA has a seasonal pricing structure that pays 120% of the average price
for four months (July, August, November, December), 100% of the average price
for five months (January, February, June, September, October) and 73.3% of the
average price for three months (March, April, May). The average price paid under
the PPA for 2014 has increased to $102.78 per megawatt-hour.
San Emidio, Nevada
The Phase I power plant at San
Emidio is located approximately 100 miles north of Reno, Nevada and achieved
commercial operation on May 25, 2012. Generation from the facility during the
fourth quarter 2013 totaled 21,103 megawatt-hours, with an average of 9.72 net
megawatts per hour of operation. Plant availability was 98.3% during the
quarter. Generation for the year was 76,696 megawatt-hours with annual plant
availability of 94.5% .
The Company entered into agreements with Science Applications
International Corporation (SAIC) for a project loan and an engineering
procurement and construction (EPC) contract for the San Emidio Phase I power
plant repower. SAICs design-build subsidiary, SAIC Energy, Environment &
Infrastructure LLC, constructed a new 9.0 net megawatt power plant, replacing
the old 3.6 net megawatt power plant. TAS Energy of Houston, Texas, supplied a
modular power plant to the project. Phase I achieved mechanical completion in
December 2011, and following performance testing of the power plant, which began
in early May 2012, achieved commercial operation on May 25, 2012. SAIC provided
its services under a fixed price contract that included financial guarantees for
the original completion date and power output of the plant.
Phase I plant completed its capacity testing during the first
quarter of 2013, and as a result of the capacity test exceeding the design
output: the plant was up-rated to 9.0 megawatt net annual average per hour from
the design point basis of 8.6 megawatts.
Substantial Completion under the contract was achieved February
21, 2013. Final Completion under the terms of the EPC was executed on June 24,
2013.
A final settlement agreement was executed as part of
Substantial Completion and included a fixed total construction loan payable to
the EPC contractor of $29.5 million. Prior to Substantial Completion, the Company had paid down the loan balance by $1.0
million in three monthly payments. Upon Substantial Completion, a payment of
$1.35 million was made to SAIC, and the construction loan was extended until
November 15, 2013 with a balance of $25.0 million carrying an interest rate of
10%. Additionally, a $2.0 million, 5 year term, unsecured loan was put in place
for the balance of the construction loan. This loan bears interest at 7% and has
a payment obligation of $119,382 per quarter.
-67-
The $25 million construction loan with SAIC was paid off in
September of 2013, and was replaced with long term notes purchased by Prudential
Capital Groups related entities. The notes are for an aggregate of
approximately $30.74 million, have a term of approximately 24 years, and bear a
fixed interest rate of 6.75% per annum. Proceeds from the sale of the notes were
used to repay the SAIC construction loan, fund project reserves, and pay certain
closing expenses, and approximately $2.56 million of the proceeds was
distributed to U.S. Geothermal Inc. to be used for general corporate working
capital purposes, including the further development of Phase II at San
Emidio.
The Phase II expansion was delayed due to the extended time
required to get Phase I online, and is still dependent on successful development
of additional production and injection well capacity. The cost of development
for Phase II is estimated at approximately $55 million. We expect that
approximately 75% of the Phase II development may be funded by project loans,
with the remainder funded through equity financing.
On June 1, 2011, an amended and restated PPA was signed with
Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9
megawatts of electricity on an annual average basis. The PPA has a 25 year term
with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate.
Power generated during 2013 was paid at the price of $90.27 per megawatt-hour.
The average price paid under the PPA for 2014 has increased to $91.17 per
megawatt-hour.
The electrical output from both Phase I and Phase II may 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. If Phase II cannot
achieve commercial operation under a proposed milestone schedule by December
2015, a new PPA would need to be negotiated and signed before financing and
construction could begin. A Small Generator Interconnection Agreement for 16
megawatts of transmission capacity was executed with Sierra Pacific Power
Company on December 28, 2010. Subsequent to the end of the year, 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
th
2014.
On October 30, 2009, the Company was awarded $3.77 million in
Recovery Act funding for the exploration and development of its San Emidio
geothermal power project using advanced geophysical exploration techniques. This
award was categorized under the Innovative Exploration and Drilling Projects
section of the American Recovery and Reinvestment Act. The project at San Emidio
has applied innovative, seismic and satellite imagery techniques along with
state-of-the-art structural modeling, to locate large aperture fractures that
represent high-productivity geothermal drilling targets. Two zones along the 4.5
mile long San Emidio fault structure were identified as high quality targets for
drilling during the first phase of the DOE program, a South Zone and a North
Zone. The first phase was completed in 2011.
-68-
The second stage of the DOE program is a 50-50 cost shared
drilling plan that followed up on the South Zone targets identified in the first
stage. In order to meet construction targets for Phase II plant construction,
the drilling stage of the program commenced prior to DOE approval, and two
observation wells were completed by the Company. The proposed drilling program
was approved by the DOE in early November 2011. One of the first two wells was
deepened and three additional wells have been completed in the South Zone under
the 50-50 cost share grant.
The DOE cost shared drilling program continues with the further
resource identification in the South Zone and the addition of the resource
identification in the North Zone. The North Resource Area, has an additional
five observation/temperature gradient wells and one production well planned as
part of the cost share drilling program. Drilling began on well OW-12 on
September 2, 2013. The well was completed on October 23, 2013 to a depth of
3,643 feet and is being evaluated in relation to the San Emidio reservoir model.
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 is planned
for the spring or early summer. The results from both wells will be used to
determine the continuing resource development plan in support of the Phase II
plant construction. In addition, permitting was initiated with the Bureau of
Land Management 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).
Raft River, Idaho
The Raft River project is located
in Southern Idaho, near the town of Malta, and achieved commercial operation in
January 2008. Generation from the facility during the fourth quarter 2013
totaled 21,742 megawatt-hours, with an average of 9.85 net megawatts per hour of
operation. Plant availability was 99.2% during the quarter. Generation for the
year was 77,552 megawatt-hours with annual plant availability of 96.5% .
The PPA for the project was signed on September 24, 2007 with
the Idaho Power Company. The PPA has a 25 year term with a starting average
price for the year 2007 of $52.50 that escalates at 2.1% per year. Power
generated during 2013 was paid at an average price of $59.47 per megawatt-hour.
The Idaho Power PPA has a seasonal pricing structure that pays 120% of the
average price for four months (July, August, November, December), 100% of the
average price for five months (January, February, June, September, October) and
73.5% of the average price for three months (March, April, May). The average
price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In
addition to the price paid for energy, Raft River currently receives $4.75 per
megawatt-hour under a separate contract for the sale of Renewable Energy
Credits.
The DOE $11.4 million cost-shared, thermal fracturing program
began the first stage of injection in June 2013 and continued until September
2013 when the second stage was started. Four, 300 foot deep seismic monitoring
wells were completed in the area around well RRG-9 and seismic geophones were
installed. Seismic monitoring will be conducted for the duration of the thermal
fracturing program. Injection continued through the quarter from power plant
injectate at an approximate temperature of 140°F. Flow in to the well has seen a
moderate increase indicating that additional permeability is developing. The
program has continued through the winter with low level injection going in to the well with a high pressure
injection phase planned for spring 2014.
-69-
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 totaling $991,417.
Republic of Guatemala
A geothermal energy rights
concession located 14 kilometers southwest of Guatemala City was awarded to U.S.
Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April
2010. The concession has a 5 year term for the development and construction of a
power plant. Discussions are being held with the Guatemalan Ministry of Energy
and Mines to allow a new schedule based on the current status of the project.
There are 24,710 acres (100 square kilometers) in the concession which is at the
center of the Aqua and Pacaya twin volcano complex.
An office and staff are located in Guatemala City and a 17.2
acre plant site has been leased on land adjacent to the existing wells.
Discussions are taking place with several interested parties for the potential
sale of an equity interest in the El Ceibillo project. El Ceibillo, the first
development target on the concession, is located near the town of Amatitlan, in
a developed industrial zone immediately adjacent to the highway that connects
Guatemala City to the Port of San Jose on the Pacific coast.
During the first phase of drilling on well EC-1, the well 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). Due to the high temperature
gradient found in the lower section of the well, the decision was made to deepen
the well, and a second phase of drilling commenced on August 21, 2013. The final
depth of the well, reached on September 15, 2013 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 the data was
provided to a third party consulting group with specific expertise in volcanic
geothermal resources for analysis and evaluation. Planning is underway for
another round of drilling to further delineate the El Ceibillo resource.
Subsequent to the end of the year, a temperature gradient (TG) drilling
program was initiated with a series of 200 meter (656 foot) deep wells planned
for the first quarter of 2014. Nine TG wells have been completed and the results
are being evaluated.
In early September 2013, the Guatemalan Ministry of the
Environment and Natural Resources (MARN) issued the Environmental License for
the construction and operation of the planned, first phase, 25 megawatt power
plant at the El Ceibillo site. The license is based on the Environmental Impact
Assessment Study that was submitted in December 2012, describing the initial
design of the 25 megawatt facility, and requires the submittal of final design
specifications for review by MARN prior to starting physical construction of
the plant. Additionally, the license requires compliance with all legal and
regulatory requirements under Guatemalan law, submittal of an air quality
monitoring plan, and that final design comply with the strict guidelines for
noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an
environmental bond of $344,850 Quetzals (approximately US $45,000) was posted
with the Ministry of Environment and Natural Resources.
-70-
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 binding Memorandum of Understanding (MOU) was signed on
October 18, 2012 with one of the largest power brokers in Central America. The
MOU establishes the framework for a PPA that includes a 15-year term for an
initially estimated 25 megawatts of power generation up to a maximum of 50
megawatts of power generation. The MOU includes a project power price that the
Company believes is competitive with the prevailing energy prices in the region.
Several conditions precedent must be met before the PPA is negotiated and
becomes effective, including confirming the geothermal reservoir by an
independent reservoir engineer, obtaining all required permits and
authorizations, and securing a project finance commitment.
The MOU may be terminated (i) as a result of the bankruptcy of
any of the parties, (ii) on January 1, 2015, unless such date is extended by
mutual agreement, because the construction of the project has not been initiated
and/or the commercial operation date has been moved beyond the date set out in
the PPA framework, or (iii) if the geothermal resource found lacks the
conditions to sustain a long-term commercial production that allows electric
power to be produced under the necessary conditions of profitability.
The El Ceibillo geothermal project area had nine previous wells
drilled into the geothermal concession, drilled in the 1990s and having depths
ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had
adequate flow and temperature to support a direct use application. Six of the
wells had measured reservoir temperatures in the range of 365°F to 400°F and had
high conductive gradients that indicated rapidly increasing temperature with
depth. Fluid samples and mineralization from the wells indicated the existence
of a high permeability reservoir below or near the existing well field.
Gerlach Joint Venture
The Gerlach Joint Venture,
located adjacent to the town of Gerlach in Washoe County, Nevada is made up of
both private and BLM geothermal leases. The Peregrine well, a historic
exploration slim hole that encountered a lost circulation zone at a depth of 975
feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a
12.5 inch diameter well. Lost circulation was confirmed with three zones through
the 900 to 1,024 foot interval. The well was stopped at 1,070 feet total depth.
Temperature surveys and a short clean out flow test were conducted on the well.
The well flowed at an estimated 300-400 gallons per minute and the flowing
temperature was 208°F. Geochemistry indicates an average potential source
temperature of 374°F for the Gerlach site.
-71-
Drilling commenced on observation well 18-10a on October 30,
2011. The upper section of the well was drilled to 826 feet deep and an 8 inch
liner was cemented in place. The well was secured and the drill rig was moved
back to San Emidio. Temperature measurements in the well have provided the
highest measured temperature in the field to date at 268°F within 160 of
surface and a temperature gradient of 6.4°F per 100 in the bottom section of
the hole. There are two previously identified lost circulation targets at 1,600
and 2,800 deep that will be targeted when drilling is resumed.
Drilling resumed on well 18-10a on April 14, 2012 and was
stopped on April 18, 2012 at 1,943 feet deep. Circulation was lost in minor
zones at 1,530 and 1,595 feet deep. Subsequent temperature surveys indicate an
isothermal temperature profile at 241°F which may indicate that higher
temperature fluid does not occur below the 18-10a well site.
A plan and budget has been developed to deepen well 18-10a to
intersect the lost circulation zone at 2,800 feet deep to provide temperature
information on the deep structure. Further work is dependent upon additional
funding from the partners.
Granite Creek, Nevada
The Granite Creek assets are
located about 6 miles north of Gerlach, Nevada along a geologic structure known
to host geothermal features including the Great Boiling Spring and the Fly Ranch
Geyser. A first stage gravity geophysical program was completed in the third
quarter of 2008 and will be used to evaluate the resource potential, and help
determine where to drill temperature-gradient exploration wells.
After a detailed review of the geologic setting, the lease
position at Granite Creek was reduced to 2,443.7 acres (3.8 square miles). One
full lease and portions of the two remaining leases were relinquished to the
Bureau of Land Management.
Factors Affecting Our Results of
Operations
Although other factors may impact our operations and
financial condition, including many that we do not or cannot foresee, we believe
that our results of operations and financial condition for the foreseeable
future will be affected by the factors discussed below. A summary of the
Companys operations is as follows:
Neal Hot Springs, Oregon
The facility achieved
commercial operation under the terms of the power purchase agreement on November
16, 2012. During the year ended December 31, 2013, the plant achieved 83.1%
availability and generated an average of 21.4 net megawatts per hour. Generation
from the facility during the year ended December 31, 2013 totaled 155,430
megawatt hours.
San Emidio, Nevada
The Phase I plant achieved
commercial operation on May 25, 2012. During the year ended December 31, 2013,
the plant achieved 94.5% availability and generated an average of 9.3 net
megawatts per hour. Power production totaled 76,696 megawatt hours for the year
ended 2013.
-72-
The plant was up rated to 9.0 net annual average megawatts per
hour from the design point basis of 8.6 megawatts.
Raft River Energy I LLC
During the year ended
December 31, 2013, Raft River operated at 96.5% availability and generated an
average of 9.2 net megawatts per hour. Power production totaled 77,552 megawatt
hours for the year ended 2013. For the 2012 year, the plant averaged 8.6 net
megawatts of generation with 98.7% availability.
The plant operated at reduced output during the first half of
the year due to a mechanical problem with the production pump in well RRG-2.
RRG-2 was shut down on April 15, 2012, the pump was replaced in early June 2012,
and it came back on line June 14, 2012 and has run through the end of the year
without any further mechanical issues.
The funding for the DOE cost-shared, thermal fracturing program
was increased from $10.2 million to $11.4 million by an additional $1.2 million
contribution from the DOE. NEPA approval for the injection program was received,
allowing the injection phase of the program to inject fluid that may induce
thermal fracturing, and it is anticipated that injection may start during the
second quarter of 2014. Two monitoring wells are planned, and must be completed
prior to injection testing. If the 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 are made in-kind by the use of the
RRG-9 well, well field data and monitoring support totaling $991,417. Eight
solar powered seismic stations were installed in June 2010 to provide a base
line of seismic data and will be used to monitor potential impacts from the
test. Construction is complete on the injection pipeline that extends from the
Unit I power plant to well RRG-9. A detailed, 3-D magnetotelluric survey was
completed during the fourth quarter of 2010.
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. 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.
-73-
Based on managements annual review of the 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.
The Companys interests in the 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 (PPA)
Prior to the
construction of a geothermal project, we typically enter into a power purchase
agreement with a utility, which fixes the price of energy produced at a project
for a 20 to 25 year period. Such PPAs are typically negotiated with the utility
company and approved by a state utility commission or similar regulating body.
-74-
Power purchase agreements generally provide for the payment of
energy payments, capacity payments, or both. Energy payments are calculated
based on the amount of electrical energy delivered to the relevant power
purchaser at a designated delivery point. The rates applicable to such payments
are either fixed, subject to adjustments in certain cases, or are based on the
relevant power purchasers short-run avoided costs calculated as the incremental
costs that the power purchaser avoids by not having to generate such electrical
energy itself or purchase it from others. Capacity payments, on the other hand,
are generally calculated based on the amount of time that our power plants are
available to generate electricity. Some power purchase agreements provide for
bonus payments in the event that the producer is able to exceed certain target
levels and forfeiture of payments if minimum target levels are not met.
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 1
percent annual escalation rate. The electrical output from both Phase I and
Phase II will be sold under the terms of the amended and restated PPA. The PPA
was approved by the Public Utility Commission of Nevada on December 27,
2011.
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. This PPA was signed as part of ongoing
negotiations with Idaho Power for PPAs covering an expected total output of 45.5
megawatts and may be used as the template for additional PPAs. The price of
energy sold under the Idaho Power PPA is split into three seasons: power
produced during the peak periods of July, August, November and December will be
purchased at 120% of the set price; power produced in the three month low demand
season will be purchased at 73.50% of the set price; and power produced in the
remaining five months of the year will be purchased at 100% of the set price.
The PPA sets a first year average purchase price of $53.60 per 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.
Neal Hot Springs, Oregon
The power purchase
agreement 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.
-75-
Operating Results
For the year ended December 31 2013, the Company reported net
income attributable to the Company of $1,946,579 ($0.02 income per share) which
represented a $4,905,146 favorable increase from the net loss of $2,958,567
million reported in the year ended 2012 ($0.03 loss per share). Net income from
plant operations for the year ended December 31, 2013 increased $12,984,636 from
the income of $227,276 reported in the year ended 2012. Other notable favorable
variances were reported in stock based compensation and other income/expenses.
Notable unfavorable variances were reported in professional and management fees,
salaries and related compensation and interest expense.
Plant Operations
During the year ended December 31
2013, the Companys energy production revenues and related operating costs
originated from its fully operational three 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.
A summary of energy sales by plant for the two reporting
periods are as follows:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2013
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
|
$
|
|
|
%*
|
|
|
$
|
|
|
%*
|
|
|
Energy sales by plant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Neal Hot Spring,
Oregon
|
|
15,566,409
|
|
|
57.7
|
|
|
2,329,030
|
|
|
24.9
|
|
|
San
Emidio, Nevada
|
|
6,792,382
|
|
|
25.2
|
|
|
2,632,502
|
|
|
28.1
|
|
|
Raft River, Idaho
|
|
4,627,258
|
|
|
17.1
|
|
|
4,396,671
|
|
|
47.0
|
|
|
|
|
26,986,049
|
|
|
100.0
|
|
|
9,358,203
|
|
|
100.0
|
|
%*
- represents the percentage of
total Company energy sales
.
A quarterly summary of power generated by plant for the current
year is as follows:
|
|
|
For
the Quarter Ended,
|
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
|
2013
|
|
|
2013
|
|
|
2013
|
|
|
2013
|
|
|
Megawatt Hours Produced:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Neal Hot Spring, Oregon
|
|
46,137
|
|
|
30,016
|
|
|
25,832
|
|
|
53,445
|
|
|
San Emidio,
Nevada
|
|
19,228
|
|
|
18,039
|
|
|
18,317
|
|
|
21,112
|
|
|
Raft River, Idaho
|
|
19,675
|
|
|
17,248
|
|
|
18,687
|
|
|
21,951
|
|
|
|
|
85,040
|
|
|
65,303
|
|
|
62,836
|
|
|
96,508
|
|
-76-
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
plants first full year of operations. The quarter ended December 31, 2013, was
the highest quarter of energy production and sales to date. High production was
due to less down time and the efficiency of the cooling towers due to the cooler
ambient temperatures of the fall/winter months. During the quarter ended June
30, 2013, plant production was down approximately 38 days for turbine upgrades.
One unit was down for approximately 26 days, during the quarter ended September
30, 2013 due to the failure of a high pressure refrigerant pump.
Since the current year was the first full year of operations,
generally all operating costs increased significantly (approximately $5.55
million) to the level expected for normal operations. Also, interest increased
significantly (approximately $1.7 million). The majority of the interest costs
incurred in the prior year were capitalized.
Key quarterly production data for the Neal Hot Springs, Oregon
plant is summarized as follows:
|
|
Mega-
|
|
|
|
Ave. Rate
|
|
|
|
Depreciation
|
|
|
watt
|
|
Energy
|
|
per
|
|
Net
|
|
&
|
|
|
Hours
|
|
Sales
|
|
Megawatt
|
|
Income*
|
|
Amortization
|
Quarter Ended:
|
|
Produced
|
|
($)
|
|
Hour
($)
|
|
($)
|
|
($)
|
December 31, 2012
|
|
23,256
|
|
2,329,030
|
|
88.7
|
|
1,451,523
|
|
256,670
|
March 31, 2013
|
|
46,137
|
|
4,197,251
|
|
90.6
|
|
2,424,647
|
|
779,298
|
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
|
* - The intercompany elimination
adjustments for management fees are not incorporated into the presentation of
the
subsidiarys net income.
-77-
Summarized statements of operations for the Neal Hot Springs,
Oregon plant are as follows:
|
|
Year
Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
Variance
|
|
|
|
$
|
|
|
%*
|
|
|
$
|
|
|
%
|
|
|
$
|
|
|
%**
|
|
Plant revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
sales
|
|
15,566,409
|
|
|
100.0
|
|
|
2,329,030
|
|
|
100.0
|
|
|
13,237,379
|
|
|
#
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
|
|
3,118,488
|
|
|
20.0
|
|
|
260,023
|
|
|
11.2
|
|
|
(2,858,465
|
)
|
|
#
|
|
Depreciation and amortization
|
|
3,217,071
|
|
|
20.7
|
|
|
522,889
|
|
|
22.5
|
|
|
(2,694,182
|
)
|
|
#
|
|
|
|
6,335,559
|
|
|
40.7
|
|
|
782,912
|
|
|
33.6
|
|
|
(5,552,647
|
)
|
|
#
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
9,230,850
|
|
|
59.3
|
|
|
1,546,118
|
|
|
66.4
|
|
|
7,684,732
|
|
|
497.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(1,856,255
|
)
|
|
(11.9
|
)
|
|
(160,633
|
)
|
|
(6.9
|
)
|
|
(1,695,622
|
)
|
|
#
|
|
Interest income/other
|
|
42,540
|
|
|
0.2
|
|
|
27,077
|
|
|
1.2
|
|
|
15,463
|
|
|
57.1
|
|
|
|
(1,813,715
|
)
|
|
(11.7
|
)
|
|
(133,556
|
)
|
|
(5.7
|
)
|
|
(1,680,159
|
)
|
|
#
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
7,417,135
|
|
|
47.6
|
|
|
1,412,562
|
|
|
60.7
|
|
|
6,004,573
|
|
|
425.1
|
|
|
%*
-
|
represents the percentage of
total plant operating revenues
.
|
|
%**
-
|
represents the percentage of change from 2012 to
2013
.
Increases in revenues and
decreases in expenses from
the prior period to the current period are considered to be
favorable and are presented as positive figures.
|
|
#
-
|
variance percentage that is
extremely high or undefined.
|
The intercompany elimination adjustments for management fees
are not incorporated into the presentation of the subsidiarys net operating
income/loss.
San Emidio, Nevada Plant Energy Sales and Plant Operating
Expenses (USG Nevada LLC)
For the year ended December 31, 2013, the San
Emidio plant reported net profit of $1,158,638 which was a favorable increase of
$1,765,526 from the loss of $606,888 reported in the year ended 2012. The new
plant became commercially operational on May 25, 2012. After the plant became
operational, it experienced down time of approximately 83 days in the third and
fourth quarters to address mechanical and performance issues that can be common
for a new plant. Overall, energy sales for the year ended December 31, 2013
increased $4,159,880 (158.0% increase) from the year ended 2012. During the
quarter ended December 31, 2013, the plant produced the highest amount of energy
revenues and kilowatt hours ($1,905,813 energy sales; 21,112,368 kilowatt hours)
than any other quarter in operating history of USG Nevada LLC.
Since the current year was the first full year of operations
for the new power plant, most operational costs increased from the prior year.
In the prior year, the majority of the employees time was dedicated to plant
construction and the plant was only operational for a portion of the year;
therefore, operation salary and related costs were approximately $369,000
(68.5%) lower than the current year. Management fees and corporate support costs
were charged to plant operations in the current year that totaled $400,000. No
management fees were earned/charged to the plant in 2012, and corporate support
costs were minimal. In the prior year ended 2012, an error was made in the calculation of property taxes. This error
was corrected in the current year, which resulted favorable decrease in property
tax expense of approximately $425,000.
-78-
Summarized statements of operations for the San Emidio, Nevada
plant are as follows:
|
|
Year
Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
Variance
|
|
|
|
$
|
|
|
%*
|
|
|
$
|
|
|
%
|
|
|
$
|
|
|
%**
|
|
Plant revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales
|
|
6,792,382
|
|
|
100.0
|
|
|
2,632,502
|
|
|
100.2
|
|
|
4,159,880
|
|
|
158.0
|
|
Energy
credit sales
|
|
-
|
|
|
-
|
|
|
(6,124
|
)
|
|
(0.2
|
)
|
|
6,124
|
|
|
100.0
|
|
|
|
6,792,382
|
|
|
100.0
|
|
|
2,626,378
|
|
|
100.0
|
|
|
4,166,004
|
|
|
318.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
|
|
2,500,816
|
|
|
36.8
|
|
|
2,194,128
|
|
|
83.5
|
|
|
(306,688
|
)
|
|
(14.0
|
)
|
Depreciation and
amortization
|
|
1,392,502
|
|
|
20.5
|
|
|
1,039,979
|
|
|
39.6
|
|
|
(352,523
|
)
|
|
(33.9
|
)
|
|
|
3,893,318
|
|
|
57.3
|
|
|
3,234,107
|
|
|
123.1
|
|
|
(659,211
|
)
|
|
(20.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
2,899,064
|
|
|
42.7
|
|
|
(607,729
|
)
|
|
(23.1
|
)
|
|
3,506,793
|
|
|
#
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(1,742,181
|
)
|
|
(25.6
|
)
|
|
-
|
|
|
-
|
|
|
(1,742,181
|
)
|
|
#
|
|
Interest income
|
|
1,755
|
|
|
0.0
|
|
|
841
|
|
|
0.0
|
|
|
914
|
|
|
108.7
|
|
|
|
(1,740,426
|
)
|
|
(25.6
|
)
|
|
841
|
|
|
0.0
|
|
|
(1,741,267
|
)
|
|
#
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
1,158,638
|
|
|
17.1
|
|
|
(606,888
|
)
|
|
(23.1
|
)
|
|
1,765,526
|
|
|
290.9
|
|
|
%*
-
|
represents the percentage of total plant operating
revenues
.
|
|
%**
-
|
represents the percentage of change from 2012 to
2013
.
Increases in revenues and
decreases in expenses from
the prior period to the current period are considered to be
favorable and are presented as positive figures.
|
|
#
-
|
variance percentage that is extremely high or
undefined.
|
The intercompany elimination adjustments for management fees
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:
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
Mega-
|
|
|
|
|
|
Ave. Rate
|
|
|
|
|
|
Depreciation
|
|
|
|
watt
|
|
|
Energy
|
|
|
per
|
|
|
Income
|
|
|
&
|
|
|
|
Hours
|
|
|
Sales
|
|
|
Megawatt
|
|
|
(Loss)*
|
|
|
Amortization
|
|
Quarter Ended:
|
|
Produced
|
|
|
($)
|
|
|
Hour
($)
|
|
|
($)
|
|
|
($)
|
|
March 31, 2012
(1)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(475,961
|
)
|
|
189,126
|
|
June 30, 2012
(2)
|
|
5,465
|
|
|
427,931
|
|
|
77.6
|
|
|
(8,693
|
)
|
|
181,333
|
|
September 30, 2012
|
|
8,280
|
|
|
745,494
|
|
|
89.7
|
|
|
101,154
|
|
|
253,429
|
|
December 31, 2012
|
|
16,231
|
|
|
1,459,078
|
|
|
90.0
|
|
|
(223,412
|
)
|
|
416,091
|
|
March 31, 2013
|
|
19,228
|
|
|
1,726,927
|
|
|
90.3
|
|
|
834,266
|
|
|
407,060
|
|
June 30, 2013
|
|
18,039
|
|
|
1,628,382
|
|
|
90.3
|
|
|
(212,058
|
)
|
|
365,314
|
|
September 30, 2013
|
|
18,317
|
|
|
1,531,260
|
|
|
83.6
|
|
|
355,499
|
|
|
307,854
|
|
December 31, 2013
|
|
21,112
|
|
|
1,905,813
|
|
|
90.3
|
|
|
180,931
|
|
|
312,273
|
|
-79-
|
(1)
|
- The old power plant ceased operations on December
12, 2011, to facilitate the transfer of operations to the new power
plant.
|
|
(2)
|
- The new power plant became commercially operational
on May 25, 2012. The plant produced power at a lower test rate in May
and at the full contract rate of .08975 per kilowatt hour in
June.
|
|
*
|
-
The intercompany elimination adjustments for
management fees are not incorporated into the presentation of the
subsidiarys net income/loss.
|
Raft River, Idaho Unit I (Raft River Energy I LLC) Plant
Operations
Net loss from Raft River Energy I LLC (RREI) operations of
$394,847 for the year ended December 31, 2013, favorably decreased by $950,028
from the loss of $1,344,875 the reported in year ended 2012. The primary reason
for the difference in net loss for the current year was the repair costs
incurred primarily in the first quarter ended March 31, 2012. The repairs of
wells RRG-2 and RRG-7 were completed in January 2012. For the year ended
December 31, 2012, repair costs totaled $830,685 which was $555,533 higher than
the repair costs incurred for the current year. Another factor contributing to
the lower repair costs were the two grant awards that totaled $217,594 collected
in the quarter ended March 31, 2013 that offset a portion of the well repairs.
For the year ended December 31, 2013, energy production and energy sales
increased 3.9% and 5.2% from the same period ended 2012.
The summarized statements of operations for RREI are as
follows:
|
|
Year
Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
Variance
|
|
|
|
$
|
|
|
%*
|
|
|
$
|
|
|
%*
|
|
|
$
|
|
|
%**
|
|
Plant revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy sales
|
|
4,627,258
|
|
|
92.3
|
|
|
4,396,671
|
|
|
91.1
|
|
|
230,587
|
|
|
5.2
|
|
Energy credit sales
|
|
384,885
|
|
|
7.7
|
|
|
406,866
|
|
|
8.5
|
|
|
(21,981
|
)
|
|
(5.4
|
)
|
|
|
5,012,143
|
|
|
100.0
|
|
|
4,803,537
|
|
|
100.0
|
|
|
208,606
|
|
|
4.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General operations
|
|
3,378,794
|
|
|
67.4
|
|
|
3,900,270
|
|
|
81.2
|
|
|
521,476
|
|
|
13.4
|
|
Depreciation and
amortization
|
|
1,844,579
|
|
|
36.8
|
|
|
2,027,929
|
|
|
42.2
|
|
|
183,350
|
|
|
9.0
|
|
|
|
5,223,373
|
|
|
104.2
|
|
|
5,928,199
|
|
|
123.4
|
|
|
704,826
|
|
|
11.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
(211,230
|
)
|
|
(4.2
|
)
|
|
(1,124,662
|
)
|
|
(23.4
|
)
|
|
913,432
|
|
|
81.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
(197,461
|
)
|
|
(3.9
|
)
|
|
(220,605
|
)
|
|
(4.6
|
)
|
|
13,452
|
|
|
10.5
|
|
Other and interest income
|
|
13,844
|
|
|
0.2
|
|
|
392
|
|
|
0.0
|
|
|
23,144
|
|
|
#
|
|
|
|
(183,617
|
)
|
|
(3.7
|
)
|
|
(220,213
|
)
|
|
(4.6
|
)
|
|
36,596
|
|
|
16.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
(394,847
|
)
|
|
(7.9
|
)
|
|
(1,344,875
|
)
|
|
(28.0
|
)
|
|
950,028
|
|
|
70.6
|
|
|
%*
-
|
represents the percentage of total plant
operating revenues
.
|
|
%**
-
|
represents the percentage of change from
2012 to 2013
.
Increases in revenues and
decreases in
expenses from the prior period to the current period are considered to
be
favorable and are presented as positive figures.
|
|
#
-
|
variance percentage that is extremely high
or undefined.
|
-80-
The intercompany elimination adjustments for interest
expense, management fees and lease costs are not incorporated into the
presentation of the subsidiarys operations.
Key quarterly production data for RREI is summarized as
follows:
|
|
Mega-
|
|
|
|
Ave. Rate
|
|
|
|
Depreciation
|
|
|
watt
|
|
Energy
|
|
per
|
|
Net Income
|
|
&
|
|
|
Hours
|
|
Sales
|
|
Megawatt
|
|
(Loss)*
|
|
Amortization
|
Quarter Ended:
|
|
Produced
|
|
($)
|
|
Hour
($)
|
|
($)
|
|
($)
|
March 31, 2012
|
|
19,639
|
|
1,057,091
|
|
55.7
|
|
(696,689)
|
|
509,027
|
June 30, 2012
|
|
15,999
|
|
765,255
|
|
50.3
|
|
(805,286)
|
|
507,783
|
September 30, 2012
|
|
17,836
|
|
1,176,107
|
|
68.1
|
|
2,348
|
|
505,560
|
December 31, 2012
|
|
21,170
|
|
1,398,218
|
|
67.9
|
|
154,752
|
|
505,559
|
March 31, 2013
|
|
19,675
|
|
1,064,481
|
|
56.1
|
|
67,620
|
|
472,040
|
June 30, 2013
|
|
17,248
|
|
823,153
|
|
49.9
|
|
(715,605)
|
|
472,094
|
September 30, 2013
|
|
18,687
|
|
1,260,124
|
|
69.5
|
|
(1,165)
|
|
450,222
|
December 31, 2013
|
|
21,951
|
|
1,479,499
|
|
69.0
|
|
254,302
|
|
450,222
|
|
* - 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, 2013, the Company incurred professional and management fees of
$1,284,936, which was an increase of $518,335 (67.6% increase) from the year
ended 2012. The two primary elements for the increase were the consulting fees
paid to the former CEO and the additional audit and accounting fees. During the
current year, consulting fees were paid to the former CEOs consulting firm and
the former Vice President of Exploration that totaled $301,281. Additional
audit, audit related and financial consulting fees were incurred during the
current year to address the audit requirements for our subsidiaries and the
change in year end for the Company. During the year ended December 31, 2013, the
Company incurred audit/audit related, legal and SOX consulting costs of
approximately $274,000, $216,000 and $82,000; respectively. In the prior year,
the Company incurred audit/audit related, legal and SOX consulting costs of
approximately $138,000, $226,000 and $100,000; respectively.
Salaries and Wages
For the year ended December 31
2013, the Company reported $2,135,945 in salaries and related costs, which was
an increase of $1,033,194 (93.7% increase) from the year ended 2012. The
increase was primarily due to bonuses awarded and due to lower amounts of
compensation that were capitalized on the Companys major projects. During the
current year, the Company paid employee bonuses of $171,000. A CEO signing bonus
of $100,000, payable in stock, was paid in the second quarter of 2013. During
the year ended December 31, 2012, significant portions of the management and
development compensation costs were allocated to the Companys capital projects
(Neal Hot Springs, Oregon and San Emidio, Nevada Phases I and II). Since both
the Neal Hot Springs and the San Emidio Phase I projects were substantially
completed prior to and operational during the current period, salary cost
allocations for both projects decreased.
-81-
Management and development employee salaries and related costs
allocated to major Company projects are summarized as follows:
|
|
For
the Year Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
Variance
|
|
Financial
Element
|
|
$
|
|
|
$
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company salary and related costs,
excluding plant operations
|
|
2,873,047
|
|
|
2,266,781
|
|
|
606,266
|
|
|
26.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Salary and related costs allocated to the
following projects:
|
|
|
|
|
|
|
|
|
|
|
|
|
USG
Oregon LLC (Neal Hot Springs Project)
|
|
(429,124
|
)
|
|
(800,189
|
)
|
|
371,065
|
|
|
46.4
|
|
USG
Nevada LLC (San Emidio Phase I Project)
|
|
(67,033
|
)
|
|
(143,311
|
)
|
|
76,278
|
|
|
53.2
|
|
USG
Nevada LLC (San Emidio Phase II Project)
|
|
(170,295
|
)
|
|
(150,805
|
)
|
|
(19,490
|
)
|
|
(12.9
|
)
|
Development activities in Guatemala
|
|
(57,164
|
)
|
|
(11,867
|
)
|
|
(45,297
|
)
|
|
(381.7
|
)
|
Small projects and
plant operations
|
|
(13,486
|
)
|
|
(57,858
|
)
|
|
44,372
|
|
|
76.7
|
|
|
|
2,135,945
|
|
|
1,102,751
|
|
|
1,033,194
|
|
|
93.7
|
|
%
- represents the percentage
of change from 2012 to 2013
.
Stock Based Compensation
For the year ended December
31 2013, the Company reported $756,935 in stock based compensation, which was a
decrease of $183,197 (19.5% decrease) from the year ended 2012. Stock based
compensation includes the calculated values for both Company stock and stock
options. In the quarter ended June 30, 2013, stock was provided to the new CEO
as a component of his compensation package. The Company issued stock options to
employees on August 24, 2012 and July 22, 2013 for 2,917,000 and 1,950,000;
respectively. The compensation related to the value of the stock options issued
to employees was significantly lower in the quarters ended March 31, 2013 and
June 30, 2013 from the same periods in 2012 due to the lower market price of the
Companys outstanding stock during those periods. During the quarter ended
September 30, 2013, the value of stock options was slightly less (8.8% decrease)
than the value in the same period ended in 2012. The value of stock options
expensed in the quarter ended December 31, 2013 was consistent with the same
period ended in 2012.
-82-
The stock based compensation
components are summarized as follows:
|
|
For the Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
2012
|
|
|
Variances
|
|
|
|
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
%
|
|
Total Stock Based Compensation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock option compensation
|
|
683,443
|
|
|
861,277
|
|
|
(177,834
|
)
|
|
(20.7
|
)
|
Stock compensation
|
|
73,492
|
|
|
78,855
|
|
|
(5,363
|
)
|
|
(6.8
|
)
|
|
|
756,935
|
|
|
940,132
|
|
|
(183,197
|
)
|
|
(19.5
|
)
|
%
- represents the percentage
of change from 2012 to 2013
.
Interest Expense
During the year ended December 31
2013, the Company incurred $3,895,890 in interest expense, which was an increase
of $3,735,060 from the year ended 2012. All interest expense costs incurred from
construction loans incurred prior to the plants becoming commercially
operational was capitalized.
Other Income/Expenses
For the year ended December 31
2013, the Company reported $115,865 in income in other income/expenses which was
a favorable increase of $553,466 from the loss reported the year ended 2012. In
February 2012, water rights on 2,917 acres leased property in the Granite Creek
area located in the State of Nevada were relinquished and removed from
intangible assets at their carrying amounts that totaled $548,701. The
relinquishment was considered to be a loss that was recognized in the year ended
December 31, 2012.
Net Income/Loss Attributable to the Non-Controlling
Interests
The net income/loss 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 subsidiaries. For the
year ended December 31, 2013, the Company reported $2,184,070 in net income
attributable to non-controlling interests, which was a favorable increase of
$3,557,028 from the net loss of $1,372,958 the year ended 2012. 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 $7,417,135 for the year
ended December 31, 2013. The impact of the Neal Hot Springs operations on the
Companys reported income attributable to non-controlling entities was an
increase of $2,568,889 from the year ended December 31, 2012 as compared to the
current year ended 2013.
-83-
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
|
|
2013
|
|
|
2012
|
|
|
Variance
|
|
|
|
|
Interest
Entities
|
|
$
|
|
|
$
|
|
|
$
|
|
|
%
|
|
Oregon USG Holdings LLC interest held
by Enbridge Inc.
|
|
(2,848,081
|
)
|
|
(279,192
|
)
|
|
(2,568,889
|
)
|
|
#
|
|
Raft River Energy I LLC interest held by
Raft River I Holdings, LLC
|
|
656,469
|
|
|
1,611,830
|
|
|
(955,360
|
)
|
|
(59.3
|
)
|
Gerlach Geothermal LLC interest held by
Gerlach Green Energy, LLC
|
|
7,542
|
|
|
40,321
|
|
|
(32,779
|
)
|
|
(81.3
|
)
|
|
|
(2,184,070
|
)
|
|
1,372,958
|
|
|
(3,574,028
|
)
|
|
#
|
|
%
- represents the percentage
of change from 2012 to 2013
.
#
- variance percentage that is
extremely high or undefined.
-84-
Liquidity and Capital Resources
We believe our cash and liquid investments at December 31, 2013
are adequate to fund our general operating activities through December 31, 2014.
Other project development, such as Guatemala, may require additional funding. In
addition to government loans and grants discussed below, we anticipate that
additional funding may be raised through financial and strategic partnerships,
market loans, issuance of debt or equity, and/or through the sale of ownership
interest in tax credits and benefits.
The recent financial credit crisis has not impacted the ability
of our customers, Idaho Power Company and Sierra Pacific Power, to pay for their
power. This power is sold under long-term contracts at fixed prices to large
utilities. The status of the credit and equity markets could delay our project
development activities while the Company seeks to obtain economic credit terms
or a favorable equity market price to further the drilling and construction
activities. The Company continues discussions with potential investors to
evaluate alternatives for funding at the corporate and project levels.
On November 29, 2013 the Company filed a replacement shelf
registration statement on Form S-3 with the SEC. The replacement shelf
registration statement was filed as routine course of business due to the
impending expiration of the Companys existing shelf registration statement
that, under SEC rules, would have expired on December 1, 2013. Pursuant to SEC
rules, the expiration date of the existing shelf registration statement has been
extended until the earlier of the effective date of the replacement shelf
registration statement or May 30, 2014. Upon effectiveness of the S-3 on
February 4, 2014, the Company may use the replacement shelf registration
statement to offer and sell from time to time for a period of three years in one
or more public offerings up to $50 million of common stock, warrants, or units
consisting of any combination thereof. The terms of any securities offered under
the replacement shelf registration statement, and the intended use of the
resulting net proceeds, will be established at the times of any future offerings
and will be described in prospectus supplements filed at such times with the
SEC. The Company has no immediate plans to sell any additional stock under the
replacement shelf registration statement at this time, but wishes to preserve
the option in support of its future growth and development of its projects as
well as strategic M&A opportunities.
Following the receipt of the Section 1603 Federal Investment
Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit
funds, and after the receipt and disbursement of all remaining construction
reserve funds, which was finalized on January 27, 2014, the final ownership
interest in the Neal Hot Springs project was calculated in accordance with the
terms of the partnership agreement. Ownership interest in the project is final
with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final
agreement, U.S. Geothermal has received a $6.2 million cash distribution from
the partnership.
Under the terms of the DOE loan agreement, project profits are
distributed to the equity partners semi-annually (February and August),
following Final Completion, which was achieved on August 1, 2013. U.S.
Geothermals share of this first distribution received March 5, 2014 is $4.6
million, out of a total distribution to the partners of $7.7 million, which
represents profits generated from the project since initial operation began in
November 2012.
-85-
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, 2013, $10.1 million in USG Oregon LLC funds were deposited at PNC
Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at
Sterling Bank, and were unavailable for immediate corporate needs.
For projects under construction before the end of 2010 and
online before the end of 2013, a project was eligible to take a 30% investment
tax credit (ITC) in lieu of the production tax credit (PTC). The ITC was
able to be converted into a cash grant within the first 90 days of operation of
the plant. Phase I at San Emidio attained commercial operation on May 25, 2012.
An application was submitted in July 2012 electing to take the ITC cash grant in
lieu of the PTC. The United States Department of Treasury notified the Company
that it would allow $10.65 million in cash grant. The cash grant proceeds were
received on November 10, 2012 and used to repay the Ares Capital bridge loan
facility, with the remaining balance payable to USG Nevada LLC. An additional
$1.05 million of cash grant items were subsequently approved and paid in March
2013. For the Neal Hot Springs project, an application was submitted in the
first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for
approximately $35.9 million from U.S. Treasury and the funds would be used to
fund reserves required under the DOE Loan Guarantee Agreement and return funds
to our partner in the project, Enbridge. Due to federal sequestration in early
2013, the ITC cash grant amount received in April 2013 was reduced by 8.7% to
$32.7 million.
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).
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, 2013, 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.
-86-
The Company also entered into an agreement with Kuhns Brothers
Securities Corporation (KBSC), pursuant to which KBSC agreed to act as the
placement agent in connection with the sale of shares of Common Stock to LPC.
The Company has agreed to pay KBSC the following compensation for its services
in acting as placement agent in the sale of Common Stock to LPC: (A) the Company
will pay a cash fee to KBSC in an amount equal to: (i) 6% of the aggregate gross
proceeds received by the Company from the initial sale of $750,000 in shares of
Common Stock to LPC pursuant to the Purchase Agreement, and (ii) 3% of the
aggregate gross proceeds received by the Company from additional sales of Common
Stock to LPC pursuant to the Purchase Agreement; and (B) the Company will issue
to KBSC the number of warrants (the Compensation Warrants) equal to: (i) in
the case of the initial sale of $750,000 in shares of Common Stock to LPC, 6% of
the aggregate number of shares sold to LPC; and (ii) in the case of additional
sales of Common Stock to LPC, 3% of the aggregate gross proceeds received by the
Company from such sales divided by 115% of the closing sale price of one share
of Common Stock on the day prior to the respective issuance of the Compensation
Warrant. The Compensation Warrants issued pursuant to clause (ii) in the
preceding sentence will be based on incremental sales to LPC of $2 million in
aggregate gross proceeds. Each Compensation Warrant will have an exercise price
equal to 115% of the closing sale price of one share of Common Stock on the day
prior to its issuance, a term of five years from the date of its issuance and
will otherwise comply with the rules of the Financial Industry Regulatory
Authority, Inc. On December 26, 2012, the Company completed a registered direct
offering with a number of investors, pursuant to which they acquired, in total,
11,810,816 units (each a Unit) of the Company at a price of $0.37 per Unit.
Each Unit consists of one share of common stock of the Company and one half of
one common stock purchase warrant (each whole warrant a Warrant). Each Warrant
will entitle the holder thereof to acquire one additional share of common stock
of the Company for a period of 60 months following the closing of the offering
for $0.50 per share of common stock. The gross proceeds of the Unit offering
were approximately $4.37 million. Kuhns Brothers Securities Corporation acted as
placement agent for this offering and was paid a placement fee of $262,000,
plus expenses of approximately $20,000.
-87-
On February 24, 2011, the Company completed the financial
closing with the U.S. Department of Energy (DOE) of a $96.8 million loan
guarantee to construct the Companys planned 22-megawatt-net power plant at Neal
Hot Springs in Eastern Oregon. Neal Hot Springs was the first geothermal project
to complete a loan guarantee under the DOEs Title XVII loan guarantee program,
which was created by the Energy Policy Act of 2005 to support the deployment of
innovative clean energy technologies. The DOE loan guarantee will guarantee a
loan from the U.S. Treasurys Federal Financing Bank. The $96.8 million Federal
Financing Bank loan represents 67% of total project cost. When combined with the
previously announced equity investments by the projects partner, Enbridge Inc.,
the loan provided 100% of the anticipated capital remaining to fully construct
the project.
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. Subsequent to the end of the quarter, 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.
-88-
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 its early stages of operation that will be allowed to offset
future earnings. Stock-based compensation is another significant area that
impacts that recognition of deferred income taxes. Compensation that has been
provided to employees and contractors based upon the value of the issuance of
stock options is reported as an operating cost. However, this compensation is
not an allowable deduction for income tax purposes. At the end of the fiscal
year, the Companys significant tax differences would ultimately result in the
recognition of an asset; however, due to the uncertainty surrounding future
earnings, an allowance has been calculated that effectively removes the asset.
The Company continues to track the financial elements that comprise the deferred
income tax calculation and will remove or reduce the asset allowance if the
Company is determined to be in position where it is likely to produce
earnings.
-89-
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, 2013, 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
|
$ 12,145,456
|
$ 475,521
|
$ 1,100,943
|
$ 1,093,763
|
$ 9,475,229
|
Capital Leases
|
69,039
|
48,118
|
20,921
|
-
|
-
|
Note Payable
(1)
|
30,505,500
|
323,167
|
1,140,803
|
1,223,579
|
27,817,951
|
Construction Loan
(2)
|
70,997,780
|
3,419,927
|
6,795,375
|
6,505,003
|
54,277,475
|
Note Payable, Settlement Agreement
(3)
|
1,850,314
|
761,865
|
851,935
|
236,514
|
-
|
|
(1)
|
Long-term note obligation with Prudential Capital Group
scheduled for to be repaid over the next 24 years.
|
|
(2)
|
Construction 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
5 years.
|
-90-
Off Balance Sheet Arrangements
As of December 31, 2013, the Company does not have any off
balance sheet arrangements.
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk
Interest Risk on Investments
At December 31, 2013, the Company held investments of
$29,623,935 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 power purchase contracts for the Raft River, Neal Hot Springs and
San Emidio power plants. These types of arrangement will be the model for power
purchase contracts planned for future power plants.
Item 8. 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.
-91-
U.S. GEOTHERMAL INC.
________
Consolidated Financial Statements
December 31, 2013
218 North Bernard
Spokane,
WA 99201
To the Board of Directors and
Stockholders of U.S.
Geothermal, Inc.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING
FIRM
We have audited the accompanying consolidated balance sheets of
U.S. Geothermal, Inc. as of December 31, 2013 and 2012, and the related
consolidated statements of operations, cash flows, and changes in stockholders
equity, for each of the years 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 audits 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, 2013 and 2012, and the results of its
operations and its cash flows for each of the years then ended in conformity
with accounting principles generally accepted in the United States of America.
MartinelliMick PLLC
Spokane, Washington
March 24, 2014
U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS
(Stated
in U.S. Dollars)
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current:
|
|
|
|
|
|
|
Cash and
cash equivalents (note 2)
|
$
|
28,736,934
|
|
$
|
12,908,779
|
|
Restricted cash and bonds
(note 3)
|
|
3,081,020
|
|
|
2,995,000
|
|
Trade
accounts receivable
|
|
4,106,806
|
|
|
3,296,890
|
|
Grant proceeds receivable
(note 4)
|
|
-
|
|
|
42,884,200
|
|
Other
current assets
|
|
1,079,262
|
|
|
839,104
|
|
Total current assets
|
|
37,004,022
|
|
|
62,923,973
|
|
|
|
|
|
|
|
|
Investment in equity securities (note 5)
|
|
42,174
|
|
|
65,551
|
|
Restricted cash and bond
reserves (note 3)
|
|
18,815,145
|
|
|
1,426,700
|
|
Property, plant and equipment, net of
accumulated
depreciation (note 6)
|
|
161,583,938
|
|
|
160,578,170
|
|
Intangible assets, net of
accumulated amortization (note 7)
|
|
15,320,018
|
|
|
15,501,702
|
|
|
|
|
|
|
|
|
Total
assets
|
$
|
232,765,297
|
|
$
|
240,496,096
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
$
|
1,611,130
|
|
$
|
1,481,959
|
|
Construction accounts payable
|
|
15,557
|
|
|
1,122,746
|
|
Related party accounts
payable
|
|
3,089
|
|
|
3,391
|
|
Notes
payable
|
|
-
|
|
|
1,000,000
|
|
Retention payable
|
|
-
|
|
|
8,089,704
|
|
Current
portion of capital lease obligations (note 9)
|
|
48,118
|
|
|
45,278
|
|
Current portion of notes
payable (note 11)
|
|
4,127,170
|
|
|
1,576,342
|
|
Total
current liabilities
|
|
5,805,064
|
|
|
13,319,420
|
|
|
|
|
|
|
|
|
Long-term Liabilities:
|
|
|
|
|
|
|
Convertible loan payable
(note 10)
|
|
-
|
|
|
2,125,000
|
|
Long-term
portion of capital lease obligations (note 9)
|
|
20,921
|
|
|
69,039
|
|
Notes payable, less
current portion (note 11)
|
|
99,226,423
|
|
|
102,124,167
|
|
Total
long-term liabilities
|
|
99,247,344
|
|
|
104,318,206
|
|
|
|
|
|
|
|
|
Total
liabilities
|
|
105,052,408
|
|
|
117,637,626
|
|
|
|
|
|
|
|
|
Commitments and
Contingencies (note 16)
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital stock (authorized:
250,000,000 common shares with a $0.001 par value;
issued
and outstanding shares at December 31, 2013 and 2012 were:
102,094,542 and 101,516,764; respectively)
|
|
102,094
|
|
|
101,516
|
|
|
|
|
|
|
|
|
Additional paid-in capital
|
|
100,381,207
|
|
|
99,524,850
|
|
Accumulated other comprehensive loss
|
|
(27,321
|
)
|
|
(3,944
|
)
|
Accumulated deficit
|
|
(30,898,571
|
)
|
|
(32,845,150
|
)
|
|
|
69,557,409
|
|
|
66,777,272
|
|
|
|
|
|
|
|
|
Non-controlling interests (note 17)
|
|
58,155,480
|
|
|
56,081,198
|
|
Total
stockholders equity
|
|
127,712,889
|
|
|
122,858,470
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity
|
$
|
232,765,297
|
|
$
|
240,496,096
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
-F-1-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Stated in U.S.
Dollars)
|
|
For
the Year Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Plant Revenues:
|
|
|
|
|
|
|
Energy sales
|
$
|
26,986,049
|
|
$
|
9,358,203
|
|
Energy credit sales
|
|
384,885
|
|
|
400,743
|
|
Total plant operating revenues
|
|
27,370,934
|
|
|
9,758,946
|
|
|
|
|
|
|
|
|
Plant Expenses:
|
|
|
|
|
|
|
Plant production expenses
|
|
7,704,871
|
|
|
5,910,880
|
|
Depreciation and
amortization
|
|
6,454,151
|
|
|
3,620,790
|
|
Total plant
operating expenses
|
|
14,159,022
|
|
|
9,531,670
|
|
|
|
|
|
|
|
|
Net Income from Plant Operations
|
|
13,211,912
|
|
|
227,276
|
|
|
|
|
|
|
|
|
Expenses (Income):
|
|
|
|
|
|
|
Corporate
administration
|
|
881,880
|
|
|
827,015
|
|
Professional and management fees
|
|
1,284,936
|
|
|
766,601
|
|
Salaries and
wages
|
|
2,135,945
|
|
|
1,102,751
|
|
Stock based compensation
|
|
756,935
|
|
|
940,132
|
|
Travel and
promotion
|
|
202,060
|
|
|
165,107
|
|
Exploration costs
|
|
39,482
|
|
|
158,764
|
|
Interest expense
|
|
3,895,890
|
|
|
160,830
|
|
Other (income) expenses
|
|
(115,865
|
)
|
|
437,601
|
|
Total
expenses (income)
|
|
9,081,263
|
|
|
4,558,801
|
|
|
|
|
|
|
|
|
Net Income (Loss) Before Income Tax
Expense
|
|
4,130,649
|
|
|
(4,331,525
|
)
|
|
|
|
|
|
|
|
Net Income Tax Expense (note 8):
|
|
|
|
|
|
|
Income taxes
|
|
1,578,000
|
|
|
-
|
|
Effect of net
deferred tax assets
|
|
(1,578,000
|
)
|
|
-
|
|
Net
income tax expense
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
Net Income (Loss)
|
|
4,130,649
|
|
|
(4,331,525
|
)
|
|
|
|
|
|
|
|
Net (income) loss
attributable to the non-controlling interests
|
|
(2,184,070
|
)
|
|
1,372,958
|
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to U.S. Geothermal Inc.
|
|
1,946,579
|
|
|
(2,958,567
|
)
|
|
|
|
|
|
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
Unrealized income (loss) on investment in equity securities
|
|
(23,377
|
)
|
|
4,605
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss) Attributable to
U.S.
Geothermal Inc.
|
$
|
1,923,202
|
|
$
|
(2,953,962
|
)
|
|
|
|
|
|
|
|
Basic Net Income (Loss) Per Share
Attributable to U.S.
Geothermal Inc.
|
$
|
0.02
|
|
$
|
(0.03
|
)
|
Diluted Net
Income (Loss) Per Share Attributable to U.S.
Geothermal Inc.
|
$
|
0.02
|
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
Weighted Average Number of Shares Outstanding for Basic
Calculations
|
|
101,795,364
|
|
|
87,847,308
|
|
Weighted Average Number of Shares, Stock Options and
Warrants Outstanding for Diluted Calculations
|
|
123,497,883
|
|
|
102,155,529
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
-F-2-
U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Stated in U.S. Dollars)
|
|
For
the Year Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Operating Activities:
|
|
|
|
|
|
|
Net Income (Loss)
|
$
|
4,130,649
|
|
$
|
(4,331,525
|
)
|
Adjustments to reconcile net
income (loss) to total cash provided by operating activities:
|
|
|
|
|
|
|
Depreciation and amortization
|
|
6,575,266
|
|
|
3,682,581
|
|
Stock based compensation
|
|
756,935
|
|
|
940,132
|
|
Stock based officer bonus
|
|
100,000
|
|
|
-
|
|
Loss on disposal of water rights
|
|
-
|
|
|
548,701
|
|
Net changes in:
|
|
|
|
|
|
|
Trade accounts receivable, operating
|
|
(809,916
|
)
|
|
(169,731
|
)
|
Accounts payable and accrued liabilities
|
|
128,868
|
|
|
(1,004,686
|
)
|
Prepaid expenses and other
|
|
(240,158
|
)
|
|
(512,166
|
)
|
Total cash provided by operating
activities
|
|
10,641,644
|
|
|
(846,694
|
)
|
|
|
|
|
|
|
|
Investing Activities:
|
|
|
|
|
|
|
Purchases
of property, plant and equipment
|
|
(13,868,842
|
)
|
|
(8,807,798
|
)
|
Proceeds from ITC cash
grants receivable
|
|
40,113,741
|
|
|
10,784,530
|
|
Cash
received from consolidation of subsidiary
|
|
-
|
|
|
592,330
|
|
Funding of restricted
cash reserves and bonds
|
|
(17,474,465
|
)
|
|
(1,501,700
|
)
|
Total cash provided (used) by investing activities
|
|
8,770,434
|
|
|
1,067,362
|
|
|
|
|
|
|
|
|
Financing Activities:
|
|
|
|
|
|
|
Issuance of share
capital, net of share issuance costs
|
|
-
|
|
|
5,488,947
|
|
Contributions from non-controlling interest
|
|
7,460
|
|
|
10,080,902
|
|
Distributions to
non-controlling interest
|
|
(117,248
|
)
|
|
(119,476
|
)
|
Proceeds
from debt obligations
|
|
16,570,400
|
|
|
-
|
|
Principal payments on
notes payable and other obligations
|
|
(19,999,257
|
)
|
|
(8,973,577
|
)
|
Principal
payments on capital lease
|
|
(45,278
|
)
|
|
(58,144
|
)
|
Total cash provided (used) by financing activities
|
|
(3,583,923
|
)
|
|
6,418,652
|
|
|
|
|
|
|
|
|
Increase in Cash and Cash Equivalents
|
|
15,828,155
|
|
|
6,639,320
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, Beginning of
Year
|
|
12,908,779
|
|
|
6,269,459
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents, End of Year
|
$
|
28,736,934
|
|
$
|
12,908,779
|
|
|
|
|
|
|
|
|
Supplemental Disclosures:
|
|
|
|
|
|
|
Non-cash investing and
financing activities:
|
|
|
|
|
|
|
Purchase of property and
equipment on account
|
$
|
1,107,189
|
|
$
|
6,008,629
|
|
Construction and development paid directly with construction loans
|
|
745,105
|
|
|
54,793,354
|
|
Net assets and
liabilities received from consolidation of subsidiary
|
|
-
|
|
|
45,386,103
|
|
Equipment
purchased with capital leases
|
|
-
|
|
|
155,000
|
|
Capitalized accrued
interest
|
|
-
|
|
|
2,749,081
|
|
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
|
|
6,973,502
|
|
|
346,889
|
|
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, 2013 and 2012
(Stated in U.S.
Dollars)
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
Accumulated
|
|
|
Non-
|
|
|
|
|
|
|
Number of
|
|
|
Common
|
|
|
Paid-In
|
|
|
Accumulated
|
|
|
Comprehensive
|
|
|
controlling
|
|
|
|
|
|
|
Shares
|
|
|
Shares
|
|
|
Capital
|
|
|
Deficit
|
|
|
Income
|
|
|
Interest
|
|
|
Totals
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011
|
|
84,989,853
|
|
$
|
84,990
|
|
$
|
92,921,978
|
|
$
|
(29,886,584
|
)
|
$
|
(8,549
|
)
|
$
|
43,812,275
|
|
$
|
106,924,110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock issued under At Market Issuance Sales
agreement and a registered direct offering agreement (note 12)
|
|
16,526,911
|
|
|
16,526
|
|
|
5,482,420
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
5,498,946
|
|
Equity contributions and note conversion by non-controlling
interest Oregon USG Holdings LLC (note 17)
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
13,761,358
|
|
|
13,761,358
|
|
Distributions to non-controlling interest
entity
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(119,476
|
)
|
|
(119,476
|
)
|
Broker fees
|
|
-
|
|
|
-
|
|
|
(10,000
|
)
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(10,000
|
)
|
Stock compensation
|
|
-
|
|
|
-
|
|
|
1,130,452
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
1,130,452
|
|
Unrealized income on investment
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
4,605
|
|
|
-
|
|
|
4,605
|
|
Net loss
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2,958,566
|
)
|
|
-
|
|
|
(1,372,959
|
)
|
|
(4,331,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
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, 2013
(Stated in
U.S. Dollars)
NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS
U.S. Geothermal Inc. (formerly U.S. Cobalt 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.
All references to dollars or $ are to United States dollars
and all references to CDN are to Canadian dollars.
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);
and
|
|
xiii)
|
U.S. Geothermal Guatemala, S.A. (organized in
Guatemala)
|
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, 2013, $7.9 million in USG Oregon LLC funds were deposited at PNC
Bank and $16.4 million in Oregon USG Holdings LLC funds were deposited at
Sterling Bank, and were unavailable for immediate corporate needs. The
allocation of these funds to the owners of USG Oregon LLC is subject to
completion of negotiations regarding the final ownership percentages. 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, 2013 and 2012, there were no balances that
were over 90 days past due and no balance in allowance for doubtful accounts was
recognized.
-F-6-
Grant Accounts Receivable
For
receivables expected to be received from grants from Federal or State agencies,
the Company records the receivable amounts net of the funds expected to be
received which may be less than the total amounts requested on the actual grant
applications. Therefore, no allowance accounts are considered to be necessary
for receivables from grants at December 31, 2013 and 2012.
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 through December 31, 2013. At December
31, 2013, the Companys total cash balance, excluding money market funds, was
$21,005,464, and bank deposits amounted to $21,268,264. The primary difference
was due to outstanding checks and deposits. Of the bank deposits, $19,700,267
was not covered by or was in excess of FDIC insurance guaranteed limits. At
December 31, 2013, the Companys money market funds invested in government
backed securities totaled $29,623,935 and were not subject to deposit insurance.
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.
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.
-F-7-
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 are expensed
when incurred. Employee training time is expensed when incurred.
Depreciation is calculated on a straight-line basis over the
estimated useful life of the asset. Where appropriate, terms of property rights
and revenue contracts can influence the determination of estimated useful lives.
Estimated useful lives 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, 2013, 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.
-F-8-
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 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.
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 (Losses) Per Share
The Company follows financial accounting standards, which
provides for calculation of "basic" and "diluted" earnings (losses) 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, 2013 and 2012 were
124,494,963 and 122,768,560; 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.
-F-9-
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.
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.
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 losses, total assets, or
stockholders equity as previously reported.
Recent Accounting Pronouncements
Management has considered all recent accounting pronouncements.
The following pronouncement was deemed applicable to our financial statements.
Presentation of an Unrecognized Tax Benefit
In July 2013, FASB issued Accounting Standards Update No. 2013-11
(Update 2013-11),
Presentation of an Unrecognized Tax Benefit When a Net
Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward
Exists
(Topic 740). Update 2013-11 provides guidance on the presentation of
unrecognized tax benefits that are associated with a net operating loss
carryforward, a similar tax loss, or a tax credit carryforward. Update 2011-05
is effective for fiscal years and interim periods within those years, beginning
after December 15, 2013. Management is still evaluating the impact of this
update, and expects that it may impact the presentation of its financial
statements.
-F-10-
NOTE 3 RESTRICTED CASH AND BOND RESERVES
During the quarter ended September 30, 2013, the Company
finalized the terms of the loan agreements with the Department of Energy and the
Prudential Capital Group. Under the terms of the loan agreements, various bond
and cash reserves were 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
|
|
|
2013
|
|
|
2012
|
|
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
|
|
|
19,848
|
|
|
-
|
|
U.S. Department of Energy,
Debt Service Reserve
|
|
|
2,191,172
|
|
|
-
|
|
U.S. Department of Energy, Construction Loan
Bond
|
|
|
-
|
|
|
2,125,000
|
|
|
|
|
|
|
|
|
|
|
|
$
|
3,081,020
|
|
$
|
2,995,000
|
|
Long-term restricted cash and bond reserves:
|
|
|
December 31,
|
|
Restricting Entities/Purpose
|
|
|
2013
|
|
|
2012
|
|
Nevada Energy, PPA Security
Bond
|
|
$
|
1,468,898
|
|
$
|
1,426,700
|
|
Prudential Capital Group, Debt Service
Reserves
|
|
|
1,594,437
|
|
|
-
|
|
Prudential Capital Group,
Maintenance Reserves
|
|
|
751,183
|
|
|
-
|
|
Prudential Capital Group, Well Reserves
|
|
|
53,072
|
|
|
-
|
|
U.S. Department of Energy,
Operations Reserves
|
|
|
270,000
|
|
|
-
|
|
U.S. Department of Energy, Debt Service
Reserves
|
|
|
2,668,179
|
|
|
-
|
|
U.S. Department of Energy,
Short Term Well Field Reserves
|
|
|
4,507,391
|
|
|
-
|
|
U.S. Department of Energy, Long-Term Well
Field Reserves
|
|
|
4,501,191
|
|
|
-
|
|
U.S. Department of Energy,
Capital Expenditure Reserves
|
|
|
3,000,794
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
$
|
18,815,145
|
|
$
|
1,426,700
|
|
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. The construction bond was required by the Loan
Guarantee Agreement with the Department of Energy at Neal Hot Springs and was
released upon completion of the plant facility. 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, 2013.
-F-11-
NOTE 4 GRANT PROCEEDS RECEIVABLE
USG Nevada LLC
The Company submitted
an application on July 17, 2012, to the United States Department of Treasury for
an ITC cash grant of approximately $11.70 million. In March 2013, the remaining
cash grant balance of $1.05 million, for items included in the original
submission, was received from the Treasury. The total proceeds from this grant
offset a portion of the construction costs of the new power plant located in San
Emidio, Nevada that was placed into service for financial reporting purposes on
September 1, 2012. As of December 31, 2013, all proceeds expected from this cash
grant have been received.
USG Oregon LLC
The Company submitted
an application for an ITC cash grant (ITC grant) to the United States
Department of Treasury in the first quarter of 2013. The Company also submitted
an application to Oregon Department of Energy for a Business Energy Tax Credit
(BETC) for qualified construction purchases related to the project located at
Neal Hot Springs, Oregon. The Company received $7,364,200 from the BETC program.
Proceeds collected on the ITC grant request totaled $32,749,541, which included
a reduction of 8.7% federal sequestration. The net proceeds from the grants have
been used to offset the construction costs of the power plant. As of December
31, 2013, all of the expected proceeds from these two programs were
collected.
NOTE 5 INVESTMENT IN EQUITY SECURITIES
Investments in equity securities (150,000 shares of Alterra
Power Corp, a publicly traded renewable energy company) activities consisted of
the following:
|
|
Amount
|
|
Available-for-sale equity securities:
|
|
|
|
Cost
basis
|
$
|
88,515
|
|
Net
unrealized losses
|
|
(22,355
|
)
|
Foreign exchange losses
|
|
(609
|
)
|
Fair value
at December 31, 2012
|
|
65,551
|
|
Net unrealized
losses
|
|
(20,551
|
)
|
Foreign exchange losses
|
|
(2,826
|
)
|
Fair
value at December 31, 2013
|
$
|
42,174
|
|
NOTE 6 - PROPERTY, PLANT AND EQUIPMENT
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 cost 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-12-
During the year ended December 31, 2012, the Company completed
both the San Emidio, Nevada and Neal Hot Springs, Oregon projects. The new San
Emidio power plant achieved commercial operation on May 25, 2012. The Neal Hot
Springs three power producing units, transmission lines, well field and other
supporting structures were completed and the plant achieved commercial operation
on November 16, 2012.
Property, plant and equipment, at cost, are summarized as
follows:
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Land
|
$
|
1,603,509
|
|
$
|
1,603,509
|
|
Power production plant
|
|
161,868,687
|
|
|
159,742,109
|
|
Grant proceeds for power
plants
|
|
(52,965,236
|
)
|
|
(54,630,755
|
)
|
Wells
|
|
67,620,661
|
|
|
67,365,362
|
|
Grant proceeds for wells
|
|
(3,464,555
|
)
|
|
(3,233,831
|
)
|
Furniture and equipment
|
|
1,462,312
|
|
|
1,356,144
|
|
|
|
176,125,378
|
|
|
172,202,538
|
|
Less: accumulated depreciation
|
|
(20,895,943
|
)
|
|
(14,502,362
|
)
|
|
|
155,229,435
|
|
|
157,700,176
|
|
Construction in progress
|
|
6,354,503
|
|
|
2,877,994
|
|
|
$
|
161,583,938
|
|
$
|
160,578,170
|
|
The Company capitalized interest costs as a component of the
Neal Hot Springs and San Emidio projects as follows:
|
|
For
the Year Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Total interest expense
incurred
|
$
|
3,687,742
|
|
$
|
2,909,911
|
|
Capitalized interest
|
|
-
|
|
|
2,749,081
|
|
Depreciation expense charged to plant operations and
administrative costs for the years ended December 31, 2013 and 2012, was
$6,393,581 and $3,508,709; respectively.
-F-13-
Changes in Construction in Progress are summarized as follows:
|
|
Year
Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Beginning balances
|
$
|
2,877,994
|
|
$
|
145,987,128
|
|
Development/construction
|
|
3,694,978
|
|
|
64,564,914
|
|
Grant
reimbursements and rebates
|
|
(33,325
|
)
|
|
(55,244,491
|
)
|
Transfers into production
|
|
(185,144
|
)
|
|
(152,429,557
|
)
|
Ending balances
|
$
|
6,354,503
|
|
$
|
2,877,994
|
|
Construction in Progress, at cost, consisting of the following
projects/assets by location are as follows:
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Raft River, Idaho:
|
|
|
|
|
|
|
Unit
II, power plant, substation and transmission lines
|
$
|
750,493
|
|
$
|
750,493
|
|
Unit II,
well construction
|
|
2,121,502
|
|
|
2,100,862
|
|
|
|
2,871,995
|
|
|
2,851,355
|
|
San Emidio, Nevada:
|
|
|
|
|
|
|
Unit
II, power plant, substation and transmission lines
|
|
3,910
|
|
|
-
|
|
Unit II,
well construction
|
|
1,753,299
|
|
|
26,639
|
|
|
|
1,757,209
|
|
|
26,639
|
|
El Ceibillo, Republic of Guatemala:
|
|
|
|
|
|
|
Well Construction
|
|
1,725,299
|
|
|
-
|
|
|
|
1,725,299
|
|
|
-
|
|
|
$
|
6,354,503
|
|
$
|
2,877,994
|
|
-F-14-
NOTE 7 INTANGIBLE ASSETS
Intangible assets, at cost, are summarized by project location
as follows:
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
In operation:
|
|
|
|
|
|
|
Neal Hot Springs, Oregon:
|
|
|
|
|
|
|
Geothermal water and mineral rights
|
$
|
625,337
|
|
$
|
-
|
|
San Emidio, Nevada:
|
|
|
|
|
|
|
Geothermal water and mineral rights
|
|
4,825,220
|
|
|
4,825,220
|
|
Less: accumulated
amortization
|
|
(935,749
|
)
|
|
(754,064
|
)
|
|
|
4,436,006
|
|
|
4,071,156
|
|
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:
|
|
|
|
|
|
|
Surface water rights
|
|
451,299
|
|
|
451,299
|
|
|
|
|
|
|
|
|
Neal Hot Springs, Oregon:
|
|
|
|
|
|
|
Geothermal water and mineral rights
|
|
-
|
|
|
625,336
|
|
|
|
|
|
|
|
|
Guatemala
City, Guatemala:
|
|
|
|
|
|
|
Geothermal water and mineral rights
|
|
625,000
|
|
|
625,000
|
|
|
|
|
|
|
|
|
Gerlach, Nevada:
|
|
|
|
|
|
|
Geothermal water and mineral rights
|
|
997,000
|
|
|
997,000
|
|
|
|
|
|
|
|
|
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
|
)
|
|
|
10,805,210
|
|
|
11,430,546
|
|
|
|
|
|
|
|
|
|
$
|
15,241,216
|
|
$
|
15,501,702
|
|
Amortization expense was charged to plant operations for the
years ended December 31, 2013 and 2012 that amounted to $181,685 and $173,872;
respectively.
Estimated aggregate amortization expense for the next five
years is as follows:
|
|
Projected
|
|
|
|
Amounts
|
|
Years ending December 31,
|
|
|
|
2014
|
$
|
181,685
|
|
2015
|
|
181,685
|
|
2016
|
|
181,685
|
|
2017
|
|
181,685
|
|
2018
|
|
181,685
|
|
|
|
|
|
|
$
|
908,425
|
|
-F-15-
NOTE 8 PROVISION FOR INCOME TAXES
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. A valuation
allowance is recorded against deferred tax assets if management does not believe
the Company has met the more likely than not standard imposed by accounting
standards to allow recognition of such an asset.
At December 31, 2013, the Company had net deferred tax assets
calculated at an expected rate, noted in the table below, of approximately
$10,742,000 (December 31, 2012 - $11,109,000). As management of the Company
cannot determine that it is more likely than not that the Company will realize
the benefit of the net deferred tax asset, a valuation allowance equal to the
net deferred tax asset was recorded at December 31, 2013 and 2012. For the
current year ended December 31, 2013, the Company has recognized the net
deferred income tax asset to the extent of the impact created from current book
earnings. During the year ended December 31, 2013, the Company engaged a tax
matters consultant to evaluate the value and timing of adjusting the deferred
tax valuation allowance. The Company anticipates that any tax obligations will
be fully offset by the utilization of prior reserved deferred tax benefits for
the year ended December 31, 2013.
The significant components of the net deferred tax asset
calculated with the estimated effective income tax rate at December 31, 2013 and
2012 were as follows:
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
Deferred tax assets*:
|
|
|
|
|
|
|
Net operating loss carry forward
|
$
|
38,400,000
|
|
$
|
20,983,000
|
|
Stock based
compensation
|
|
1,868,000
|
|
|
1,532,000
|
|
|
|
|
|
|
|
|
Deferred tax liabilities*:
|
|
|
|
|
|
|
Depreciation and amortization
|
|
(29,554,000
|
)
|
|
(11,406,000
|
)
|
Net deferred income tax asset
|
|
10,714,000
|
|
|
11,109,000
|
|
Estimated deferred tax asset
recognized and utilized in current period
|
|
(1,578,000
|
)
|
|
-
|
|
Deferred tax asset valuation allowance
|
|
(9,136,000
|
)
|
|
(11,109,000
|
)
|
Net deferred tax asset
|
$
|
-
|
|
$
|
-
|
|
* - significant components of
deferred assets and liabilities are considered to be long-term.
The Companys estimated effective income tax rate is summarized
as follows:
|
|
For
the Years Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
U.S. Federal statutory rate
|
|
34.0%
|
|
|
34.0%
|
|
Average State income tax, net of federal tax
effect
|
|
4.2
|
|
|
4.2
|
|
Production tax credits
|
|
-
|
|
|
(2.0
|
)
|
Net
effective tax rate
|
|
38.2%
|
|
|
36.2%
|
|
-F-16-
At December 31, 2013, the Company had net income tax operating
loss carry forwards of approximately $101,414,000 ($57,963,000 in December 31,
2012), which expire in the years 2023 through 2033. The change in the allowance
account from December 31, 2012 to December 31, 2013 was a decrease of $1,295,000
for the anticipated deferred tax allocations based on 2013 income.
The change in the allowance account is summarized as follows:
|
|
For
the Year Ended December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Change in net operating loss
|
$
|
16,258,000
|
|
$
|
3,976,000
|
|
Change in estimated effective tax rate
|
|
614,000
|
|
|
-
|
|
Net change in difference
between book and tax stock compensation costs
|
|
251,000
|
|
|
230,000
|
|
Estimated deferred tax asset recognized and
utilized in current period
|
|
(1,578,000
|
)
|
|
|
|
Change in period book to
income tax depreciation
|
|
(17,518,000
|
)
|
|
(2,499,000
|
)
|
|
$
|
(1,973,000
|
)
|
$
|
1,707,000
|
|
At December 31, 2013, Raft River Energy I LLC has a book-to-tax
difference of $35.7 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, 2013, USG
Oregon LLC has a book-to-tax difference of $38.1 million due to the acceleration
of depreciation.
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.
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 year ended
December 31, 2013, nine months ended December 31, 2012 and the fiscal year ended
March 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 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, 2013, the nine months
ended December 31, 2012 and the fiscal year ended March 31, 2012 could be
subject to agency examinations as of December 31, 2012. No filings are currently
under examination. No adjustments have been made to reduce the estimated income
tax benefit at fiscal year end. Any valuations relating to these income tax
provisions will comply with U.S. generally accepted accounting
principles
.
NOTE 9 - 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.
-F-17-
The scheduled future lease payments for the three contracts are
presented as follows:
|
|
|
Capital Lease
|
|
Years ending
December 31,
|
|
|
Amounts
|
|
2014
|
|
$
|
50,997
|
|
2015
|
|
|
21,249
|
|
Total future payments
|
|
|
72,246
|
|
|
|
|
|
|
Less: imputed interest portion
|
|
|
(3,207
|
)
|
|
|
$
|
69,039
|
|
|
|
|
|
|
Allocation of capital lease obligations:
|
|
|
|
|
Current
portion
|
|
$
|
48,118
|
|
Long-term portion
|
|
|
20,921
|
|
|
|
$
|
69,039
|
|
At December 31, 2013, the net book value of the equipment under
capital lease amounted to $81,301 ($155,000, less $73,699 accumulated
amortization).
NOTE 10 CONVERTIBLE NOTE PAYABLE
On August 5, 2011, the Oregon USG Holdings, LLC (Oregon
Holdings), a subsidiary of the Company, signed a convertible note agreement
with our equity partner (Enbridge Inc.). The principal of the loan totaled
$2,125,000, and accrued interest at a rate of 4.75% per annum. The loan balance
plus accrued interest would have converted to an equity interest in Oregon
Holdings upon the earliest of a conversion event or April 1, 2014, if unpaid.
Conversion events include the failure to obtain the Section 1603 ITC cash grant
funds by the Project. The converted balance would have increased Enbridge Inc.s
ownership at a ratio of 1.5% for each $1 million contributed. During the year
ended December 31, 2013, the principal of $2,125,000 was paid in full without
conversion to an equity interest. At December 31, 2013, accrued and unpaid
interest on the loan totaled $208,061.
NOTE 11 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 planned 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 grant. 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 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, 2013 totaled $70,997,780
(estimated current portion $3,419,927).
-F-18-
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, 2013
|
|
|
(12,060,185
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Loan balance at December 31,
2013
|
|
$
|
70,997,780
|
|
|
|
|
* - 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 9.0 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. The loan balance at December 31, 2013 totaled
$1,850,314 (estimated current portion $378,698).
-F-19-
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 (the
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 operating results 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 project and
the equity interests in USG Nevada LLC. At December 31, 2013, the balance of the
loan was $30,505,500 (estimated current portion $323,167).
Based upon the terms of the notes payable and expected
conditions that may impact some of those terms, the estimated annual principal
payments were calculated as follows:
For the Year Ended
|
|
|
Principal
|
|
December 31,
|
|
|
Payments
|
|
2014
|
|
$
|
4,121,792
|
|
2015
|
|
|
4,319,468
|
|
2016
|
|
|
4,410,770
|
|
2017
|
|
|
4,332,491
|
|
2018
|
|
|
4,073,645
|
|
Thereafter
|
|
|
82,095,427
|
|
|
|
|
|
|
|
|
$
|
103,353,593
|
|
NOTE 12 - 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.
During the quarter ended September 30, 2013, the Company issued
577,778 shares of common stock to an employee of the Company at prices between
$0.35 and $0.36 per share under the terms of an employment agreement.
On December 21, 2012, the Company issued 11,810,816 common
stock shares at $0.37 under a registered direct offering with a limited number
of investors and collected $4,087,802, net of broker fees and other costs of
$282,200.
During the quarter ended September 30, 2012, the Company issued
1,250,000 common stock shares at prices between $0.312 and $0.355 under an At
Market Issuance Sales agreement with Lincoln Park Capital.
During the quarter ended June 30, 2012, the Company issued
3,375,503 shares of common stock at prices between $0.341 and $0.536 under an At
Market Issuance Sales agreement with Lincoln Park Capital.
-F-20-
During the quarter ended March 31, 2012, the Company issued
90,592 shares of common stock at a price of $0.65 under an At Market Issuance
Sales agreement with Lincoln Park Capital.
NOTE 13 - 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 December 2009 and 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, 2013, the Company can issue stock option grants totaling up to
15,314,181 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,
2013, the Company had 11,888,250 options granted and outstanding.
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.
On August 24, 2012, the Company granted 2,917,000 stock options
to employees exercisable at a price of $0.31 until August 24, 2017.
On July 23, 2012, 652,500 stock options exercisable at a price
of $2.41 expired without exercise.
On January 22, 2012, 157,500 stock options exercisable at a
price of $1.40 CDN expired without exercise.
-F-21-
The following table reflects the summary of stock options
outstanding at December 31, 2011 and changes for the years ended December 31,
2013 and 2012:
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
|
|
|
|
|
Number of
|
|
|
Exercise
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
|
shares under
|
|
|
Price Per
|
|
|
Fair
|
|
|
Intrinsic
|
|
|
|
|
options
|
|
|
Share
|
|
|
Value
|
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance outstanding, December 31, 2011
|
|
8,132,625
|
|
$
|
1.26
|
|
$
|
0.71
|
|
$
|
5,752,781
|
|
|
Forfeited/Expired
|
|
(810,000
|
)
|
|
2.21
|
|
|
0.74
|
|
|
(600,246
|
)
|
|
Exercised
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Granted
|
|
2,917,000
|
|
|
0.31
|
|
|
0.16
|
|
|
453,774
|
|
|
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
|
|
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 Years Ended December 31,
|
|
|
2013
|
2012
|
|
Dividend yield
|
0
|
0
|
|
Expected volatility
|
71-81%
|
65-70%
|
|
Risk free interest rate
|
0.27-0.82%
|
0.19-0.33%
|
|
Expected life (years)
|
4.63
|
3.17
|
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-22-
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
|
|
The following table summarizes information about the stock
options outstanding at December 31, 2012:
|
|
|
|
OPTIONS OUTSTANDING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REMAINING
|
|
|
NUMBER OF
|
|
|
|
|
|
EXERCISE
|
|
|
NUMBER OF
|
|
|
CONTRACTUAL
|
|
|
OPTIONS
|
|
|
|
|
|
PRICE
|
|
|
OPTIONS
|
|
|
LIFE (YEARS)
|
|
|
EXERCISABLE
|
|
|
INTRINSIC VALUE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2.22
|
|
|
1,465,000
|
|
|
0.63
|
|
|
1,465,000
|
|
$
|
1,786,417
|
|
|
1.78
|
|
|
95,000
|
|
|
0.74
|
|
|
95,000
|
|
|
81,172
|
|
|
0.92
|
|
|
1,704,625
|
|
|
1.40
|
|
|
1,704,625
|
|
|
1,204,713
|
|
|
1.58
|
|
|
68,000
|
|
|
1.73
|
|
|
68,000
|
|
|
26,435
|
|
|
0.86
|
|
|
1,300,000
|
|
|
2.70
|
|
|
1,300,000
|
|
|
752,207
|
|
|
0.83
|
|
|
2,590,000
|
|
|
3.43
|
|
|
2,590,000
|
|
|
1,269,100
|
|
|
0.60
|
|
|
100,000
|
|
|
3.70
|
|
|
75,000
|
|
|
27,054
|
|
|
0.31
|
|
|
2,917,000
|
|
|
4.65
|
|
|
729,250
|
|
|
113,444
|
|
$
|
0.91
|
|
|
10,239,625
|
|
|
2.80
|
|
|
8,026,875
|
|
$
|
5,260,542
|
|
-F-23-
A summary of the status of the Companys nonvested stock
options outstanding at December 31, 2011 and changes during the years ended
December 31, 2013 and 2012 are presented as follows:
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
Average Grant
|
|
|
Average
|
|
|
|
Number of
|
|
|
Date Fair Value
|
|
|
Grant Date
|
|
|
|
Options
|
|
|
Per
Share
|
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested, December 31, 2011
|
|
1,695,000
|
|
$
|
0.83
|
|
$
|
0.50
|
|
Granted
|
|
2,917,000
|
|
|
0.31
|
|
|
0.16
|
|
Vested
|
|
(2,399,250
|
)
|
|
0.69
|
|
|
0.40
|
|
Forfeited/Expired
|
|
-
|
|
|
-
|
|
|
-
|
|
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
|
|
As of December 31, 2013, there was $389,503 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, 2013 and 2012 was $683,143 and $861,277; respectively.
Stock Compensation Plan (Restricted Shares
)
On September 10, 2010, the Company granted officers, directors
and select employees 705,000 common shares that will be distributed in three
six-month vesting periods. The recipients meet the vesting requirements by
maintaining employment and good standing with the Company through the vesting
periods. After vesting, there are no restrictions on the shares. On March 10,
2011, the 705,000 common shares were issued to the recipients and held by the
Company. All of these shares were considered to be issued and outstanding. On
March 11, 2011, 235,000 common shares vested valued at $0.99 per share, and the
shares were released to the qualified recipients. On September 11, 2011, 235,000
common shares vested valued at $0.60 per share and the shares were released to
the qualified recipients. The final 235,000 shares valued at $0.58 vested and
were released on March 11, 2012.
On April 19, 2013, the Company granted an officer and director
300,000 common shares valued at $0.35 per share, which will be 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, 2013 was $73,792.
-F-24-
Stock Purchase Warrants
At December 31, 2013, 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
|
|
-
|
|
|
-
|
|
|
5,905,408
|
|
|
0.50
|
|
On February 2013, 500,000 stock purchase warrants at an
exercise price of $5.00 expired without exercise.
On December 21, 2012, the Company issued 5,905,408 stock
purchase warrants exercisable at a price of $0.50 until December 21, 2017.
On May 23, 2012, the Company issued 118,421 broker warrants at
an exercise price of $0.437.
On March 4, 2012, 2,500,000 stock purchase warrants and 56,000
broker warrants at an exercise price of $1.075 expired without exercise.
NOTE 14 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.
-F-25-
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, 2013 at fair value on a recurring
basis:
|
|
Total
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market accounts *
|
$
|
29,623,935
|
|
$
|
29,623,935
|
|
$
|
-
|
|
$
|
-
|
|
Investment in equity securities
|
|
43,632
|
|
|
-
|
|
|
42,174
|
|
|
-
|
|
|
$
|
29,666,109
|
|
$
|
29,623,935
|
|
$
|
42,174
|
|
$
|
-
|
|
* - 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.
NOTE 15 - RELATED PARTY TRANSACTIONS
At December 31, 2013 and 2012 the amounts of $3,089 and $3,391;
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, 2013 and 2012 amounting to $99,000 and $120,000; respectively.
NOTE 16 - 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 Washoe County Nevada; Republic of Guatemala;
Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River,
Idaho. The Company incurred total lease expenses for the years ended December
31, 2013 and 2012, of $373,039 and $116,227; respectively.
BLM Lease Agreements
The Company believes that it is in compliance with all of the
following lease terms.
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.
-F-26-
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.
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 expire from March 2013 to December 2033. The contracted lease payments
are scheduled for $31,287 for the year ended December 31, 2013.
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 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 5 year extension option.
Tyrell Lane
Under the current contract, the lease
payments were due in monthly installments of $6,535. The current contract
effectively ends January 31, 2014 and will not be renewed. The total office
lease costs incurred under the current contract and the prior contract for years
ended December 31, 2013 and 2012, totaled $78,423 and $76,138; respectively.
-F-27-
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
|
|
2014
|
|
$
|
475,521
|
|
2015
|
|
|
534,828
|
|
2016
|
|
|
566,115
|
|
2017
|
|
|
561,053
|
|
2018
|
|
|
532,710
|
|
Thereafter
|
|
|
9,475,229
|
|
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, and from the Phase Two plants to
other purchasers. These agreements will govern the operational revenues for the
initial phases of the Companys operating activities.
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 25 year
contract signed in December of 2011 that sets the new set rate at $89.70 per
megawatt hour with a 1% annual escalation rate. The new contract allows for a
maximum of 71,300 megawatt hours annually. 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, 2013,
the Company has fund a security bond 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 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.
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 $60,425 and $36,520 for the years ended December 31, 2013
and 2012, respectively.
-F-28-
NOTE 17 JOINT VENTURES/NON-CONTROLLING INTERESTS
Non-controlling interests included on the consolidated balance
sheets of the Company are detailed as follows:
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Gerlach Geothermal LLC
interest held by Gerlach Green Energy, LLC
|
$
|
404,352
|
|
$
|
404,434
|
|
Oregon USG Holdings LLC interest held by
Enbridge Inc.
|
|
35,926,826
|
|
|
33,078,744
|
|
Raft River Energy I LLC
interest held by Raft River I Holdings, LLC
|
|
21,824,302
|
|
|
22,598,020
|
|
|
$
|
58,155,480
|
|
$
|
56,081,198
|
|
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.
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 project in the Neal Hot Springs project located in
Malheur County, Oregon. 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.
Under the initial agreement, the ownership interest began at 20%, and increased
to 35% according to capital contribution levels. On February 20, 2014, a new
agreement was reached with Enbridge that established the ownership interest
percentage at 40%, effective January 1, 2013.
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.
-F-29-
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 the 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 year ended December 31, 2013, RREI made principal
payments on the loan of $755,288. The balance of the loan at December 31, 2013
was $1,380,862. The loan balance and related interest effects are fully
eliminated during the consolidation process.
-F-30-
NOTE 18 CHANGE IN YEAR END FOR FINANCIAL REPORTING
PURPOSES
On July 5, 2012, the Companys Board of Directors approved the
change in the Companys fiscal year end for reporting purposes from March
31
st
to December 31
st
. The change was made to increase
financial reporting efficiency for the consolidated Company, as well as several
of its subsidiaries. The change resulted in a nine month transition period that
began on April 1, 2012 and ended on December 31, 2012. The following summarized
financial information is presented to compare and illustrate operating results
for the periods involved in the transition:
|
|
|
|
|
Nine Months
|
|
|
Three Months
|
|
|
|
|
|
|
Year Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
December 31,
|
|
|
|
2013
|
|
|
2012
|
|
|
2012
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plant operating revenues
|
$
|
27,370,934
|
|
$
|
8,599,859
|
|
$
|
1,159,087
|
|
$
|
9,758,946
|
|
Plant operating expenses
|
|
(14,159,022
|
)
|
|
(7,310,808
|
)
|
|
(2,220,862
|
)
|
|
(9,531,670
|
)
|
Net income (loss) from plant operations
|
|
13,211,912
|
|
|
1,289,051
|
|
|
(1,061,775
|
)
|
|
227,276
|
|
Other expenses (income)
|
|
9,081,263
|
|
|
3,204,718
|
|
|
1,354,083
|
|
|
4,558,801
|
|
Net income (loss)
|
|
4,130,649
|
|
|
(1,915,667
|
)
|
|
(2,415,858
|
)
|
|
(4,331,525
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (income) loss attributable to the
non-
controlling interests
|
|
(2,184,070
|
)
|
|
600,823
|
|
|
772,135
|
|
|
1,372,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to U.S.
Geothermal Inc.
|
|
1,946,579
|
|
|
(1,314,844
|
)
|
|
(1,643,723
|
)
|
|
(2,958,567
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss)
|
|
(23,377
|
)
|
|
(26,946
|
)
|
|
31,551
|
|
|
4,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) attributable
to
U.S. Geothermal Inc.
|
$
|
1,923,202
|
|
$
|
(1,341,790
|
)
|
$
|
(1,612,172
|
)
|
$
|
(2,953,962
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income (loss) per
share
attributable to U.S. Geothermal Inc.
|
$
|
0.02
|
|
$
|
(0.01
|
)
|
$
|
(0.02
|
)
|
$
|
(0.03
|
)
|
Diluted net
income (loss) per share attributable
to
U.S. Geothermal Inc.
|
$
|
0.02
|
|
$
|
(0.01
|
)
|
$
|
(0.02
|
)
|
$
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares
outstanding
for basic calculations
|
|
101,795,364
|
|
|
88,783,972
|
|
|
85,016,732
|
|
|
87,847,308
|
|
Weighted average number of shares
outstanding
for basic and diluted
calculations
|
|
123,497,883
|
|
|
104,180,331
|
|
|
99,690,548
|
|
|
102,155,529
|
|
NOTE 19 - SUBSEQUENT EVENTS
The Company has evaluated events and transactions that have
occurred after the balance sheet date through March 25, 2014, which is
considered to be the issuance date. The following events were identified for
disclosure:
-F-31-
USG Oregon LLC Financial Partnership Agreement
On February 20, 2014, the Company finalized a financial partnership
agreement with Enbridge Inc. that defined the equity interest in USG Oregon LLC,
a subsidiary of the Company. The final ownership interest of USG Oregon LLC was
calculated in accordance with the terms of the partnership agreement that
specified a 60% interest for U.S. Geothermal Inc. and a 40% interest for
Enbridge Inc. The defined ownership interests were effective January 1, 2013. As
a result of the final agreement, the Company received a $6.2 million cash
distribution from the partnership.
Oregon USG Holdings LLC/USG Oregon LLC Profit
Distribution
On March 10, 2014, Oregon USG Holdings LLC,
Parent Company of USG Oregon LLC, made its first distribution of cash. Oregon
USG Holdings is 60% owned by the Company and 40% owned by Enbridge Inc. Under
the terms of the U.S. Department of Energy loan agreement, distributable cash is
distributed to the equity partners semi-annually (February and August) following
Final Completion, which was achieved on August 1, 2013. The Companys share of
this first distribution is $4.6 million, out of a total distribution to the
partners of $7.7 million, which represents distributable cash generated from the
project since initial operation began in November 2012.
-F-32-
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 Securities Exchange Act of
1934 (Exchange Act)) as of December 31, 2013. 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, 2013.
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.
-92-
The Companys management assessed the effectiveness of the
Companys internal control over financial reporting as of December 31, 2013. 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 1992). Based on its assessment, management
concluded that, as of December 31, 2013, the Companys internal control over
financial reporting is effective based on those criteria.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
As of the end of the period covered by this report, there have
been no changes in internal control over financial reporting (as defined in Rule
13a-15(f) of the Exchange Act) during the year ended December 31, 2013, that
materially affected, or are reasonably likely to materially affect, the
Companys internal control over financial reporting.
Item 9B. Other Information
None.
-93-
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 55, serves as a director of
the Company, a position he has held since September 2011. Mr. Gilles also
currently serves as a Director and Executive Board Officer of the Geothermal
Resource Council. Mr. Gilles is a senior executive with 30 years of experience
in the management, operations, maintenance, engineering, construction and
administration of power and petrochemical plants and their related facilities.
Mr. Gilles primary activities have included the identification, evaluation and
acquisition of existing renewable projects or portfolios, as well as heading
development of new green-field opportunities. 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 20 years of experience in
the natural resource industry and his many years of senior management and
director experience.
Douglas J. Glaspey
:
Age 61, 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.
-94-
Kerry D. Hawkley:
Age 60, 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 63
,
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., Draft Team Fantasy Sports Inc. 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 73
,
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.
-95-
John H. Walker
:
Age 65, 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 117mw 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.
Jonathan Zurkoff:
Age 58, 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 Securities Exchange Act of 1934, as
amended (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, 2013 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.
-96-
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, 2013. 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.
-97-
The three primary components of total direct compensation for
our senior executives are:
-
base salary;
-
annual cash incentive bonus opportunity; and
-
stock options and restricted stock.
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.
During the fiscal year ended December 31, 2013, the Company was
focused on (1) operation and completion of financing for the San Emidio Phase I
geothermal project in Nevada, (2) completion of construction, operation and
financing for the Neal Hot Springs project in Oregon, (3) drilling, conducting
negotiations for PPA and equity partners at the El Ciebello project in
Guatemala, (4) optimizing the operation of the well field at the Raft River
project in Idaho, and (5) the evaluation of potential new geothermal project
acquisitions.
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.
-98-
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.
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, 2013,
stock option grants to executive officers represented approximately 52% of the
total stock option grants to all employees. During the year ended December 31,
2013, 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.
Kunz Employment Agreement
On September 29, 2011, Daniel J. Kunz, our former Chief Executive
Officer, signed an employment agreement that set the amount of time devoted to
the business of the Company to 60 hours per month at a compensation of $120,000
annually. Mr. Kunz was entitled to receive performance bonuses and incentive
stock options as determined by the Companys board of directors, benefits
(including for immediate family) as were or became available to other employees,
and vacation. The Company also provided reasonable life insurance and accidental
death coverage with the proceeds payable to Mr. Kunzs estate or specified
family member. The employment agreement could be terminated by the Company
without notice, payment in lieu of notice, severance or other sums for causes
which include failure to perform in a competent and professional manner,
appropriation of corporate opportunities or failure to disclose a conflict of
interest, conviction which has become final for an indictable offense, fraud,
dishonesty, refusal to follow reasonable and lawful direction of the Company,
breach of fiduciary duty, and a declaration of bankruptcy by or against Mr.
Kunz. Otherwise, the Company could terminate the agreement upon one month written notice. The agreement included
covenants by Mr. Kunz of confidentiality and non-competition, and provided for
equitable relief in the event of breach. In the case of termination of
employment due to a change of control, Mr. Kunz would have received a lump sum
payment equal to 24 monthly installments of his normal compensation. Effective
February 1, 2012, Mr. Kunz agreed to increase his hours to 120 hours per month
at an annual rate of $240,000. Although the employment agreement expired on
December 31, 2012, the terms of the agreement as amended were effective until a
subsequent agreement was finalized. Effective January 1, 2013, the annual salary
for Mr. Kunz was increased to $252,000. Effective April 19, 2013, Mr. Kunz
retired as a director and Chief Executive Officer and the employment agreement
was terminated.
-99-
The Company has entered into an engagement agreement for
executive management advisory services (the "Engagement Agreement") with Daniel
Kunz & Associates LLC ("Kunz & Associates"), a company wholly owned and
managed by Mr. Kunz. The Engagement Agreement is effective April 19, 2013, and
will remain in effect until April 18, 2014 unless earlier terminated in
accordance with its terms or renewed by agreement of both parties. Under the
terms of the Engagement Agreement, Kunz & Associates has agreed to devote
exclusively for the benefit of the Company 60 hours per month of Mr. Kunz's
services. In consideration for the performance by Kunz & Associates of its
responsibilities and duties under the Engagement Agreement, the Company has
agreed to pay to Kunz & Associates a retainer of $12,400 per month. In
addition, Kunz & Associates was paid a bonus of $125,000 upon execution of
the Engagement Agreement. In the event that Mr. Kunz elects on a timely basis to
continue his participation in the Company's health and dental benefit plans in
accordance with the Consolidated Omnibus Budget Reconciliation Act ("COBRA"),
the Company has agreed to reimburse 50% of Mr. Kunz's actual cost of the COBRA
premium. In addition, Mr. Kunz will be eligible to receive stock option awards
under the 2009 Plan at the discretion of the Board. The Company will also
reimburse Kunz & Associates for reasonable incidental, or Chief Executive
Officer pre-approved, expenses incurred in connection with its engagement.
The Engagement Agreement may be terminated by the Company
without notice, payment in lieu of notice, severance payments, benefits, damages
or other sums for cause. In such event, Kunz & Associates will only be
entitled to compensation through the date of termination. The Engagement
Agreement may be terminated by the Company without cause upon one months
written notice. In such event, Kunz & Associates will be entitled to receive
a lump sum payment equal to the balance of payments due under the term of the
contract of Kunz & Associates base annual retainer as described above. The
Engagement Agreement also includes covenants by Kunz & Associates and Mr.
Kunz with respect to the treatment of confidential information, non-competition,
non-solicitation and non-change of control activities, and provides for
equitable relief in the event of breach.
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.
-100-
The Company has agreed to pay to Mr. Gilles an annual base
salary of $375,000, which will increase to $410,000 on April 19, 2014 and 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 within two weeks following completion of a probationary
period which ended June 18, 2013 (the Probationary Period). 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 will be granted stock options to acquire shares of
the Companys common stock with a target value equal to 35% of Mr. Gilles
then-current annual salary, and an exercise price equal to the close of the
market for the date they are granted. 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 (401K) 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 will receive cost reimbursement for a single relocation for costs not to
exceed $35,000.
The Company may terminate Mr. Gilles employment without
cause (which has the meaning commonly ascribed to it at common law and is
defined in the employment agreement) during the Probationary Period upon two
weeks notice. In such event, Mr. Gilles will be paid his salary and reimbursed
for expenses incurred through the date of termination. The Company would not be
obligated to pay Mr. Gilles any unpaid portion of the $100,000 signing bonus
described above, and unvested portions of the 300,000 restricted shares of the
Companys common stock and stock options to acquire 1,250,000 shares of the
Companys common stock described above will be cancelled. 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.
-101-
Following the Probationary Period, 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.
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 401K 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.
-102-
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 30
th
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.
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 401K retirement benefit as is available to other employees of the Company.
In addition, the Company will reimburse Mr. Hawkley for reasonable expenses
incurred in connection with the performance of his duties under the employment
agreement. Mr. Hawkley is entitled to a paid vacation of five weeks within each
12 month period under the terms of the employment agreement.
-103-
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 30
th
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.
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 amended, is effective December 31, 2010,
and will remain in effect until March 31, 2014 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 401K 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.
-104-
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 30
th
day after the
date of termination (which sum would be currently $288,000). The terms cause,
good reason and change of control are defined in the employment agreement.
The employment agreement also includes covenants by Mr. Zurkoff
with respect to the treatment of confidential information and non-competition,
and provides for equitable relief in the event of breach.
-105-
Summary Compensation Table
The following table shows the compensation for the last two
years awarded to or earned by our Chief Executive Officer and each of our three
other most highly compensated executive officers (collectively, our Named
Executive Officers).
Name and principal
position(s)
|
Year Ended
|
Salary
(1)
($)
|
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
|
|
Daniel J. Kunz,
Former Chief Executive
Officer
(retired effective 4/19/13)
|
12/31/12
|
230,000
|
0
|
41,348
|
8,170
|
279,518
|
12/31/13
|
94,726
|
0
|
0
|
0
|
94,726
|
|
Douglas J. Glaspey,
President and Chief
Operating Officer
|
12/31/12
|
210,000
|
0
|
31,806
|
1,035
|
242,841
|
12/31/13
|
215,000
|
10,000
|
39,245
|
1,035
|
262,280
|
|
Kerry D. Hawkley,
Chief Financial Officer
|
12/31/12
|
140,000
|
0
|
25,110
|
0
|
165,110
|
12/31/13
|
163,000
|
10,000
|
32,704
|
0
|
205,704
|
|
Jonathan Zurkoff,
Treasurer and Executive
Vice President
|
12/31/12
|
192,000
|
0
|
22,200
|
0
|
214,200
|
12/31/13
|
192,000
|
27,000
|
30,364
|
0
|
249,364
|
(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.
|
-106-
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, 2013 by our Named Executive Officers.
|
|
Option Awards
|
|
|
Stock Awards
|
|
|
|
Number of
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
Securities
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Market Value of
|
|
|
|
Underlying
|
|
|
Underlying
|
|
|
|
|
|
|
|
|
Shares or Units
|
|
|
Shares or Units of
|
|
|
|
Unexercised
|
|
|
Unexercised
|
|
|
Option
|
|
|
Option
|
|
|
of Stock That
|
|
|
Stock That
Have
|
|
|
|
Options
|
|
|
Options
(1)
|
|
|
Exercise Price
|
|
|
Expiration
|
|
|
Have Not
Vested
|
|
|
Not Vested
|
|
Name
|
|
(#) Exercisable
|
|
|
(#) Unexercisable
|
|
|
($)
|
|
|
Date
|
|
|
(#)
|
|
|
($)
|
|
Douglas J. Glaspey
|
|
150,000
|
|
|
0
|
|
|
0.92
|
|
|
5/26/14
|
|
|
0
|
|
|
0
|
|
Kerry D. Hawkley
|
|
100,000
|
|
|
0
|
|
|
0.92
|
|
|
5/26/14
|
|
|
0
|
|
|
0
|
|
Jonathan Zurkoff
|
|
150,000
|
|
|
0
|
|
|
0.92
|
|
|
5/26/14
|
|
|
0
|
|
|
0
|
|
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
|
|
75,000
|
|
|
25,000
|
|
|
0.31
|
|
|
8/24/17
|
|
|
0
|
|
|
0
|
|
Douglas J. Glaspey
|
|
142,500
|
|
|
47,500
|
|
|
0.31
|
|
|
8/24/17
|
|
|
0
|
|
|
0
|
|
Kerry D. Hawkley
|
|
112,500
|
|
|
37,500
|
|
|
0.31
|
|
|
8/24/17
|
|
|
0
|
|
|
0
|
|
Jonathan Zurkoff
|
|
112,500
|
|
|
37,500
|
|
|
0.31
|
|
|
8/24/17
|
|
|
0
|
|
|
0
|
|
Dennis J. Gilles
|
|
625,000
|
|
|
625,000
|
|
|
0.35
|
|
|
4/19/23
|
|
|
300,000
|
|
|
105,000
|
|
Douglas J. Glaspey
|
|
37,500
|
|
|
112,500
|
|
|
0.46
|
|
|
7/22/18
|
|
|
0
|
|
|
0
|
|
Kerry D. Hawkley
|
|
31,250
|
|
|
93,750
|
|
|
0.46
|
|
|
7/22/18
|
|
|
0
|
|
|
0
|
|
Jonathan Zurkoff
|
|
31,250
|
|
|
93,750
|
|
|
0.46
|
|
|
7/22/18
|
|
|
0
|
|
|
0
|
|
(1)
|
The $0.31 options unexercisable at December 31, 2013 will
fully vest on February 24, 2014.
The $0.35 options unexercisable at
December 31, 2013 will fully vest on October 19, 2014.
The $0.46
options unexercisable at December 31, 2013 will fully vest 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. Kunz, Gilles, Glaspey, Hawkley
and Zurkoff which provide for change-in-control payments.
Mr. Kunzs employment agreement, which terminated upon his
retirement effective April 19, 2013, provided that if within twelve months
following change-in-control Mr. Kunzs employment was terminated either by the
Company without cause or by Mr. Kunz for good reason, then Mr. Kunz would
have been entitled to a lump-sum payment consisting of (a) his prorated base
salary through the date of termination, (b) a severance payment equal to twenty
four times his monthly base salary at termination, and (c) employee medical and
dental coverage for 24 months or until Mr. Kunz commenced alternate employment,
whichever came first, subject to certain limitations and conditions. The terms
cause, good reason and change of control were defined in the
agreement.
-107-
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.
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.
-108-
Director Compensation
The following table summarizes the compensation paid to our
directors during the year ended December 31, 2013.
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
|
30,000
|
0
|
26,163
|
0
|
0
|
0
|
56,163
|
|
Paul A. Larkin
|
40,000
|
0
|
26,163
|
0
|
0
|
0
|
66,163
|
|
Leland L. Mink
|
30,000
|
0
|
26,163
|
0
|
0
|
0
|
56,163
|
|
Dennis J. Gilles
|
9,000
|
0
|
0
|
0
|
0
|
0
|
9,000
|
(1)
|
Stock options are valued at the grant date in accordance
with FASB ASC Topic 718.
|
Directors who are not otherwise remunerated per an employment
agreement are paid $7,500 per quarter and 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.
-109-
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, 2013.
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
|
11,888,250
|
$0.61
|
3,425,931
|
Equity compensation plans not approved by security holders
|
Nil
|
Nil
|
Nil
|
Total
|
11,888,250
|
$0.61
|
3,425,931
|
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 21, 2014, 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 102,714,178 shares of the Companys common stock outstanding as of
March 21, 2014.
|
|
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
|
|
9,980,873
|
(1)
|
|
9.72%
|
|
|
|
|
|
|
|
|
AGF Management Limited
PO Box 50, Toronto
Dominion Bank Tower, 31
st
Floor,
Toronto, ON, Canada M5K
1E9
|
|
5,203,762
|
(2)
|
|
5.07%
|
|
(1)
|
As of January 31, 2013, based on information set forth in
a Schedule 13G filed with the SEC on February 7, 2013 by Sprott Inc.,
which has sole voting and dispositive power over 2,602,493 shares of the
Companys common stock and shared voting and dispositive power over
7,378,380 shares of the Companys voting stock. These shares are held in
accounts managed by subsidiaries of Sprott Inc., none of which, with the
exception of Exploration Capital Partners 2000 Limited Partnership,
beneficially own more than five percent of the class. Exploration Capital
Partners 2000 Limited Partnership has shared voting and dispositive power
over 7,378,380 shares of the Companys common stock.
|
-110-
(2)
|
As of December 30, 2012, based on information set forth
in a Schedule 13G/A filed with the SEC on January 30, 2013 by AGF
Management Limited, which shares voting and dispositive power over
5,203,762 shares of the Companys common stock with AGF Investments Inc.,
its wholly owned subsidiary.
|
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, 2013, by each of our
directors, Named Executive Officers and directors and executive officers as a
group. The percentage of beneficial ownership is based on 102,334,042 shares of
the Companys common stock outstanding as of March 21, 2014.
|
|
Amount and
|
|
|
|
|
|
|
Nature
|
|
|
|
|
Name of Beneficial Owner
|
|
of Beneficial
|
|
|
Percent of
|
|
|
|
Ownership
|
|
|
Class
|
|
Dennis J. Gilles
|
|
1,690,278
|
(1)
|
|
1.65%
|
|
Douglas J. Glaspey
|
|
1,262,457
|
(2)
|
|
1.23%
|
|
Kerry D. Hawkley
|
|
582,500
|
(3)
|
|
*
|
|
Paul A. Larkin
|
|
648,068
|
(4)
|
|
*
|
|
Leland L. Mink
|
|
425,000
|
(5)
|
|
*
|
|
John H. Walker
|
|
424,900
|
(6)
|
|
*
|
|
Jonathan Zurkoff
|
|
748,500
|
(7)
|
|
*
|
|
|
|
|
|
|
|
|
All directors and executive
officers as a group (7 persons)
|
|
5,781,703
|
(8)
|
|
5.63%
|
|
*
|
Less than 1% of the Companys outstanding common stock
|
|
|
(1)
|
Includes 1,137,500 options exercisable within 60 days of
March 21, 2014.
|
(2)
|
Includes 680,000 options exercisable within 60 days of
March 21, 2014.
|
(3)
|
Includes 457,500 options exercisable within 60 days of
March 21, 2014.
|
(4)
|
Includes 350,000 options exercisable within 60 days of
March 21, 2014.
|
(5)
|
Includes 350,000 options exercisable within 60 days of
March 21, 2014.
|
(6)
|
Includes 350,000 options exercisable within 60 days of
March 21, 2014.
|
(7)
|
Includes 653,500 options exercisable within 60 days of
March 21, 2014.
|
(8)
|
Includes 3,978,500 options exercisable within 60 days of
March 21, 2014.
|
-111-
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, Daniel J. Kunz (through April 18, 2013), Paul A.
Larkin, Leland L. Mink and John H. Walker. The majority of the Board, made up of
Mr. Gilles (through April 18, 2013), Mr. Larkin, Dr. Mink and Mr. Walker,
satisfy the applicable independence requirements of the NYSE MKT. Mr. Gilles
(beginning April 19, 2013), Mr. Kunz (through April 18, 2013) 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.
-112-
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, 2013, and 2012 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 $138,202 and $52,482;
respectively.
Audit-Related Fees
The aggregate fees billed to the Company by MartinelliMick PLLC
for the years December 31, 2013 and 2012, 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 and $77,276; respectively. 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, 2013 and 2012 were $32,701 and
$34,331; 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 years ended December 31, 2013 and 2012 that amounted to $20,000
and $4,809; respectively.
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.
The aggregate fees billed to the Company by Hein &
Associates LLP for the years ended December 31, 2013 and 2012, 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 $80,171 and $101,783; 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, 2013 and 2012, for professional
services rendered for tax compliance, tax advice, and tax planning were $15,425
and $27,000; 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, 2013 and 2012.
-113-
All Other Fees
The Company was not billed by MartinelliMick PLLC LLP for any
other services during years ended December 31, 2013 and 2012. Hein &
Associates provided other consulting services for the year ended December 31,
2013 that amounted to $9,190. Hein & Associates did not provide any
additional services for the year ended December 31, 2012.
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
Securities and Exchange Commission. 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, 2013 and 2012, including services related to the
Audit-Related Fees and Tax Fees described above, were approved by the Audit
Committee under its pre-approval policies.
-114-
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. Cobalt Inc. (now
known as U.S. Geothermal Inc.) (Incorporated by reference to exhibit 3.1
to the registrants Form SB-2 registration statement as filed on July 8,
2004)
|
3.2
|
|
Certificate of Domestication of Non-U.S. Corporation
(Incorporated by reference to exhibit 3.2 to the 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)
|
3.7
|
|
Certificate of Amendment to Certificate of Incorporation
filed on August 26, 2008 (incorporated by reference to Exhibit 3.4 to the
Companys Form 8-K as filed on August 27, 2008)
|
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)
|
4.2
|
|
Provisions Regarding Rights of Stockholders (Incorporated
by reference to Exhibit 4.3 to the Companys Form SB-2 registration
statement as filed on July 8, 2004)
|
4.3
|
|
Form of Warrant used in private placement of April 2008
(Incorporated by reference to Exhibit 10.3 to the Companys Form 8-K
current report as filed on May 2, 2008)
|
4.4
|
|
Form of Broker Warrant (Incorporated by reference as
exhibit 10.4 to the 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)
|
-115-
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)
|
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 tothe registrants Form 10-KSB annual report as
filed on June 29, 2006)
|
-116-
10.11
|
|
Employment Agreement dated September 29, 2011 with Daniel
J. Kunz (Incorporated by reference to exhibit 10.1 to the registrants
Form 8-K as filed on September 30, 2011)
|
10.12
|
|
Employment Agreement dated April 1, 2011 with Kerry D.
Hawkley (Incorporated by reference to exhibit 99.2 to the 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.)
|
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).
|
-117-
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)
|
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. datedMarch 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 August27, 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) *
|
-118-
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)
|
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, 2012.
|
21.1
|
|
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
|
-119-
*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.
-120-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
U.S. Geothermal Inc.
|
|
|
|
|
|
|
|
(Registrant)
|
|
|
|
|
|
|
|
|
March 25, 2014
|
|
|
|
|
|
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 25, 2014
|
Dennis J. Gilles
|
|
|
|
|
|
|
Chief Financial Officer (Principal Financial
and
|
|
/s/ Kerry Hawkley
|
Accounting Officer)
|
March 25, 2014
|
Kerry Hawkley
|
|
|
|
|
|
/s/
Douglas J. Glaspey
|
President, Chief Operating Officer and
Director
|
March 25, 2014
|
Douglas J. Glaspey
|
|
|
|
|
|
|
|
|
/s/ John H. Walker
|
Chairman and Director
|
March 25, 2014
|
John H. Walker
|
|
|
|
|
|
|
|
|
/s/ Paul A. Larkin
|
Director
|
March 25, 2014
|
Paul A. Larkin
|
|
|
|
|
|
|
|
|
/s/ Leland L. Mink
|
Director
|
March 25, 2014
|
Leland R. Mink
|
|
|
-121-
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