Information Regarding Forward Looking
Statements
This document contains forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. These
forward-looking statements involve a number of risks and uncertainties. We
caution readers that any forward-looking statement is not a guarantee of future
performance and that actual results could differ materially from those contained
in the forward-looking statement. These statements are based on current
expectations of future events. You can find many of these statements by looking
for words like believes, expects, anticipates, intend, estimates,
may, should, will, could, plan, predict, potential, or similar
expressions in this document or in documents incorporated by reference in this
document. These forward-looking statements are based on the current beliefs and
expectations of our management and are subject to significant risks and
uncertainties. If underlying assumptions prove inaccurate or unknown risks or
uncertainties materialize, actual results may differ materially from current
expectations and projections.
All subsequent written or oral forward-looking statements
attributable to us or any person acting on our behalf are expressly qualified in
their entirety by the cautionary statements contained or referred to in this
section. We do not undertake any obligation to release publicly any revisions to
these forward-looking statements to reflect events or circumstances after the
date of this document or to reflect the occurrence of unanticipated events,
except as may be required under applicable U.S. securities law. If we do update
one or more forward-looking statements, no inference should be drawn that we
will make additional updates with respect to those or other forward-looking
statements.
U.S. Geothermal Inc. (the Company, we or us or words of
similar import) is in the renewable green energy business. Through our
subsidiary, U.S. Geothermal Inc., an Idaho corporation (Geo-Idaho, although
our references to the Company include and refer to our operations through
Geo-Idaho), we are engaged in the acquisition, development and utilization of
geothermal resources in the Western United States and the Republic of Guatemala.
Geothermal energy is the natural heat energy stored within the 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.
-5-
Development of Business
U.S. Geothermal Inc. was originally incorporated on March 10,
2000 in the State of Delaware. The Company constructs, manages and operates
power plants that utilize geothermal resources to produce electricity. The
Companys operations have been, primarily, focused in the Western United States.
The Company currently owns and operates the following
geothermal power plant projects: Raft River, Idaho; San Emidio, Nevada; and Neal
Hot Springs, Oregon. The Company also has geothermal property interests in the
Republic of Guatemala; the Geysers in California; Vale, Oregon; Crescent Valley,
Nevada; Ruby Hot Springs, Nevada; Lee Hot Springs, Nevada; and Gerlach, Nevada,
some of which are under development or exploration.
History
Geo-Idaho was formed as an Idaho corporation in February 2002
to conduct geothermal resource development.
U.S. Cobalt Inc. entered into a merger agreement with Geo-Idaho
on February 28, 2002, which was amended and restated on November 30, 2003, and
closed on the reverse take-over on December 19, 2003. In accordance with the
merger agreement, the Company acquired Geo-Idaho through the merger of Geo-Idaho
with a subsidiary, EverGreen Power Inc., an Idaho corporation formed for that
purpose. Geo-Idaho was the surviving corporation and is the subsidiary through
which the Company conducts operations. As part of this acquisition, the Company
name was changed to U.S. Geothermal Inc.
Plan of Operations
Our business strategy is to identify, evaluate, acquire,
develop, and operate geothermal assets and resources economically, safely and
efficiently. Our management evaluates our operating projects based on revenues
and expenses, and our projects under development, based on costs attributable to
each project. We examine different factors when assessing projects at different
stages of development or potential acquisitions, such as the internal rate of
return of the investment, technical and geological matters and other relevant
business considerations.
We intend to execute this strategy in several steps outlined
below:
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Maximize Our Operations
Our operating
power plants and operations team provide revenue to the Company through
both power sales and Operations & Maintenance contracts. We strive to optimize plant operations through
high safety standards, quality preventative maintenance programs, operator
education, equipment selection and by exceeding our annual budgetary
goals.
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-6-
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Leverage Management Team Capabilities and Experience
Our strategy is focused on the identification and acquisition of
resources that can be developed in a cost-effective manner to produce
attractive returns. In particular, we seek to acquire projects that have
already undergone geothermal resource discovery. In addition, we intend to
operate and manage construction of the projects, while using internal
personnel and third-party contractors to efficiently and cost-effectively
develop those resources. We believe that we have the strategic personnel
in place to determine which resources provide the greatest opportunity for
efficient development and operation. We have developed relationships and
employed personnel that will allow us to develop and utilize geothermal
resources as efficiently as possible.
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Develop Our Pipeline of Quality Projects
Our
project pipeline currently consists of several projects that we believe
are aligned with our growth strategy. These projects typically have
consulting reports from various industry experts supporting our belief in
those projects potential. We are evaluating the potential of those
projects and expect to negotiate Power Purchase Agreements (PPAs) for
power deliveries with counterparties for some of these growth
opportunities. If realized, our identified project pipeline will greatly
expand our renewable power generation capacity as we move forward with the
development of those opportunities.
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Utilize Production Tax Credits, Investment Tax Credits
and Other Incentives
Although geothermal power production can be
cost competitive with fossil fuel power generating facilities on a life
cycle cost basis, government incentives such as production tax credits
(PTC) and Investment Tax Credits (ITC) available to geothermal power
producers help offset the high upfront project capital cost by enhancing
the project economics and attracting capital investment. For the Raft
River Unit I project, we partnered with Goldman Sachs as a tax equity
partner to fully utilize production tax credits available to the project.
Our strategy is to structure project ownership to optimize project
economics. Under current legislation, a company may elect to take 30% ITC
for certain qualified investments (or the PTC) provided construction of
the project was started prior to the end of 2017. We believe that the
second phase of our San Emidio project, our WGP Geysers project, and our
Crescent Valley project each qualify for this credit.
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Pursue Acquisition Strategy
The geothermal
market, particularly in the United States, is fragmented and characterized
by a few large players and a number of smaller ones. Geothermal
exploration and development is capital intensive, technically challenging
and requires long lead times before a project will produce revenue. We
believe that geothermal technical and managerial talent is limited in the
industry and that access to capital to develop projects will not be
equally available to all participants. As a result, we believe that there
will be opportunities in the future to pursue acquisitions of geothermal
projects and/or geothermal development companies with attractive project
pipelines.
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-7-
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Evaluate Other Potential Revenue Streams
from Geothermal Resources
In addition to electricity generation, we
may evaluate additional applications for our geothermal resources
including industrial, agriculture, and aquaculture purposes. These uses
generally constitute lower temperature applications where, after driving a
turbine generator, residual hot water can be cycled for secondary
processes before being returned to the geothermal reservoir by injection
wells, which can provide incremental revenue streams. We may evaluate the
optimal use for each geothermal resource and determine whether selling
heat for industrial purposes or generating and subsequently selling power
to a grid will generate the highest return on the asset.
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For the year ended December 31, 2017, the Company was focused
on:
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operating and optimizing the Neal Hot Springs, San Emidio
and Raft River power plants;
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continuing detailed engineering and pursuing PPA
opportunities for the WGP Geysers project;
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continuing permitting and engineering for the San Emidio
II project;
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continuing the advanced resource evaluation portion of
the $1.5 million SubTER grant from the Department of Energy at San Emidio
and Crescent Valley;
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continuing engineering for the Neal Hot Springs hybrid
cooling system and injection pump system; and
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evaluating potential new geothermal projects and
acquisition opportunities.
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The Board of Directors is focused on the strategic direction of
the Company, including review of the Companys overall development plan as well
as reviewing strategic alternatives. The Board has established committees to
assist the Board with this process. There can be no assurance that this ongoing
strategic review will result in any specific action or transaction or that any
action taken or transaction we may enter into will prove to be beneficial to
stockholders.
On January 24, 2018, U.S. Geothermal Inc. (the Company)
entered into an Agreement and Plan of Merger (the Merger Agreement) by and
among Ormat Nevada Inc., a Delaware corporation (Ormat), OGP Holding Corp., a
Delaware corporation and a wholly-owned subsidiary of Ormat (Merger Sub) and
the Company. Pursuant to the Merger Agreement, Merger Sub will be merged with
and into the Company (the Merger), the separate corporate existence of Merger
Sub will cease and the Company will continue its corporate existence under the
Delaware General Corporation Law as the surviving company in the Merger and a
subsidiary of Ormat.
Subject to the terms and conditions set forth in the Merger
Agreement, at the effective time of the Merger (the Effective Time), each
share of common stock, par value $0.001, of the Company (Company Shares)
issued and outstanding immediately prior to the Effective Time of the Merger
(other than Company Shares owned by Ormat, Merger Sub or the Company (as
treasury stock or otherwise), or any of their respective direct or indirect
wholly-owned subsidiaries, in each case, not Company Shares owned by
shareholders who have exercised their rights as dissenting owners under Delaware
law) will be automatically converted into the right to receive $5.45 per Company
Share in cash, without interest.
-8-
The Merger Agreement provides that, at the Effective Time, each
of the Companys then outstanding stock options will be treated as follows: (i)
the accelerated vesting and settlement of all then-outstanding Options
immediately prior to and contingent on the closing of the Merger, (ii) the
cash-out of such Options providing for payment of an amount equal to the excess,
if any,of the Merger Consideration per Company Share over the exercise price of
such Options and (iii) the cancellation, as of the Effective Time, of each
Option that is outstanding and unexercised as of immediately prior to the
Effective Time. Certain optionholders, such as directors and officers, will be
required to sign an Option Holder Acknowledgement Form, attached as an exhibit
to the Merger Agreement, in order to be automatically cashed-out as noted above
in subsection (ii).
The Merger Agreement contains customary representations and
warranties of the Company, Ormat and Merger Sub relating to their respective
businesses and organizations, in appropriate cases subject to materiality
qualifiers. Additionally, the Merger Agreement provides forcustomary pre-closing
covenants of the Company, including covenants relating to conducting its
business in the ordinary course consistent with past practice and refraining
from taking certain actions without Ormats consent, covenants not to solicit
proposals relating to alternative transactions or, subject to certain
exceptions, enter into discussions concerning or provide information in
connection with alternative transactions and covenants requiring the Companys
board of directors (the Board), subject to certain exceptions, to recommend
that the Company's shareholders approve the Merger Agreement. In the event that
the Board receives an alternative acquisition proposal that it determines is a
Superior Proposal (as defined in the Merger Agreement) in accordance with the
terms of the Merger Agreement, the Company may, subject to compliance with
requirements to provide notice to and a period for Ormat to match such proposal,
and subject to payment of the termination fee payable by the Company to Ormat
and other conditions and requirements set forth in the Merger Agreement,
terminate the Merger Agreement to accept the applicable Superior Proposal.
The Company, Ormat and Merger Sub have agreed to use their
respective commercially reasonable efforts, subject to certain exceptions, to,
among other things, consummate the transactions contemplated by the Merger
Agreement as promptly as reasonably practicable and make all required filings
and obtain all required consents, permits, regulatory approvals and expirations
or terminations of waiting periods. None of the Company, Ormat or Merger Sub is
required to divest any of its businesses, product lines or assets, or to take or
agree to take any other action or to agree to any limitation or restriction of
any kind on its business, operations, properties or assets.
Consummation of the Merger is subject to various conditions,
including, among others, customary conditions relating to the approval of the
Merger Agreement by the requisite vote of the Company's shareholders, expiration
or termination of the applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended, and any other applicable
antitrust laws, any required approvals from the Federal Energy Regulatory
Commission and any other applicable filings with or authorizations, consents or
waivers from third parties. The obligation of each party to consummate the
Merger is also conditioned on the other parties representations and warranties
being true and correct (subject to certain materiality exceptions) and the other
parties having performed in all material respects its obligations and complied
in all material respects with the agreements and covenants under the
Merger Agreement. The transaction is not conditioned on Ormats receipt of
financing.
-9-
The Merger Agreement contains termination rights for each of
the Company and Ormat, including, among others, if the Merger has not been
consummated by May 24, 2018. Either party may also terminate the Merger
Agreement if the Company's stockholder approval has not been obtained at a duly
convened meeting of the Company's stockholders or an order permanently
restraining, enjoining, or otherwise prohibiting consummation of the Merger
becomes final and non-appealable. Upon termination of the Merger Agreement under
specified circumstances, generally relating to alternative acquisition
proposals, an adverse change in the Boards recommendation in favor of the
Merger, a knowing and intentional breach of the Company representations or
warranties, or a failure by the Company to consummate the Merger when required
to do so pursuant to the terms of the Merger Agreement, the Company would be
required to pay Ormat a termination fee equal to 3% of the Merger Consideration
(approximately $3.2 million). Upon termination of the Merger Agreement under
specified circumstances, generally relating to a knowing and intentional breach
of Ormats representations or warranties, or a failure by Ormat to consummate
the Merger when required to do so pursuant to the terms of the Merger Agreement,
Ormat would be required to pay the Company a reverse termination fee equal to 3%
of the Merger Consideration (approximately $3.2 million).
The foregoing description of the Merger Agreement is qualified
in its entirety by the full text of the Merger Agreement, which is attached as
Exhibit 2.1 to the Companys Current Report on Form 8-K filed with the U.S.
Securities and Exchange Commission (SEC) on January 25, 2018, which is
incorporated by reference herein.
Project Overview
The following is a list of projects that are in operation,
under development or under exploration. Projects in operation currently have
producing geothermal power plants. Projects under development have a geothermal
resource discovery or may have wells in place, but require the drilling of new
or additional production and injection wells in order to supply enough
geothermal fluid sufficient to operate a commercial power plant. Projects under
exploration do not have a geothermal resource discovery occurrence yet, but have
significant thermal and other physical evidence that warrants the expenditure of
capital in search of the discovery of a geothermal resource. Due to inflation
and marketplace increases in the costs of labor and construction materials,
estimates provided for project development costs could understate actual
costs.
-10-
Projects in Operation
Although other factors may impact our operations and financial
condition, including many that we do not or cannot foresee, we believe that our
results of operations and financial condition for the foreseeable future will be
affected by the factors discussed below. A summary of the Companys operations
is as follows:
Projects in Operation
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Generation
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Ownership
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(Ave. Net
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PPA Limit
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Power
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Contract
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Project
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Location
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%
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MWs)
(3)
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(megawatts)
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Purchaser
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Expiration
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Neal Hot Springs
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Oregon
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60
(1)
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21.2
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25.0
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Idaho Power
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2036
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San Emidio (Unit I)
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Nevada
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100
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8.4
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9.9
(4)
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NV Energy
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2038
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Raft River (Unit I)
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Idaho
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95
(2)
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9.4
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13.0
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Idaho Power
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2032
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(1)
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Neal Hot Springs is a joint venture with a 40% interest
held by Enbridge.
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(2)
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Raft River is a joint venture with a subsidiary of
Goldman Sachs as the tax equity partner owning a 5% interest. On January
2, 2018, US Geothermal acquired the remaining 5% interest and now owns
100% of the project.
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(3)
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Average of 3 years generation.
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(4)
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Generation eligible for full PPA price. Generation from
9.9 MW up to 14.7 MW is eligible for excess energy payment of $50 per
megawatt-hour within the terms of the PPA.
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Facility Generation
Generation from all facilities totaled 323,832 megawatt hours
for 2017. For 2016, the total generation was 326,601 megawatt hours. For the
fourth quarter of 2017, generation from all facilities totaled 95,417 megawatt
hours compared to 97,879 megawatt hours during the same period in 2016.
Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of
Vale, the county seat of Malheur County, and achieved commercial operation on
November 16, 2012. The Neal Hot Springs facility is designed as a 22 megawatt
net annual average power plant, consisting of three separate 12.2 megawatt
(gross) modules, with each module having a design output of 7.33 megawatts (net)
annual average based on a specific flow and temperature of geothermal brine.
For the fourth quarter of 2017, generation was 56,100
megawatt-hours with an average of 25.6 net megawatts per hour of operation and
plant availability was 99.3% . For the same period in 2016, the plant generated
57,038 megawatt-hours with an average of 26.3 net megawatts per hour and plant
availability was 98.2% . Warmer winter temperatures reduced generation during
the fourth quarter of 2017.
The PPA for the project was signed on December 11, 2009 with
the Idaho Power Company. It has a 25-year term, and a variable percentage annual
price escalation. The PPA has a seasonal pricing structure that pays 120% of the
average price for four months (July, August, November, December), 100% of the
average price for five months (January, February, June, September, October) and
73.3% of the average price for three months (March, April, May). The annual
average price paid under the PPA for 2017 is $111.83 per megawatt-hour. For
2018, the average price will increase to $114.49 per megawatt-hour.
-11-
San Emidio Unit I, Nevada
The Unit I power plant at San Emidio is located approximately
100 miles north-east of Reno, Nevada near the town of Gerlach, and achieved
commercial operation on May 25, 2012. The San Emidio facility is a single 14.7
megawatt (gross) module with a design output of 9 megawatts (net) annual average
based on a specific flow and temperature of geothermal brine.
For the fourth quarter of 2017, generation was 18,097
megawatt-hours with an average of 8.2 net megawatts per hour of operation and
plant availability was 89.3% . For the same period in 2016, the plant generated
20,803 megawatt-hours with an average of 9.4 net megawatts per hour and plant
availability was 98.2% .
In mid-December 2017, the plant was shut down for 7 days to
repair leaks that were found in the vaporizer tubes. The damaged tubes were
plugged and will be replaced during the spring 2018 scheduled maintenance
outage. The pump in production well 75B-16 was shut down on December 29, 2017
after 7.8 years in service. The pump was replaced and returned to service.
Standby production well 75-16 was brought on line to supplement brine flow to
the plant while 75B-16 was off line.
On May 31, 2011, an amended and restated PPA was signed with
Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 10 megawatts
annual average. The PPA has a 25-year term with an annual escalation rate of 1
percent. The annual average price paid under the PPA for 2017 is $93.94 per
megawatt-hour. For 2018, the price will increase to $94.88 per megawatt-hour.
Raft River, Idaho
Raft River Energy I is located in Southern Idaho, near the town
of Malta, and achieved commercial operation on January 3, 2008. The Raft River
facility is a single, 18 megawatt (gross) module, with a design output of 13
megawatts (net) annual average based on a specific flow and temperature of
geothermal brine.
For the fourth quarter of 2017, generation was 21,220
megawatt-hours with an average of 10.8 net megawatts per hour of operation and
plant availability was 100%. For the same period in 2016, the plant generated
20,039 megawatt-hours with an average of 9.2 net megawatt hours and plant
availability was 100%.
Production pump RRG-7 was off line for 79 days to replace the
pump, build a new pump support structure and make a repair to the surface
casing. The well was shut down in late September 2017 when the pump failed after
8 years in service and was restarted in mid-December 2017.
Subsequent to the end of the year, the remaining 5% of the
project owned by GFSF Investments I Corp, a wholly owned subsidiary of Goldman
Sachs, was purchased on January 2, 2018. The purchase price was $350,000. U.S.
Geothermal Inc. now owns 100% of the project.
Well RRG-9, which was used as part of an $11.4 million thermal
stimulation grant funded primarily by the DOE, has increased injection capacity
to a current level of over 1,450 gpm. This injection capacity is sufficient to
provide all of the additional volume needed to accept the flow from well RRG-5
without requiring any new drilling.
-12-
The PPA for the project was signed on September 24, 2007 with
the Idaho Power Company and allows for the sale of up to 13 megawatts of
electricity on an annual average basis. The PPA has a 25 year term with a
starting average price for the year 2007 of $52.50 that escalates at 2.1% per
year through 2020 and then at 0.6% per year until the end of the contract in
2034. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the
average price for four months (July, August, November, December), 100% of the
average price for five months (January, February, June, September, October) and
73.5% of the average price for three months (March, April, May). The annual
average price paid under the PPA for 2017 is $64.63 per megawatt-hour. The
average price for 2018, including the projects share of the REC value, will be
$74.32 per megawatt-hour.
In addition to the price paid for energy by Idaho Power, Raft
River Unit I used to receive $4.75 per megawatt-hour under a separate contract
for the sale of RECs to Holy Cross Energy, a Colorado electric cooperative. As
of January 2018, a new, 10-year REC contract with the Public Utility District
No. 1 of Clallam County, Washington has replaced the Holy Cross Energy contract.
This REC contract only includes the sale of the RECs owned by the Raft River
project. Under the terms of our PPA, starting in 2018, 49% of the RECs produced
will be owned by the Raft River Project, and the Idaho Power Company will own
the remaining 51%.
Material Projects Under
Development/Exploration
In addition to our projects in operation, we have projects
under development and under exploration. Projects under development have at
least a geothermal resource discovery or may have wells in place, but require
the drilling of new or additional production and injection wells in order to
supply enough geothermal fluid sufficient to operate a commercial power plant.
Projects under exploration do not have a geothermal resource discovery
occurrence yet, but have significant thermal and other physical evidence that
warrants the expenditure of capital in search of the discovery of a geothermal
resource. Due to inflation and marketplace increases in the costs of labor and
construction materials, estimates of property development costs may be low.
A summary of projects under development and under exploration
is as follows:
Development Projects
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Target
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Projected
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Estimated
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Development
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Commercial
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Capital Required
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Power
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Project
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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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Purchaser
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Neal Hot Springs - upgrade
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60%
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1-2
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4
th
Quarter 2018
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1.6
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Idaho Power
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San Emidio I - upgrade
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100%
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1-2
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3
rd
Quarter 2018
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4
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NV Energy
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Raft River upgrade
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100%
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0.5
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3
rd
Quarter 2018
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1
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Idaho Power
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WGP Geysers
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100%
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30
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4
th
Quarter 2022
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148
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TBD
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San Emidio Phase II
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100%
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25-35
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4
th
Quarter 2020
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126-168
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TBD
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El Ceibillo Phase I
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100%
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25
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TBD
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140
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TBD
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Crescent Valley Phase I
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100%
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25
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TBD
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130
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TBD
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*
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- Commercial operation dates are projections only. The
actual commercial operation date can only be provided after a PPA has been
obtained for the project.
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-13-
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Exploration Properties
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Target Development
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Project
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Location
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Ownership
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*(Megawatts)
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Gerlach
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Nevada
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67.4%
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10
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Vale
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Oregon
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100%
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15
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El Ceibillo Phase II
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Guatemala
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100%
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25
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Neal Hot Springs II
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Oregon
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100%
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10
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Raft River Phase II
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Idaho
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100%
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13
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Crescent Valley Phase II
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Nevada
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100%
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25
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Crescent Valley Phase III
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Nevada
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100%
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25
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Lee Hot Springs
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Nevada
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100%
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20
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*
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- Target development sizes are predevelopment estimates
of resource potential of unproven resources. The estimates are based on
our evaluation of available information regarding temperature, and where
available, flow.
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Property Details
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Property Size
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(square
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Property
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miles)
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Temperature (
º
F)
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Depth (Ft)
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Technology
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Neal Hot Springs
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9.6
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286-311
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2,500-3,000
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Binary
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San Emidio
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27.9
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289-316
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1,500-3,000
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Binary
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Raft River
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10.8
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275-302
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4,500-6,000
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Binary
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Gerlach
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4.7
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338-352
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2,000-3,000
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Binary
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El Ceibillo
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38.6
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410-526
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1,800-TBD
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Steam/Flash
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WGP Geysers
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6.0
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380-598
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6,000-10,000
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Steam
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Crescent Valley
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33.3
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326-351
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2,000-3,000
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Binary
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Lee Hot Springs
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4.0
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280-320
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1,250-5,000
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Binary
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Vale
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0.6
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290-300
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2,450-5,000
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Binary
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Binary Cycle Geothermal Power Plants
In a binary cycle geothermal power plant hot water is produced
to a piping and gathering system from wells drilled into the geothermal
reservoir. The hot water flows, with to a heat exchanger called a vaporizer
where it vaporizes a secondary working fluid, with its heat extracted, causing
the original hot water to become cool. All of the cooled water is then pumped to
injection wells where it is injected back into the reservoir to help recharge
the geothermal reservoir. The vaporized working fluid passes through a turbine
which drives an electrical generator that is tied into the electrical
transmission grid. Upon discharging the turbine the secondary working fluid is
condensed before piping it back to the vaporizer where the process is repeated.
-14-
Dry Steam Geothermal Power Plants
An example of a vapor dominated geothermal system is at The
Geysers in central California. Dry super-heated steam is produced from wells
through a piping system and run directly through a turbine. The turbine drives
an electrical generator that delivers power to the electrical transmission grid.
Steam discharges from the turbine into a condenser where it is condensed forming
water. The water is pumped to a cooling tower where it can be used as water for
the cooling process. The cooled water from the cooling tower is recycled back to
the condenser to repeat the process. Any excess water from the cooling tower is
pumped through a piping system to injection wells where it is injected back into
the reservoir which helps to recharge the geothermal reservoir.
-15-
Flash Geothermal Power Plants
In hot water geothermal systems (temperatures greater than
approximately 400 degrees Fahrenheit), flash production systems are often used.
The hot water is produced from wells drilled into the geothermal reservoir. The hot water from the
various production wells is piped to a flash tank where the pressure is reduced.
The reduction in pressure in the flash tank causes part of the hot water to
flash to form steam and part to remain as water. The flash tank also acts a
separator, separating the steam from the water. The hot water separated from the
steam is pumped through a pipeline system to injection wells and injected into
the reservoir for reservoir recharge. The steam coming off the flash
tank/separator is piped directly to a turbine where the process is identical to
that used for dry steam geothermal power plants.
Neal Hot Springs Upgrade Projects
At our operating Neal Hot Springs project, there are
approximately 3.9 megawatts of annual average generation that are available
under the terms of the PPA. Each megawatt of increased generation is worth
approximately $990,000 per year at the 2019 contract price of $116.45.
The decision was made to delay the hybrid cooling system until
2019 to allow additional time to firm up the water supply and complete the final
design of the cooling system. The updated design for the hybrid system would
have a single cooling tower with heat exchangers located at all three units.
Cooling water would come from both fresh groundwater wells and treated
geothermal water. The engineering for the hybrid system is completed to the bid
level and will be further refined during the year. Water cooling will increase
the efficiency of the plant during the summer period when generation is
suppressed by high ambient temperatures.
A second upgrade project under evaluation and engineering is the
addition of two injection pumps that would both reduce the parasitic load in the
plant, and allow an increase in the pumping capacity of the production pumps
that feed hot fluid to the plant. The estimated capital costs is $1.6 million and the system could be on-line by the 4
th
quarter 2018.
San Emidio I, Nevada Upgrade Project
At our operating San Emidio I project, we will move forward
with an enhancement program to increase generation from the power plant by
drilling a new production well in the Southwest Zone and delivering that fluid to the San Emidio I plant. There
are approximately 1.5 megawatts annual average that remains available under the
terms of the PPA at full price, and several more megawatts that could be sold at
the excess energy price. One megawatt at full contract price is worth
approximately $800,000 in additional annual revenue and each megawatt of excess
energy generated above 10 megawatts, but below 14.7 megawatts is worth
approximately $425,000.
-16-
The drilling permit was received from the Bureau of Land
Management (BLM) in January 2018 to drill production well 25A-21. A permit
from the State of Nevada is pending. The new production well will twin
observation well 25-21, which intersected a high temperature, high permeability
structure in the Southwest Zone. The well will be connected to the Phase I plant
with a new pipeline, and is now planned to provide up to 2,000 gallons per
minute of 320°F fluid. Starting production from the Southwest Zone in 2018 will
provide a long-term flow test of the Southwest Zone that will be critical to
understand its full development potential.
Raft River, Idaho Upgrade Project
The addition of production well RRG-5 increased the average
generation from the Raft River plant by 1.6 net megawatts in 2017. Due to the
positive response from the wellfield, which showed a minimal decrease in fluid
levels, a study to increase the capacity of production pump RRG-4 in 2018 was
completed. The upgrade project would consist of adding additional bowls to the
pump and setting the pump deeper in the well to produce approximately 400-500
gpm more fluid to the plant. The pump in RRG-4 has been in service for 10 years
and was already scheduled for replacement in 2018.
This upgrade would result in an estimated generation increase
of approximately 0.5 net megawatts annual average. In 2019, the first full year
of production, the energy plus renewable energy credit value will be $75.71 per
megawatt hour. If the full amount of new generation is realized, it would result
in approximately $600,000 of additional annual revenue. Approximately half of
this revenue is expected to be realized in 2018.
WGP Geysers, California Development Project
The WGP Geysers project is located in the broader Geysers
geothermal field located approximately 75 miles north of San Francisco,
California. The broader Geysers geothermal field is the largest producing
geothermal field in the world generating more than 850 megawatts of power for
more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was
completed on April 22, 2014 for $6.4 million. We expect that approximately 75%
of the development may be funded by non-recourse project debt, with the
remainder funded through equity financing. Due to the lapse in the Federal
Investment Tax Credit program for geothermal power generation and the delay for
start of construction, we do not believe that the project currently qualifies
for the 30% ITC or PTC. Several bills have been introduced in Congress that
could reauthorize the ITC/PTC for geothermal power generation, but it is unknown
when that action might take place.
Detailed engineering of the 28.8 net megawatt power plant is
nearly complete. Our engineers and consultants are working in concert with our
EPC contractors to examine all aspects of the construction cycle with a focus on
reducing construction costs. The hybrid cooling design will dramatically
increase the volume of water available for injection back into the reservoir,
which will result in increased power generation over the life of the project.
Traditional water cooled geothermal steam plants re-inject approximately 20 to 25% of
the water that is extracted from the steam, while our current hybrid design may
re-inject approximately 80% more of the water. This higher injection rate will
provide long term, stable steam production, and will result in increased power
generation over the life of the project.
-17-
The Conditional Use Permit from Sonoma County, which approves
the construction plan for the WGP Geysers power plant, was received on December
16, 2016 and is active for 10 years. Combined with the Large Generator
Interconnection Agreement (LGIA) that was received from the California
Independent System Operator and Pacific Gas & Electric, this completes the
long lead permits and agreements that are needed for the project. Once final
engineering design is finished, and a PPA is executed, an air quality permit and
building permit will be needed before on site construction will begin.
We terminated the LGIA the project had with the California
Independent System Operator and Pacific Gas & Electric (PG&E). The
termination was driven by various milestone dates that were not achievable
because of the lack of a PPA and the lack of an easement for the 1.7 mile long
transmission line from the plant to the substation. This LGIA allowed the
project to connect to the transmission grid and deliver up to 35 megawatts of
energy. The Company paid the total interconnection cost of $1.9 million to the
grid operator for their substation work. After termination, the remaining
balance of the interconnection cost is expected to be reimbursed to the Company
during the first quarter of 2018.
We are now considering an alternative interconnection method
which will trigger additional interconnection studies and extend the time
required for interconnection into the transmission grid. A ring bus type
substation located on the plant site will be required if the easement cannot be
acquired. The additional cost associated with the ring bus type substation is
currently included in the estimated capital cost for the project.
Based on flow test data generated from well flow testing
performed in mid-2015, a third party expert reported in September 2015, that the
four production wells already drilled are capable of delivering an initial
capacity of 28.1 MW (gross) or 25.4 MW (net) based on current power plant steam
conversion rates from a detailed design for a 28.8 MW (net) power plant. These
tests show the wells would initially produce a combined total of 458,000 pounds
per hour. Using the average steam production rate from these wells and an
assumed interference factor of 30%, the third party expert estimates that an
additional two to three production wells would be needed to support the
long-term operation of a 28.8 MW (net) plant. Using the large data base from the
surrounding Geysers geothermal field, the historic WGP well production data, and
the 2015 flow test information, a numerical reservoir model has been developed
to provide the final well requirements and targeting for injection sites.
We continue to submit proposals when Request for Offers are released by organizations seeking renewable energy and have continued bilateral discussions with several potential purchasers. In Fall 2017, we adopted a revised, more aggressive pricing structure when submitting bids. Despite the new pricing structure, to date, the WGP Geysers project has not been selected to negotiate a PPA. Purchasers have expressed interest in renewable, base load power to replace fossil fuel based power generation that is being phased out of some of their portfolios and to stabilize and balance intermittent resources already in their portfolios.
-18-
San Emidio Phase II, Nevada Development Project
The Phase II expansion is dependent on successful development
of additional production and injection well capacity. We expect that
approximately 75% of the Phase II development may be funded by non-recourse
project debt, with the remainder funded through equity financing. We believe the
project qualifies for the 30% Federal Investment Tax Credit (or Production Tax
Credit) which, when monetized, can meet most of the equity financing
requirements.
A power plant development permit application for the San Emidio
Phase II project was submitted to the BLM on March 29, 2017. The application
provides for the installation of three power plant units and up to 20 wells and
related infrastructure needed to develop the project. It is expected that the
evaluation by the BLM will take 12 months or longer to complete. All of the
required cultural and biological surveys were completed for the plant and
wellfield area during the second quarter, with no unique or notable sites or
species identified. Archeological surveys of the power line that will
interconnect the plant to the NV Energy substation were conducted during the
4
th
quarter 2017.
During September 2017, a 59-hour, multi-well flow test was
conducted using three of the recently drilled Southwest Zone wells. Total flow
from the wells was approximately 1,590 gpm. Testing included a step rate program
with four-hour increments, whereby one well, then two wells, and finally all
three wells were flowed for the 51-hour duration of the test. Flowing
temperature from the three wells ranged from 319°F to 325°F. Pressure was also
monitored on the flowing wells, which experienced pressure drawdown from 7.7 psi
to 43.0 psi. A monitoring well in the Southwest Zone, located 1,700 feet from
the nearest flowing well, had a pressure drawdown of 4.3 psi. Five additional
monitoring wells located in the Phase I reservoir area recorded pressure changes
of 0.9 psi to 3.2 psi.
These results continue to support the previously announced
Probability Power Density model resource estimate of 25.9 megawatts at a 90%
probability. The 50% probability level estimate of 47 megawatts remains
unchanged because all of these wells are inside the originally defined Southwest
Zone resource area. Future drilling to expand the resource beyond the currently
defined area is planned but cannot be implemented until the Environmental
Assessment for the Phase II power plant development is approved by the BLM.
An application for a LGIA was filed with NV Energy on June 26, 2017. The LGIA would provide for the interconnection of 45 megawatts of generation capacity. Permitting for the transmission line, which is approximately 57 miles long, may extend the time required to interconnect the project and could impact the currently projected commercial operation date. The LGIA was accepted as complete by NV Energy and entered the first step in the FERC mandated evaluation process on October 1, 2017. The first phase study, a System Impact Study (“SIS”), was received on January 29, 2018. The SIS that was presented indicated potentially higher transmission costs, but did not study the correct interconnection parameters and is currently undergoing a re-study by NV Energy. A second phase study, the Facilities Study, will be required to be completed before an interconnection agreement can be reached.
The three power plant equipment packages that were purchased in
2016 are available to provide this project with the major, long lead equipment
requirements for 25-35 net megawatts annual average (depending upon cooling
system used). The increased San Emidio II reservoir capacity with a 320°F+
temperature fits the design range of the equipment. These new, unused components represent approximately 70% of the equipment needed
for a complete facility similar to the Companys Neal Hot Springs operation.
-19-
In July 2016, the Company was awarded a $1.5 million DOE cost
share grant under the Development of Technologies for Sensing, Analyzing, and
Utilizing Novel Subsurface Signals in Support of the Subsurface Technology and
Engineering (SubTER) Crosscut Initiative. The program approved under the
grant includes using new subsurface imaging technologies at both San Emidio and
Crescent Valley to identify fluid flow paths in the geothermal resource. The
primary data collection phase of the program, which included passive seismic and
magnetotelluric (MT) stations, was completed at San Emidio in December 2016. A
second phase of data collection was required to fill in and replace a limited
number of MT stations at San Emidio, and was completed in the third quarter.
Final interpretation of the geophysical data is currently underway.
After all data is compiled and interpreted, if viable drilling
targets have been identified, DOE may approve a second phase of the grant
program to confirm the findings by drilling. There is no assurance the DOE will
approve the drilling phase of the grant, even if viable targets are identified.
The total program cost is estimated to be $1.9 million and we anticipate the
Company cost share would be $400,000.
El Ceibillo, Republic of Guatemala Development Project
A geothermal energy rights concession, located 14 kilometers
southwest of Guatemala City, was awarded to U.S. Geothermal Guatemala S.A., a
wholly owned subsidiary of the Company, in April 2010. The concession agreement
contains a schedule that requires the development and construction of a power
plant. In July 2015, the Guatemalan Ministry of Energy and Mines approved a
modified construction schedule that extended the development and construction
period to June 1, 2018. There are 24,710 acres (100 square kilometers) in the
concession, which is at the center of the Aqua and Pacaya twin volcano complex.
On September 28, 2017, U.S. Geothermal Guatemala S.A. was
notified that it has been awarded a $3.42 (€2.91) million grant from the German
Development Facility for Latin America for further development drilling at the
El Ceibillo project. The grant represents an approximate 40% cost share for
drilling up to three production wells, with a total estimated program cost of
$8.81 (€7.486) million. If the GDF funding is used on the project and the power
plant is constructed, the grant would be converted into a loan. The German
Development Bank may consider financing the entire project if it moves to
production. The next phase of work for the project is being considered by the
management team as 2018 budgets are being developed.
On December 29, 2017 we were notified that the US Trade
Development Agency had approved the grant for a feasibility study at El Ceibillo
valued at $825,319. The study is being led by Power Engineers of Hailey, Idaho
and a consortium of professional geothermal contractors. It is scheduled to be
completed by the end of 2018. All of the proceeds from the grant are paid to the
contractors at defined milestones.
A production well, EC-5, was drilled in August 2016 to a depth
of 1,450 feet (442 meter and intersected a high permeability zone at 1,299 feet
(396 meters). EC-5 underwent a series of flow tests, with field wide monitoring,
beginning on September 5, 2016 and ran until September 13, 2016. Data was collected from three monitoring wells during the
test (EC-2A, EC-3, and EC-4) to provide pressure data for the reservoir model.
Fluid samples taken at the end of the flow test indicate a potential reservoir
temperature of 450 to 523°F (232 to 273°C).
-20-
With the shallow, commercial resource now outlined, a deeper
well has been sited to test the producing structure down dip from well EC-5 to a
projected depth of 1,970 to 2,300 feet (600-800 meters). A deeper intersection
in the reservoir could increase the reservoir capacity and production
temperature and change the design of the power plant. Well EC-1, which was
drilled in 2013 to a depth of 5,650 feet (1,722 meters) found a measured
bottom-hole temperature of 526°F (274°C), but did not intersect a commercial
zone of permeability. The comparative geology between EC-5 and EC-1 suggests a
fault or other structure feeding the reservoir may be located in the area
between the two wells.
Expenditures at El Ceibillo are being carefully controlled
until we see evidence that the energy market is advancing in Guatemala. On
January 10, 2017, the Guatemalan government, through the National Electrical
Energy Commission (COMISIÓN NACIONAL DE ENERG¥A ELÉCTRICACNEE),
announced that it is preparing to issue a Request For Proposal (RFP) for
420 megawatts of power, of which 40 megawatts is to be reserved specifically for
geothermal energy. The RFP was not issued in 2017 and there is still no
indication of when that RFP may be issued. When the RFP is issued, we expect to
bid the El Ceibillo project into the process.
Raft River Phase II, Idaho
In 2011, the Raft River Phase II project was awarded an $11.4
million cost-shared, thermal stimulation program grant from the DOE with the
University of Utah Energy and Geoscience Institute as the project lead. The goal
of the project is to create an Enhanced Geothermal System (EGS) by creating
thermal fractures and developing a corresponding increase in permeability in the
low permeability rock. Well RRG-9 was made available for the program and the
first stage of injection into the well began in June 2013.
Initially the well was only capable of receiving 20 gpm of
water due to the low permeability of the rock. After several moderate pressure
stimulations, the injection of cold power plant discharge fluid first began in
June 2015 and has continued to date. The lower temperature fluid causes thermal
fracturing within the higher temperature host rock of the reservoir. At the
current plant generation level, the flow into the well has continued to increase
and is now approximately 1,572 gallons per minute.
Well RRG-9 continues to be used temporarily for injection from
the Raft River Energy I power plant as an extension of the DOE EGS program. The
Companys contributions for the thermal stimulation program are made in-kind by
the use of the RRG-9 well, well field data provided by the Company, and through
ongoing labor for monitoring support.
The development and construction of a Phase II project at Raft
River is dependent upon additional drilling and the availability of a PPA.
-21-
Crescent Valley, Nevada
The Crescent Valley prospect consists of approximately 21,300
acres (33.3 square miles) of private and Federal geothermal leases. It is
located in Eureka County, Nevada, approximately 15 miles south of the Beowawe
geothermal power plant and about 33 miles southeast of Battle Mountain. The
project was acquired as part of the Earth Power Resources merger which was
completed in December 2014.
In light of federal legislation that extended the qualification
for the 30% Federal Investment Tax Credit to projects that began construction
prior to December 31, 2014, drilling of the first production/injection well
CVP-001 (67-3) was initiated in December of 2014, following completion of
gravity surveys, and analysis of prior temperature gradient drilling data. Well
CVP-001 was completed on March 27, 2015 to a depth of 2,746 feet. The well
exhibited modest permeability with a flowing temperature of 213°F, which makes
the well suited for duty as an injection well.
The SubTER program, approved under the DOE grant awarded in
July 2016, includes using new subsurface technologies at both San Emidio and
Crescent Valley to identify fluid flow paths in the geothermal resource. The
passive seismic data collection phase of the program was completed at Crescent
Valley in December of 2016. A magnetotelluric (MT) survey was completed during
the third quarter 2017. The data is being interpreted to develop a 3D map to
help identify future drilling targets. The details of this award are discussed
in the San Emidio Phase II project discussion above.
Employees
At December 31, 2017, the Company had 48 full-time and one part
time employees (14 administrative and project development, and 34 field and
plant operations) in the United States, with another 9 employees in Guatemala.
The Company continuously considers acquisition opportunities, and if the Company
is successful in making acquisitions, additional management and administrative
staff may be added.
The Company did not experience any labor disputes or labor
stoppages during the current fiscal year.
Principal Products
The principal product is based upon activities related to the
production of electrical power from the utilization of the Companys geothermal
resources. The primary product will be the direct sale of power generated by our
interests in our geothermal power plants. Currently, our principal revenues
consist of energy sales and energy credit sales. All power plants currently in
operation, as well as all sites under exploration or development, are sites
located in the Western United States or in the Republic of Guatemala in Central
America.
-22-
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.
Unless major geological changes occur that impact the
geothermal reservoirs, the condition of the existing resources is expected to
remain relatively consistent over time.
Significant Government Permits
The Company maintains all permits necessary for operating its
three plants located in Idaho, Nevada and Oregon. In addition, in December 2016
the Company received the Sonoma County Conditional Use Permit required for
construction and operations of the WGP Geysers project.
Neal Hot Springs, Oregon.
The Neal Hot Springs project
has four primary permits governing power plant operations. The permits include:
|
1.
|
Geothermal Well Permits issued by the Department of
Geology.
|
|
|
|
|
2.
|
A Right-of-Way issued by the Bureau of Land
Management.
|
|
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|
3.
|
A Conditional Use Permit issued by the Malheur County
Commission.
|
|
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4.
|
Underground Injection Control Permit issued by the Oregon
Department of Environmental Quality.
|
-23-
San Emidio, Nevada.
The San Emidio project has five
primary permits governing power plant operations. The permits include:
|
1.
|
Geothermal well permits issued by the Nevada Division of
Minerals.
|
|
|
|
|
2.
|
A Special Use Permit issued by the Washoe County Board of
Commissioners.
|
|
|
|
|
3.
|
An Air Quality Permit to Operate from Washoe
County.
|
|
|
|
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4.
|
A Surface Discharge Permit from Nevada Division of
Environmental Protection.
|
|
|
|
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5.
|
An Underground Injection Permit from Nevada Division of
Environmental Protection.
|
Raft River, Idaho.
The Raft River project has three
primary permits governing power plant operations. The permits include:
|
1.
|
Geothermal well permits issued by the Idaho Department of
Water Resources.
|
|
|
|
|
2.
|
A Conditional Use Permit issued by the Cassia County
Planning and Zoning Commission.
|
|
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|
|
3.
|
A Wastewater Reuse Permit issued by the Idaho Department
of Environmental Quality.
|
WGP Geysers, California
. Western GeoPower had previously
been issued all necessary permits for construction and operation of up to a 38.5
megawatt geothermal power plant. The Sonoma County Conditional Use Permit
administratively expired in 2015. A new Conditional Use was issued in December
2016 for an initial term of 10 years including administrative extensions of 5
years. The primary permits include:
|
1.
|
Geothermal well permits for production and injection
wells issued by the California Department of Oil, Gas, and Geothermal
Resources.
|
|
|
|
|
2.
|
A Conditional Use Permit that has been issued by the
Sonoma County.
|
|
|
|
|
3.
|
Air Quality Permit to Construct issued by the Northern
Sonoma Air Quality Board.
|
Seasonality of Business
The Company has been producing energy revenues under the terms
of three PPAs. Two of these contracts specify favorable rate periods and all
three plants experience changes in levels of production through the year. The
Raft River Energy I LLC (Raft River, Idaho) and USG Oregon LLC (Neal Hot
Springs, Oregon) contracts pay higher rates in the months of July/August and
November/December. Energy production can be influenced by the seasonal
temperatures. The Companys binary geothermal plants can operate more
efficiently in cooler temperatures. Cooler temperatures facilitate the cooling
process of the secondary fluid that is used to power the turbines. The Neal Hot
Springs plant, since it utilizes air cooling rather than water cooling, is
impacted more in the summer (lower generation) than the Raft River or San Emidio
plants. Neal Hot Springs produces higher generation in the winter. Drilling and
other construction activities can be negatively impacted by inclement weather
that can occur, primarily, during the winter months.
-24-
Industry Practices/Needs for Working Capital
The Company is heavily involved in exploration and development
operations. Once the decision is made to construct a project, high levels of
working capital are committed, either directly or indirectly to the construction
efforts. After a plant becomes commercially operational and the necessary
operating reserves have been funded, the needs for working capital are typically
low. The Company is expecting to be significantly involved in exploration and
development activities for the next 5 to 10 years.
Dependence on a Few Customers
Ultimately, the market for electrical power is vast; however,
the numbers of entities that can physically, logistically and economically
purchase the commodity in large quantities are limited. The 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. As of
January 2018, energy credits earned by Raft River plant are sold to the Public
Utility District No. 1 of Clallam County, Washington. Under the current PPAs,
energy credits that are earned by USG Oregon LLC and USG Nevada LLC plants are
bundled with energy sales. Based upon current operations and expected project
completions, it is expected that the Company will have a small number of direct
customers that may amount to less than 10 over the next 5 to 10 years.
Competitive Conditions
Although the market for different forms of energy is large and
dominated by very powerful players, we perceive our industrial competition to be
independent power producers and in particular those producers who provide
green renewable power. Our definition of green power is electricity derived
from a source that does not pollute the air, water or earth. Sources of green
power, in addition to geothermal, include wind, solar, biomass and run-of-the
river hydroelectric. A number of states have instituted renewable portfolio
standards (RPS) that require utilities and retail sellers of electricity to
purchase a minimum percentage of their power from renewable sources. For
example, RPS statutes in California require 50% by 2030, Oregon requires 50% by
2040 and Nevada requires 25% by 2015. According to the Department of Energys
Energy Efficiency and Renewable Energy department, approximately 38 states
nationwide have established renewable portfolio standards or goals encouraging
the procurement of green, renewable power. As a result, we believe green power
is an important sub-market in the broader electric market, in which many power
purchasers are increasing or committing to increase their investments.
Accordingly, the conventional energy producers do not provide direct
competition.
In the Pacific Northwest there are currently only two
commercial geothermal facilities, both operated by the Company. There are a
number of wind farms, as well as biomass and run-of-the river hydroelectric
facilities. However, the Company believes that the combination of greater
reliability and the baseload generation profile provided by geothermal power,
with access to infrastructure for deliverability, and a low "full life" cost
of power will allow geothermal to successfully compete for long term PPAs.
-25-
Factors that can influence the overall market for our product
include some of the following:
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number of market participants buying and
selling electricity;
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availability and cost of transmission;
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availability of low cost natural gas as an
alternate fuel source
|
|
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amount of electricity normally available in the
market;
|
|
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fluctuations in electricity supply due to
planned and unplanned outages of competitors generators;
|
|
|
fluctuations in electricity demand due to
weather and other factors;
|
|
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cost of fuel used by generators, which could be
impacted by efficiency of generation technology and fluctuations in fuel
supply;
|
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|
environmental regulations that impact us and
our competitors;
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|
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availability of production tax credits and
other benefits allowed by tax law;
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relative ease or difficulty of developing and
constructing new facilities; and
|
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credit worthiness and risk associated with
buyers.
|
Environmental Compliance
Geothermal drilling, construction and power plant operations
are subject to federal, state and local environmental requirements and
construction oversight. Applicable laws may include but are not limited to the
Clean Air Act, the Clean Water Act, the Emergency Planning and Community
Right-to-Know Act, the Endangered Species Act, the National Environmental Policy
Act, state specific geothermal drilling rules, state and federal injection well
requirements and standards and local building codes.
Prior to acquiring an existing geothermal development, USG
retains an independent, licensed engineer or geologist to conduct an
Environmental Site Assessment and evaluate the property for recognized
environmental conditions that could result in regulatory and financial
liabilities being passed to U.S. Geothermal Inc. or our subsidiaries.
Our geothermal operations involve significant quantities of
geothermal brine that is returned to the local subsurface, geologic formation.
We also use isopentane and R-134A refrigerant working fluids, and numerous
industrial lubricants that are defined by state regulatory agencies as
contaminants if released or spilled. We are not aware of any mismanagement of
these materials and we are required to promptly report any release of specified
volumes of oil, lubricants, and chemicals used in our operations.
The requisite approvals and permits for our operations have
been independently reviewed and verified prior to obtaining project financing.
Independent legal reviews have verified that USG and our subsidiary companies
are operated in accordance with applicable laws. Existing laws and regulations
may be revised or reinterpreted, or new laws and regulations may become
applicable to us. Under those circumstances we work with the appropriate agency
or entity to ensure that our operations remain in compliance with the applicable
rules. As of the date of this memorandum, all of the permits and approvals required to
operate our plants have been obtained and are valid.
-26-
Neal Hot Springs, Oregon
The Neal Hot Springs project is situated approximately 12 miles
west of Vale, Oregon. There are two nearby residents; both are family of JR Land
& Livestock, our primary lessor. There are no unique plant or animal
communities in the area and no unique cultural or environmental constraints.
Because the power plant is air-cooled the only environmental
reporting required is a monthly production and injection report and an annual
water quality summary. The reports are filed with the Oregon Department of
Environmental Quality and Oregon Department of Geology and Mineral Industries.
Bi-annual water monitoring has been conducted since 2008 and will continue
throughout the life of the project. Energy generation reports are filed with the
Federal Energy Regulatory Commission on a quarterly basis. An independent legal
team has reviewed all regulatory requirements, permits and approvals for the
project.
Adjoining rangelands are privately and federally managed and
there are no rangeland or cropland management obligations.
The Neal project is in compliance with all environmental
permitting, monitoring and reporting requirements and has received no formal or
informal notices from any local, state, or federal agency.
San Emidio, Nevada
The San Emidio project is located approximately 14 miles south
of Gerlach Nevada. The nearest residence is over four miles from the plant site.
The San Emidio staff files monthly, quarterly and annual water
reports with the Nevada Department of Environmental Protection and Nevada
Department of Water Resources. Similar to other projects San Emidios monthly
geothermal production and injection volumes are submitted the Nevada Division of
Minerals and Nevada Division of Environmental Protection. Water quality
reporting is also submitted regularly to the Nevada Division of Environmental
Protection.
San Emidio is in compliance with all environmental permitting,
monitoring and reporting requirements and has received no formal or informal
notices from any local, state, or federal agency.
Raft River, Idaho
The Raft River project is located approximately 12 miles south
of Malta, Idaho in a rural agricultural area with the nearest residence
approximately two miles from the plant site. There are no unique plants or
animal communities in the area and no unique cultural or environmental
constraints.
Wastewater reuse requires bi-annual ground water monitoring at
six locations, monthly monitoring of the cooling water and annual reporting.
Water quality data is collected a minimum of twice annually. Monthly production and injection reports are
filed with the Idaho Department of Water Resources, and land application and
cooling water quality reports are filed with the Idaho Department of
Environmental Quality and Idaho Department of Water Resources annually. The
Projects private lands are managed on an ongoing basis for weed control, water
management, irrigation, and fencing infrastructure.
-27-
The Raft River project is in compliance with all environmental
permitting, monitoring and reporting requirements and has received no formal or
informal notices from any local, state, or federal agency.
WGP Geysers, California
The Geysers project is located approximately 30 minutes
north-east of the city of Healdsburg, California. The property encompasses a
ridgetop and a north facing hillside that has been developed and used for
geothermal operations from l979 to l989. There are no unique plant or animal
communities on the project site and no unique cultural or environmental
constraints. The North Coast Regional Water Quality Board (NCRWQB) has required,
prior to new construction, that WGP submit a plan to remove or reuse existing
steam pipelines. The pipelines may contain mineral scale that has arsenic levels
that exceed 150 parts per million.
WGPs ongoing environmental reports include a monthly well
report that is filed with the California Department of Oil, Gas and Geothermal
Resources and an annual water quality report that is filed with the California
Regional Water Board.
The Geysers project is in compliance with all environmental
permitting, monitoring and reporting requirements and has received no formal or
informal notices from any local, state, or federal agency.
Gerlach, El Ceibillo, Crescent Valley, Lee Hot Springs, Ruby
Hot Springs, and Vale
No power plant operations are being conducted on these
properties at this time. The Company is in compliance with all environmental and
regulatory requirements and has received no formal or informal notices from any
local, state, or federal agency. There are no monthly, quarterly, or annual
reporting requirements associated with these projects.
-28-
Financial Information about Geographic Areas
The Company has interests in operational power plants in three
locations in the Western United States. The Raft River Energy I LLC power plant
is located in the southeastern part of the State of Idaho. Raft River Unit I
became operational on January 3, 2008. USG Nevada LLC constructed a new power
plant located in the northwestern part of the State of Nevada in the San Emidio
Desert. This power plant owned by USG Nevada LLC became commercially operational
May 25, 2012. The three units owned by USG Oregon LLC became commercially
operational November 16, 2012. These units are located in the Eastern part of
the State of Oregon near the Idaho border. A summary of total energy and energy
credit sales by location is as follows:
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For the Year Ended December 31,
|
|
|
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2017
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
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|
USG Oregon LLC located in
Eastern Oregon
|
$
|
19,941,366
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|
$
|
19,561,718
|
|
$
|
18,823,799
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|
USG Nevada LLC located in
Northwestern Nevada
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|
6,255,599
|
|
|
6,980,358
|
|
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7,324,484
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Raft River Energy I LLC located in
Southeastern Idaho
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|
5,859,822
|
|
|
4,939,599
|
|
|
5,051,815
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Total energy and energy
|
|
|
|
|
|
|
|
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credits sales
|
$
|
32,056,787
|
|
$
|
31,481,675
|
|
$
|
31,200,098
|
|
Financial Information about Business Segments
The Company has two reporting segments: operating plants and
corporate and development. For more information about the business segments,
please see Note 16 to our consolidated financial statements.
Available Information
We file annual, quarterly and periodic reports, proxy
statements and other information with the U.S. Securities and Exchange
Commission (SEC). You may obtain and copy any document we file with the SEC at
the SECs Public Reference Room at 100 F Street, N.E., Room 1580;Washington D.C.
20549. You may obtain information on the operation of the SECs Public Reference
Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website
at http://www.sec.gov that contains reports, proxy and other information
statements and other information regarding issuers that file electronically with
the SEC. Our SEC filings are accessible via the internet at that website.
We make available, free of charge through our Internet website
at http://www.usgeothermal.com, our annual report on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 of 1934, as amended (the Exchange Act), as soon as reasonably practicable after such material is electronically
filed with or furnished to the SEC. Information on our website is not
incorporated into this report and is not a part of this report.
-29-
Governmental Approvals and Regulations
The geothermal energy industry in the United States is
regulated by federal, state and local agencies and commissions. Those agencies
and commissions regulate geothermal drilling, power generation activities and
environmental protection through permitting, licensing and bonding requirements.
The following information is a general summary of the electric utility industry
and applicable regulations in the United States and is not a full statement of
the law or all issues pertaining to electric industry requirements.
Regulatory oversight of the industry can be broadly divided
between rules governing geothermal exploration and rules governing actual energy
generation, power sales and delivery. Geothermal fluid production is regulated
under federal and state rules and regulations that require permits for drilling
operations, geothermal fluid production and injection, and well abandonment.
Prior to drilling agencies will review plans and ensure that natural resource
values such as air, water, wildlife and vegetation are protected. Geothermal
energy generation is regulated under federal, state and local rules and
regulations. Permits are required for power plant construction and operation and
ensure that a project site is suitable and that natural resource values and
community concerns, if any, are evaluated and mitigated during the planning and
design phase.
Federal Electric Utility Industry Regulation
.
Electricity production and public utilities are regulated by both the
federal government and state utility commissions. State utility commissions
traditionally exercise their jurisdiction over an electric utilitys retail
operations. There are two primary pieces of federal legislation that have
governed public utilities since the 1930s, the Federal Power Act (FPA) and
Public Utility Holding Company Act of 1935 (PUHCA). These statutes have been
amended and supplemented by subsequent legislation, including Public Utility
Regulatory Protection Act (PURPA), the Energy Policy Act of 1992, and Energy
Policy Act of 2005 (EPAct 2005).
Federal Power Act
.
Pursuant to the FPA the
Federal Energy Regulatory Commission (FERC) has exclusive jurisdiction over
the rates for most wholesale sales of electricity and transmission in interstate
commerce. These rates may be based on a cost of service approach or may be
determined on a market basis through competitive bidding or negotiation. FERC's
regulations under PURPA exempt owners of small power production Qualifying
Facilities that use geothermal resources as their primary source and other
Qualifying Facilities that are 30 megawatts or under in size from many
provisions of the FPA.
Under the FPA and FERCs regulations, the wholesale sale of
power at market-based or cost-based rates requires that the seller have
authorization issued by FERC to sell power at wholesale pursuant to a
FERC-accepted rate schedule. FERC grants market-based rate authorization based
on several criteria, including a showing that the seller and its affiliates lack
market power in generation and transmission, that the seller and its affiliates
cannot erect other barriers to market entry and that there is no opportunity for
abusive transactions involving regulated affiliates of the seller. All of the
Companys facilities are qualifying facilities and have been granted market-based rate authority to make wholesale sales of electrical
energy by FERC. For the Neal Hot Springs power plant, USG Oregon files
electronic quarterly reports of the contract and transaction data.
-30-
Energy Policy Act of 2005
.
EPAct 2005
contains provisions to prohibit the manipulation of the electric energy and
natural gas markets and increase the ability of FERC to enforce and promote
compliance with the statutes, orders, rules, and regulations that FERC
administers. To implement the market manipulation provision of EPAct 2005, FERC
amended its regulations to prohibit a company, in connection with the purchase
or sale of natural gas, electric energy, or transportation or transmission
services subject to FERCs jurisdiction, from (1) using or employing any device,
scheme, or artifice to defraud, (2) declaring any untrue statement of a material
fact or omitting to state a material fact necessary in order to make the
statements made, in the light of the circumstances under which they were made,
not misleading, or (3) engaging in any act, practice, or course of business that
operates or would operate as a fraud or deceit upon any person. The EPAct 2005
made a number of other changes to laws affecting the regulation of electricity.
These include, but are not limited to, giving FERC explicit authority to
proscribe and enforce rules governing market transparency, giving FERC authority
to oversee and enforce electric reliability standards, requiring FERC to
promulgate rules providing for incentive ratemaking to encourage investments
that promote transmission reliability and reduce congestion, giving FERC certain
siting authority for transmission lines in critical transmission corridors,
requiring FERC to promulgate rules granting incentives for transmission owners
to join Regional Transmission Organizations, authorizing FERC to require
unregulated utilities to provide open access transmission, and ensuring that
load serving entities can retain transmission rights necessary to serve native
load requirements. EPAct 2005 promulgated PUHCA 2005, which repeals PUHCA 1935,
effective as of February 8, 2006.
Public Utility Holding Company Act
.
Under
PUHCA 2005, the books and records of a utility holding company, its affiliates,
associate companies, and subsidiaries are subject to FERC and state commission
review with respect to transactions that are subject to the jurisdiction of
either FERC or the state commission or costs incurred by a jurisdictional
utility in the same holding company system. However, if a company is a utility
holding company solely with respect to Qualifying Facilities, exempt wholesale
generators, or foreign utility companies, it will not be subject to review of
books and records by FERC under PUHCA 2005. Qualifying Facilities that make only
wholesale sales of electricity are not subject to state commissions rate,
financial, and organizational regulations and, therefore, would not be subject
to any review of their books and records by state commissions pursuant to PUHCA
2005 as long as the Qualifying Facility is not part of a holding company system
that includes a utility subject to regulation in that state.
Our power plants are Qualifying Facilities that make only
wholesale sales of electricity and are not subject to rate, financial and
organizational regulations that are otherwise applicable to electric utilities
in those states. The power plants each sell their electrical output under power
purchase agreements to an electric utility company. The utilities are regulated
by their respective state public utilities commissions. Neither USG nor our
subsidiaries are considered utility holding companies under FPA, FERC, the
EPAct2005, or PUHCA2005 and those regulations have had no direct adverse impact
on our ability to develop geothermal resources or deliver power under our
contracts.
-31-
Geothermal Development Concession in
Guatemala
.
The following summary of certain aspects of the
electric industry in Guatemala should not be considered a full statement of the
laws of Guatemala or all of the issues pertaining thereto.
In Guatemala, the General Electricity Law of 1996, Decree
93-96, created a wholesale electricity market and established a new regulatory
framework for the electricity sector. The law created a regulatory commission,
the CNEE, and a new wholesale power market administrator, the AMM, for the
regulation and administration of the sector. The AMM is a private not-for-profit
entity. The CNEE functions as an independent agency under the Ministry of Energy
and Mines and is in charge of regulating, supervising, and controlling
compliance with the electricity law, overseeing the market and setting rates for
transmission services, and distribution to medium and small customers. All
distribution companies must supply electricity to such customers pursuant to
long-term contracts with electricity generators. Large customers can contract
directly with the distribution companies, electricity generators or power
marketers, or buy energy in the spot market. Guatemala has approved a Law of
Incentives for the Development of Renewable Energy Power plants, Decree 52-2003,
in order to promote the development of renewable energy power plants. This law
provides certain benefits to companies utilizing renewable energy, including a
10-year exemption from corporate income tax and an import tax exemption for
generation equipment, transmission lines and substation equipment. In September
2008, CNEE issued a resolution which approved the Technical Norms for the
Connection, Operation, Control and Commercialization of the Renewable
Distributed Generation and Self-producers Users with exceeding amounts of
energy. This technical norm was created to regulate all aspects of generation,
connection, operation, control and commercialization of electric energy produced
with renewable sources to promote and facilitate the installation of new
generation plants, and to promote the connection of existing generation plants
which have exceeding amounts of electric energy for commercialization. It is
applicable to projects with a capacity of up to 5 megawatts.
Environmental Credits
In the past several years, there has been increased demand for
energy generated from geothermal resources in the United States as production
costs for electricity generated from geothermal resources have become
competitive relative to fossil fuel generation. This is partly due to newly
enacted legislative and regulatory incentives, such as production tax credits
and state renewable portfolio standards. State renewable portfolio standards
laws require that an increasing percentage of the electricity supplied by
electric utility companies operating in states with such standards will be
derived from renewable energy resources until certain pre-established goals are
met. We expect increasing demand for energy generated from geothermal and other
renewable resources in the United States as additional states adopt or extend
renewable portfolio standards.
As a green power producer, environmental-related credits,
such as renewable energy credits or carbon credits, are also available for sale
to power companies (to allow them to meet their green power requirements) or
to businesses which produce carbon based pollution. In all of the Companys
projects, these credits have been sold separately, or bundled with the
electricity to provide an additional source of revenue.
-32-
We expect the following key incentives to influence our results
of operations:
Production Tax Credits and Investment Tax
Credits
.
A PTC provides project owners with a federal tax credit
for the first ten years of plant operation. The PTC enhances the annual revenues
of the projects by as much as 25 percent per year for the first 10 years.
Facilities that begin construction after December 31, 2016 will not be eligible
to use this production tax credit. The federal production tax credit available
for geothermal energy in 2014 was 2.3 cents per kilowatt-hour. Alternatively,
certain projects under construction before the end of 2016, are eligible to
elect to take a 30% ITC in lieu of the PTC. The ITC may be taken after the plant
has gone into operation and may be monetized. Both PTC and ITC credits require a
tax equity partner to monetize.
The WGP Geysers project, San Emidio II project, and the
Crescent Valley project all began construction prior to December 31, 2014, and
the Company believes all three projects currently qualify for the 30% ITC in
lieu of the PTC.
Renewable Energy Credits
.
Renewable Energy
Certificates, or RECs, are tradable environmental commodities that represent
proof that one megawatt-hour of electricity was generated from an eligible
renewable energy resource. A renewable energy provider is credited with one REC
for every 1,000 kilowatt-hours or one megawatt-hour of electricity it produces.
The electrical energy is fed into the electrical grid and the accompanying REC
can either be delivered to the purchaser of the power (bundled) or can be sold
on the open market providing the renewable energy producer with an additional
source of income.
On July 29, 2006, the Company signed a $4.6 million renewable
energy credits purchase and sales agreement with Holy Cross Energy, a Colorado
cooperative electric association. The agreement is capped at 87,600 RECs (10
megawatt average over the year) through the year 2017. Holy Cross Energy began
purchasing the renewable energy credits associated with the RREI power
production on October 2007, and continued purchasing through 2017. Under the
revised RREI agreement, Idaho Power keeps all RECs above 87,600 RECs per year.
In addition, we retain 49% of the renewable energy credits associated with power
production from RREI after 2017 and Idaho Power retains the other 51%.
On December 15, 2010, a second REC contract was signed with
Public Utility District No. 1 of Clallam County, Washington. The term of the
agreement is from 2018 to 2034 and includes sales of an estimated 50,000
megawatt hours of RECs annually, representing the 49% ownership in RECs retained
by RREI under the Idaho Power PPA.
The PPAs for the existing San Emidio and Neal Hot Springs power
plants require the bundling of power sales and RECs. Therefore, under these
contracts all RECs are delivered with the net power sold to the utility.
-33-
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;
and
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Risks Related to the Merger.
|
Risks Related to Our Business
Our geothermal power plants have numerous pieces of
equipment that are subject to breakdown or failure, many beyond our control.
Failure of critical equipment could have a material impact on electrical
generation and associated revenues.
Our financial performance depends on
the successful operation of our geothermal power plants, which are subject to
numerous operational risks that are outside of our control. The continued
operation of our geothermal power plants involves many risks, including
breakdown or failure of power generation equipment, transmission lines,
pipelines, pumps or other equipment or processes, and performance below expected
levels of output or efficiency. If any of these risks were to materialize, they
could have a material and adverse effect on our financial condition and results
of operations.
A breakdown or failure in our geothermal power plants, our
power generation equipment, the transmission lines, pipelines, pumps or other
equipment or processes would also mean lost revenue because such a failure or
breakdown could prevent us from selling electricity to our customers. For
instance, because we rely on transmission lines owned by third parties to
deliver all of the power that we generate to the purchasers of our electricity,
any interruption in a transmission 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.
-34-
Our geothermal reserves could decline in the future.
Declines greater than those that we expect would reduce our electricity
production levels, which could have a material adverse effect on our operating
revenues.
We currently derive all of our revenue from geothermal energy and anticipate that we will continue to generate
substantially all of our revenue from our current geothermal power plants for
the next several years. Electricity production from geothermal properties can
decline as the water resources in the earth are used, with the rate of water or
temperature decline depending on reservoir characteristics and our ability to
re-inject water effectively back into the earth. Therefore, we try to minimize
the decline in water and temperature of the water in the ground and maximize the
resources that we use to generate electricity. For each of our geothermal power
plants, we estimate the productivity of the geothermal resource and the expected
decline in productivity. We base our operating plans and financial models on
these estimates of resources. However, because the development and operation of
geothermal energy resources are subject to substantial risks and uncertainties,
the productivity of a geothermal resource may decline more than anticipated,
resulting in insufficient reserves being available for sustained generation of
the electrical power capacity desired. Factors that could adversely affect our
geothermal reserves and result in decline rates greater than we forecast
include, among others:
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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
corresponding future net cash flows attributable to those resources are prepared
by independent engineers, geologists and geoscientists. There are numerous
uncertainties inherent in estimating these resources and the potential future
cash flows attributable to such resources. Reserve engineering is a subjective
process of estimating underground accumulations that cannot be measured in an
exact manner. The accuracy of an estimate of quantities of resources, or of cash
flows attributable to such resources, is a function of the available data,
assumptions regarding future electricity prices and expenditures for future
development and exploitation activities, and of engineering and geological
interpretation and judgment. In order to undertake these estimates and studies,
independent third parties must often rely to some extent on our own estimates
and data, which we believe are reasonable and accurate but which may ultimately
be proved to be incorrect. Actual future production, revenue, taxes, development
expenditures, operating and royalty expenses, quantities of recoverable
resources and the value of cash flows from such resources may vary significantly
from the assumptions and underlying information set forth herein. In addition,
different reserve engineers may make different estimates of resources and cash
flows based on the same available data. We cannot assure you that we will
accurately estimate the quantity or productivity of our geothermal resources.
Our results are subject to quarterly and seasonal
fluctuations.
Our results of operations are subject to seasonal
variations. This is primarily because some of our power plants receive higher
energy payments during certain summer and winter months. Some of our air cooled
power plants may also experience reduced generation during hot summer months due
to the lower differential between the temperature of the geothermal fluid and
the ambient surroundings. Such seasonal variations could materially and adversely affect our business,
financial condition, and cash flow. If our operating results fall below the
publics or analysts expectations, the market price of our common stock can
fall in such periods.
-35-
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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spills, releases, and other accidental
environmental impacts; and
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induced seismic activity.
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The occurrence of any one of the above may result in injury,
loss of life, suspension of operations, environmental damage and remediation
and/or governmental investigations and penalties.
In addition, all of our operations are susceptible to damage
from natural disasters, such as earthquakes and fires, which involve increased
risks of personal injury, property damage and service interruptions. Any of
these events could cause serious injuries, fatalities or property damage, which
could expose us to liabilities. The payment of any of these liabilities could
reduce, or even eliminate, the funds available for exploration, development and
acquisition, or could result in a loss of our properties. Our insurance policies
are subject to deductibles, limits and exclusions that are customary or
reasonable given the cost of procuring insurance, current operating conditions
and insurance market conditions. There can be no assurance that such insurance
coverage will continue to be available to us on an economically feasible basis,
nor that all events that could give rise to a loss or liability are insurable,
nor that the amounts of insurance will at all times be sufficient to cover each
and every loss or claim that may occur involving the operations of our assets.
If we incur substantial liability and the damages are not covered by insurance
or are in excess of policy limits, or if we incur liability at a time when we do
not have liability insurance, our business, results of operations and financial
condition could be materially and adversely affected.
Threats of terrorism and cyber-attacks could impact our
operations and could adversely affect our business and operating revenues.
We are subject to the potentially adverse operating and financial
effects of terrorist acts and threats, as well as cyberattacks. Our generation
and transmission facilities, information technology systems and other
infrastructure facilities could be directly or indirectly affected by such
activities. Terrorist acts or other similar events could harm our business by
limiting our ability to generate or transmit power and by delaying the
development of new generating facilities. These events could result in a
material decrease in revenues and significant additional costs to repair and
insure our assets. We operate in an industry that requires the continued
operation of sophisticated information technology systems vulnerable to security
breaches, and failures. Those breaches and events may result from acts of our
employees, contractors, or third parties. If our technology systems were to be
breached and we were unable to recover in a timely way, we would be unable
to fulfill critical business functions, which could adversely affect our
business.
-36-
Our geothermal resource leases may terminate if not
placed into production, which could require us to enter into new leases or
secure rights to alternate geothermal resources, none of which may be available
on terms as favorable to us as any such terminated lease, if at all.
Most of our geothermal resource leases are originally for a
fixed term but provide for continuation for so long as we extract geothermal
resources in commercial quantities or pursuant to other terms of extension.
Most of the leases have been producing in commercial quantities for many
years. The land covered by a few of our periphery leases have yet to produce
commercial quantities of geothermal resources. Leases covering land that
remains undeveloped and does not produce geothermal resources in commercial
quantities may terminate. In the event that we determine that a terminated lease
is subsequently required for a project, we would need to enter into one or more
new leases in order to develop and exploit these geothermal resources. It may
not be possible to enter into new leases or these new leases could be on less
favorable financial terms than the prior leases, which could materially and
adversely affect our ability to achieve commercial success on the applicable
project.
Pursuant to the terms of our leases with the BLM, we are
required to conduct our operations on BLM-leased land in a workmanlike manner
and in accordance with all applicable laws and BLM directives and to take all
mitigating actions required by the BLM to protect the surface of and the
environment surrounding the relevant land. In the event of a default under any
BLM lease, or the failure to comply with such requirements, or any
non-compliance with any applicable regulations governing our use of the land,
the BLM may, thirty days after notice of default is provided to our relevant
project subsidiary, suspend our operations until the requested action is taken
or terminate the lease, either of which could materially and adversely affect
our business, financial condition, operating results and cash flow.
Claims have been made that thermal fracturing and well
drilling at some geothermal plants may cause seismic activity and related
property damage.
There are approximately two-dozen steam geothermal
plants operating within a fifty-square-mile region known as The Geysers
located near the community of Anderson Springs, in Northern California, and
there is general agreement that the operation of these plants causes a generally
low level of seismic activity. Some residents in the Anderson Springs area have
asserted property damage claims against those plant operators. There are
significant issues whether the plant operators are liable, and to date no court
has found in favor of such claimants. While we do not believe the areas where
our current projects are located will present the same geological or seismic
risks, there can be no assurance that we would not be subject to similar claims
and litigation, which may adversely impact our operations and financial
condition.
As an SEC reporting company, failure to achieve and
maintain effective internal control over financial reporting could harm our
business and operating results and/or result in a loss of investor confidence in
our financial reports, which could in turn have a material and adverse effect on
our business and stock price.
We are required to document and test our
internal control over financial reporting so that our management can certify as
to the effectiveness of our internal control over financial reporting. We cannot
be certain as to the timing of completion of our evaluation, testing and
remediation actions, if any, related to internal controls and other SEC rules or the impact of the same on our operations. The
assessment of our internal control over financial reporting will require us to
expend significant management and employee time and resources and incur
significant additional expense.
-37-
During the course of our assessment of the effectiveness of our
internal control over financial reporting, we may identify material weaknesses
in our internal control over financial reporting, as well as any other
significant deficiencies that may exist or hereafter arise or be identified,
which could harm our business and operating results, and could result in adverse
publicity, regulatory scrutiny and a loss of investor confidence in the accuracy
and completeness of our financial reports. In turn, this could have a materially
adverse effect on our stock price, and, if such weaknesses are not properly
remediated, could adversely affect our ability to report our financial results
on a timely and accurate basis. Although we believe we would be able to take
steps to remediate any material weaknesses we may discover, we cannot assure you
that this remediation would be successful or that additional deficiencies or
weaknesses in our controls and procedures would not be identified. Moreover, we
expect to continue to operate at a relatively low staffing level. Our control
procedures have been designed with this staffing level in mind; however, they
are highly dependent on each 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.
Our participation in joint ventures is subject to risks
relating to working with a co-venture partner
. We are subject to risks
in working with a co-venture partner that could adversely impact our current
projects as well as anticipated development of expansion projects. Involving a
joint venture partner may result in issues related to funding challenges,
control issues, and other general disputes. Its possible that the proposed
project expansions may utilize the geothermal resource within the current joint
venture boundaries. Our required contribution to the joint venture could also
exceed returns from the joint venture.
We are a holding company and our revenues depend
substantially on the performance of our subsidiaries and the projects they
operate.
We are a holding company whose primary assets are our ownership
of the equity interests in our subsidiaries. We conduct no other business and,
as a result, we depend entirely upon our subsidiaries earnings and cash flow.
Our subsidiaries and projects may be
restricted in their ability to pay
dividends, make distributions or otherwise transfer funds to us prior to the
satisfaction of other obligations, including the payment of operating expenses
or debt service.
Counterparty credit default could have an adverse effect
on the Company.
Our revenues are generated under contracts with various
counterparties. Results of operations would be adversely affected as a result of
non-performance by any of these counterparties of their contractual obligations
under the various contracts. A counterpartys default or non-performance could
be caused by factors beyond our control. A default could occur as a result of
circumstances relating directly to the counterparty, or due to circumstances
caused by other market participants having a direct or indirect relationship
with such counterparty. We seek to mitigate the risk of default by evaluating
the financial strength of potential counterparties and utilizing industry
standard credit provisions in our contracts, however, despite our mitigation
efforts, defaults by counterparties may occur from time to time, and this could negatively impact
our results of operations, financial position and cash flows.
-38-
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.
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Any noncompliance with these laws and regulations could subject
us to material administrative, civil or criminal penalties or other liabilities
and could lead to a curtailment or shut down of one or more of our plants.
Additionally, our compliance with these laws may result in increased costs to
our operations or our exploration, acquisition and development of new plants or
may result in decreased production from our existing plants. We are unable to
predict the ultimate cost of complying with these regulations. Pollution and
similar environmental risks generally are not fully insurable.
We use industrial lubricants and other substances at our
projects that are or could become classified as hazardous substances. If any
hazardous substances are found to have been released into the environment at or
by the projects, we could become liable for the investigation and removal of
those substances, regardless of their source or time of release. If we fail to
comply with these laws, ordinances or regulations, we could be subject to civil
or criminal liability, the imposition of liens or fines, and large expenditures
to bring the projects into compliance. Furthermore, we can be held liable for
the cleanup of releases of hazardous substances at other locations where we
arranged for disposal of those substances, even if we did not cause the release
at that location. The cost of any remediation activities in connection with a
spill or other release of such substances could be significant.
Our geothermal facilities have been in operation for a
substantial length of time, and current or future local, state and federal
environmental and other laws and regulations may require substantial
expenditures to remediate the properties or to otherwise comply with these laws
and regulations.
-39-
We depend on our senior management, geothermal resource
and other technical employees. The loss of these employees could harm our
business.
Our future operating results depend to a large extent upon the
continued contribution of key senior managers and personnel.
Our success depends on the skills, experience and efforts of
our people, particularly our senior management, geothermal resource and other
technical employees. The geothermal industry is relatively small with a limited
number of individuals with the management, technical and operational expertise
necessary to run and operate facilities. In addition, many of our workers have
significant and unique knowledge on how to manage and operate geothermal
facilities. The loss of the services of one or more members of our senior
management or of numerous employees with critical skills could have a material
adverse effect upon us. As of the date of this report, the Company has executed
employment agreements with key senior managers, but does not have key-man
insurance on any of them.
There are some risks for which we do not or cannot carry
insurance.
Because our current operations are limited in scope, the
Company carries property, public liability insurance and directors and
officers liability coverage, but does not currently insure against other risks.
As its operations progress, the Company will acquire additional coverage
consistent with its operational needs, but the Company may become subject to
liability for pollution or other hazards against which it cannot insure or
cannot insure at sufficient levels or against which it may elect not to insure
because of high premium costs or other reasons.
Our officers and directors may have conflicts of
interests arising out of their relationships with other companies.
Several of our directors and officers serve (or may agree to serve) as
directors or officers of other companies or have significant shareholdings in
other companies. To the extent that such other companies may participate in
ventures in which the Company may participate, the directors may have a conflict
of interest in negotiating and concluding terms respecting the extent of such
participation.
Risks Related to Our Growth
Our growth prospects depend in part on our ability to
further develop or acquire geothermal or other renewable energy power generation
facilities and resources, which are subject to substantial risks.
Because production from geothermal properties generally declines as both
water and temperature is depleted, with the rate of decline depending on
reservoir characteristics, our geothermal resources will decline as we continue
to produce electricity unless we conduct other successful exploration and
development activities or supplement the current amounts of water that we inject
into the reservoir with sufficient water from other sources, or both. The
acquisition and development of geothermal power generation facilities and
resources is complex, expensive, time consuming and subject to substantial
risks, many of which are outside of our control. In connection with the
development of geothermal power generation facilities and resources, we must:
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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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-40-
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obtain appropriate governmental permits;
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maintain cost controls during construction;
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identify, hire and retain a qualified work
force;
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obtaining Power Purchase Agreements; and
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negotiating engineering, construction, and
procurement agreements.
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We may be unsuccessful in accomplishing any of these matters or
in doing so on a timely basis. In our exploration efforts, we may not find
commercially productive reservoirs or, if we do, the remote location of the
resource may hinder our access to markets or delay our production. In addition,
project development is subject to various environmental, engineering and
construction risks. Although we may attempt to minimize the financial risks in
the development of a power generation facility by obtaining all required
governmental permits and approvals and arranging adequate financing prior to the
commencement of construction, the development of a power project may require us
to expend significant sums for preliminary engineering, permitting, legal and
other expenses before we can determine whether a project is feasible,
economically attractive or financeable.
In addition, community opposition could delay or prevent us
from obtaining the necessary approvals The process for obtaining initial
environmental, siting and other governmental permits and approvals is
complicated and lengthy, often taking more than one year, and is subject to
significant uncertainties. If we are unable to complete the development of a
facility, we would most likely not recover any of our investment in the project.
We cannot assure you that we will be successful in the acquisition of additional
geothermal resources or development of power generation facilities in the future
or that we will be able to successfully complete construction of our facilities
currently in development, nor can we assure you that any of these facilities of
resources will be profitable or generate consistent and reliable cash flow.
We may decide not to implement, or may not be successful
in implementing, our 5 year strategic plan for the growth of the Company.
There are uncertainties and risks associated with the achieving our 5
year growth target. It is possible that we may not be successful in implementing
one or more elements of the plan. It is also possible that we may decide to
change, or not implement, one or more elements of the plan. The growth goals are
provided as a target only, as we do not have direct control over the timing
associated with the solicitation for power purchase agreements, transmission
interconnection agreements, or use permits allowing for the building of a new
power plant. These or other factors could mean that we decide to change or even
abandon, or are otherwise unable to implement, one or more elements of the plan.
Early stage project development costs may not be recovered, in whole or in part,
if one or more elements of the plan are not successfully implemented. These
costs could materially and adversely affect our business, financial condition,
and cash flow and the price at which our common stock is traded.
Our business development activities may not be successful
and our projects under construction may not commence operation as scheduled.
We are in the process of developing and constructing a number of new
power plants. Our success in developing a particular project is contingent upon
successfully obtaining Power Purchase Agreements, satisfactorily negotiating
engineering, procurement, and construction agreements, obtaining required
permits, and securing adequate financing. These are followed by the satisfactory
completion of the power plant construction and commissioning. We may be unsuccessful in
accomplishing any of these tasks on a timely basis. Though we try to minimize
our expenses before we can determine whether a project is feasible, we may incur
significant expense prior for preliminary engineering, permitting and legal
support prior to securing financing.
-41-
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 may provide for a
priority payback to our lender or partner. If the actual costs of construction
or operations exceed the anticipated costs, we may not be able to operate
profitably or receive the planned share of cash flow and proceeds from the
project.
Our acquisition strategy could fail or present
unanticipated problems for our business in the future, which could adversely
affect our ability to make acquisitions or realize anticipated benefits of those
acquisitions.
Our growth strategy may include acquiring geothermal and
other renewable energy businesses and properties. We may not be able to identify
suitable acquisition opportunities or finance and complete any particular
acquisition successfully. Furthermore, acquisitions involve a number of risks
and challenges, including:
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diversion of managements attention;
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the need to integrate acquired operations;
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potential loss of key employees of the acquired
companies;
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greater geographic dispersion of employees;
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the potential that we may make bad
acquisitions;
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potential lack of operating experience in a
geographic market of the acquired business; and
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an increase in our expenses and working capital
requirements.
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Any of these factors could materially and adversely affect our
ability to achieve anticipated levels of cash flows from the acquired businesses
or realize other anticipated benefits of those acquisitions.
We may not be able to successfully integrate companies
that we may acquire in the future, which could materially and adversely affect
our business, financial condition, future results and cash flow.
Our
strategy is to continue to expand in the future, including through acquisitions.
Integrating acquisitions is often costly, and we may not be able to successfully
integrate our acquired companies with our existing operations without
substantial costs, delays or other adverse operational or financial
consequences. Integrating our acquired companies involves a number of risks that
could materially and adversely affect our business, including:
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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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-42-
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the difficulty of establishing and maintaining
uniform standards, controls, procedures and policies, including accounting
controls and procedures.
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If any of our acquired companies suffers performance problems,
the same could adversely affect the reputation of our group of companies and
could materially and adversely affect our business, financial condition, future
results and cash flow.
Our development activities are inherently very
risky
.
The high risks involved in the development of a geothermal
resource must be emphasized. The development of geothermal resources at our
projects is such that there cannot be any assurance of success. Exploration
costs are high and are not fixed. The geothermal resource cannot be relied upon
until substantial development, including drilling and testing, has taken place.
The costs of development drilling are subject to numerous variables such as
unforeseen geologic conditions underground which could result in substantial
cost overruns. Drilling for geothermal resources can result in well depths that
are relatively deep with well costs typically proportionate to the depth and
geology encountered. Drilling may involve unprofitable efforts, not only from
dry wells, but also from wells that do not produce sufficient volumes to
generate net revenues that provide a profit after drilling, operating and other
costs.
Our drilling operations may be curtailed, delayed or cancelled
as a result of numerous factors, many of which are beyond our control, including
economic conditions, mechanical problems, title problems, weather conditions,
compliance with governmental requirements and shortages or delays of equipment
and services. If our drilling activities are not successful, we could experience
a material adverse effect on our future results of operations and financial
condition.
In addition to the substantial risk that wells drilled will not
be productive, or may decline in productivity after commencement of production,
hazards such as unusual or unexpected geologic formations, pressures, downhole
conditions, mechanical failures, blowouts, cratering, explosions, chemical
corrosion, uncontrollable flows of well fluids, pollution and other physical and
environmental risks are inherent in geothermal exploration and production. These
hazards could result in substantial losses to us due to injury and loss of life,
severe damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations.
Our exploration and development activities may not be
commercially successful.
Exploration activities involve numerous risks,
including the risk that no commercially productive reservoirs will be
discovered. In addition, the future cost and timing of drilling, completing and
producing wells is often uncertain. Furthermore, drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including:
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unexpected drilling conditions; irregularities
in formations; equipment failures or accidents;
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compliance with governmental regulations;
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unavailability or high cost of drilling rigs,
equipment or labor;
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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.
-43-
Development and expansion are dependent on the ability to
successfully complete drilling activity.
Drilling and exploration are
the main methods of establishing new reserves. However, drilling and exploration
may be curtailed, delayed or cancelled as a result of:
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availability of equipment, particularly
drilling rigs and well casing;
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lack of acceptable prospective acreage;
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inadequate capital resources;
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weather;
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compliance with governmental regulations; and
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mechanical difficulties;
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opposition to development.
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The power generation industry is characterized by intense
competition, and we encounter pricing pressure from electric utilities,
community choice aggregators and other power producers and power marketers, that
could materially and adversely affect our growth plans.
The power generation industry is characterized by intense
competition. In recent years, there has been increasing competition in the sale
of electricity, in part due to excess capacity in a number of U.S. markets and
an emphasis on short duration contracts or spot market power. This increased
competition has contributed to a reduction in electricity prices. We expect that
power purchasers interested in long-term power purchase agreements will engage
in competitive bid solicitations to satisfy their demands. This competition
could adversely affect our ability to obtain PPAs and the price paid for
electricity by the relevant power purchasers. There is also increasing
competition between electric utilities, municipal power companies, and community
choice aggregators that is putting further pressure on power purchasers to
reduce the prices at which they purchase electricity from us.
Natural gas prices and oil prices are volatile, and lower
prices for these commodities could affect the electricity prices we are able to
obtain in future PPA contracts.
Development of our new plants depends on
the prices we are able to negotiate in our long term PPAs. The prices of those
PPAs in todays market are associated with both the demand for renewable energy,
as well as the prices and demand for natural gas in the United States markets
and the price of oil in our Central American markets. The markets for these
commodities are volatile, and modest drops in prices can affect significantly
price levels obtainable on new PPA contracts. Prices fluctuate widely in
response to relatively minor changes in the supply and demand for oil and gas,
market uncertainty and a variety of additional factors beyond our control, such
as:
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domestic and foreign supply of oil and gas;
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price and quantity of foreign imports;
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actions of the Organization of Petroleum
Exporting Countries and state-controlled
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oil companies relating to oil price and
production controls;
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domestic and foreign governmental regulations;
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political conditions in or affecting other oil
producing and gas producing countries, including conflicts in the Middle
East and conditions in South America and Russia;
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weather conditions, as evidenced by recent
hurricanes;
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technological advances affecting oil and gas
consumption;
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overall U.S. and global economic conditions;
and
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price and availability of alternative fuels.
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Further, oil and gas prices do not necessarily fluctuate in
direct relationship to each other. Because our geothermal reserves are valued
similar to gas reserves, our financial results are more sensitive to movements
in gas prices. Lower gas prices decrease our potential revenues available from
future long term PPAs, but have little impact on the actual proved reserves we
can produce economically, unlike typical oil and gas fields that require
extensive ongoing drilling to sustain production.
Our foreign projects expose us to risks related to the
application of foreign laws, taxes, economic conditions, labor supply and
relations, political conditions and policies of foreign governments, any of
which risks may delay or reduce our ability to profit from such
projects.
We have development projects outside of the United States. For
example, the El Ceibillo project is located in Guatemala. Our foreign
development is subject to regulation by various foreign governments and
regulatory authorities and is subject to the application of foreign laws. Such
foreign laws or regulations may not provide for the same type of legal certainty
and rights, in connection with our contractual relationships in such countries,
as are afforded to our projects in the United States, which may adversely affect
our ability to receive revenues or enforce our rights in connection with our
foreign operations. In addition, the laws and regulations of some countries may
limit our ability to hold a majority interest in some of the projects that we
may develop or acquire, thus limiting our ability to control the development,
construction and operation of such projects. Our foreign development is also
subject to significant political, economic and financial risks, which vary by
country, and include:
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Changes in government policies or personnel;
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Changes in general economic conditions;
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Restrictions on currency transfer or
convertibility;
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Changes in labor relations;
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Political instability and civil unrest;
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Changes in the local electricity market;
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Breach or repudiation of important contractual
undertakings by governmental entities; and
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Expropriation and confiscation of assets and
facilities.
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We plan to obtain political risk insurance in connection with
our foreign project, when appropriate, but note that such political risk
insurance does not mitigate all of the above-mentioned risks. In addition,
insurance proceeds received pursuant to a political risk insurance policy, where
applicable, may not be adequate to cover all losses sustained as a result of any
covered risks and may at times be pledged in favor of the lenders to a project
as collateral. Also, insurance may not be available in the future with the scope
of coverage and in amounts of coverage adequate to insure against such risks and
disturbances.
-45-
Our foreign project may expose us to risks related to
fluctuations in currency rates, which may reduce our profits from such projects
and operations.
Risks attributable to fluctuations in currency exchange
rates can arise when any foreign subsidiary borrows funds or incurs operating or
other expenses in one type of currency but receive revenues in another. In such
cases, an adverse change in exchange rates can reduce such subsidiary's ability
to meet its debt service obligations, reduce the amount of cash and income we
receive from such foreign subsidiary or increase such subsidiary's overall
expenses. In addition, the imposition by foreign governments of restrictions on
the transfer of foreign currency abroad or restrictions on the conversion of
local currency into foreign currency would have an adverse effect on the
operations of our foreign project and may limit or diminish the amount of cash
and income that we receive from such foreign projects.
Changes in costs and technology may significantly impact
our business by making our power plants less competitive.
A basic
premise of our business model is that generating baseload power at central
geothermal power plants achieves economies of scale and produces electricity at
a competitive price. However, gas-fired systems may under certain economic
conditions produce electricity at lower average short term prices than our
geothermal plants. In addition, there are other technologies that can produce
electricity at competitive prices, most notably fossil fuel power systems,
hydroelectric systems, wind-turbines and photovoltaic (solar) cells. Research
and development activities are ongoing to seek improvements in such alternate
technologies and their cost of producing electricity is gradually declining. It
is possible that advances will further reduce the cost of alternate methods of
power generation to a level below that of most geothermal power generation
technologies such that the competitive advantage of our projects may be
significantly impaired. Intermittent renewable energy sources such as solar and
wind, have already seen such cost reductions allowing them to offer their
intermittent power and substantially lower prices.
Risks Related to Our Power Purchase Agreements
A force majeure event, disruption of existing
transmission or a forced outage affecting a project or unexpected operating
expenses could reduce our net income and materially and adversely affect our
business, financial condition, future results and cash flow.
If a plant
experiences a force majeure event, such as a fire, earthquake or flood, we would
be excused from our obligations to deliver electricity under the PPAs to which
we are parties. However, the power purchasers under those PPAs may/will not be
required to make any energy payments with respect to the affected project or
plant so long as the force majeure event continues and, pursuant to certain of
our PPAs, will have the right to prematurely terminate the PPA altogether.
Additionally, to the extent that a forced outage has occurred, a power purchaser
may not be required to make any energy payments to the affected project, and if
as a result the project fails to attain certain performance requirements under
certain of our PPAs, the purchaser may have the right to prematurely terminate
the PPA altogether. As a consequence, we may not receive any net revenues from
the affected project or plant other than the proceeds from any business
interruption insurance that may apply to the force majeure event or forced
outage after the relevant waiting period, and we may incur significant
liabilities in respect of past amounts required to be refunded.
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In addition, we rely on transmission lines owned by local
utilities to deliver all of the electricity that we generate to the purchasers
of our electricity. If the transmission system were to experience a force
majeure event or a forced outage which prevented it from transmitting the
electricity from our projects to a power purchaser, the power purchaser would
not be required to make energy payments for that electricity with respect to the
affected project so long as such force majeure event or forced outage
continues.
Any of these events could significantly increase the expenses
incurred by our projects or reduce the overall generating capacity of our
projects and could significantly reduce or entirely eliminate the revenues
generated by one or more of our projects, which in turn would reduce our net
income and could materially and adversely affect our business, financial
condition, future results and cash flow.
Payments under our PPAs may be reduced if we are unable
to forecast our production adequately
. Under the terms of certain of our
PPAs, if we do not deliver electricity output within 90% to 110% of our
forecasted amount, payments for the amount delivered will be reduced, possibly
significantly. For example if the plant produces more than 110% of the power as
forecasted then we would receive reduced revenue for the amount over the
forecast figure. If the plant produces less than 90% of the forecast amount for
unexcused reasons, such as normal plant breakdowns and maintenance, then we may
be subject to a replacement power costs, depending on the prevailing power
market conditions. The agreement moves the power price to the market price
instead of contracted price, and the reduction in revenue could be perhaps 30
percent of that amount. As a risk mitigation element, we are not subject to this
adjustment until year three of the contract and then we are able to submit a new
forecast every three months thereby limiting this exposure.
Our failure to supply the contracted capacity under some
of our PPAs with investor-owned electric utilities in states that have renewable
portfolio standards may result in the imposition of penalties.
The terms
of certain of our PPAs require that we make payments to the relevant power
purchaser in an amount equal to such purchaser's replacement costs for renewable
energy that we are required to but do not provide as required under the PPA and
which such power purchaser obtains from an alternate source. In addition, we may
be required to make payments to the relevant power purchaser in an amount equal
to its replacement costs relating to any renewable energy credits we do not
provide as required under the relevant PPA. All of which could materially and
adversely affect our business, financial condition, future results and cash
flow.
Industry competition may impede our growth and ability to
enter into PPAs on terms favorable to us, or at all, which would negatively
impact our revenue
. The electrical power generation industry, of which
geothermal power is a sub-component, is highly competitive and we may not be
able to compete successfully or grow our business. We compete in areas of
pricing, grid access and markets. The industry in the Western United States is
complex as it is composed of public utility districts, cooperatives and
investor-owned power companies. Many of the participants produce and distribute
electricity. Their willingness to purchase electricity from an independent
producer may be based on a number of factors and not solely on pricing and
surety of supply. If we cannot enter into PPAs on terms favorable to us, or at
all, it would negatively impact our revenue and our decisions regarding development of
additional properties. Additionally, the credit quality of newly formed power
purchasers may negatively impact our ability to finance our power purchase
projects and may negatively impact their ability to pay for the contracted power
in the future.
-47-
Changes in costs and technology of other baseload
renewable electricity sources may significantly impact our business by making
our power plants less competitive.
A basic premise of our business model
is that our geothermal power plants generate baseload power at a competitive
price. While there are other renewable energy technologies that can also produce
baseload electricity, such as biomass, fuel cell, and hydroelectric systems,
most of these alternative technologies currently produce electricity at a higher
average price than our geothermal plants. However, research and development
activities are ongoing to seek improvements in such alternate technologies and
their cost of producing electricity may gradually decline. It is possible that
advances will further reduce the cost of alternate methods of power generation
to a level that is equal to or below that of most geothermal power generation
technologies. If this were to happen, the competitive advantage of our power
plants may be significantly impaired.
Risks Related to Our Liquidity and Capital
Resources
Substantial leverage and debt service obligations may
adversely affect our cash flows, liquidity and operations.
We have
substantial indebtedness that we may be unable to service and that restricts our
activities. Our ability to meet our debt service obligations and repay, extend,
or refinance our outstanding indebtedness will depend primarily upon the
operational performance of our geothermal power generation, the prices that we
receive for the electricity that we generate, risk management activities, as
well as general economic, financial, competitive, legislative, regulatory and
other factors that are beyond our control. In addition, this indebtedness has
important consequences, including:
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limiting our ability to borrow additional amounts for
working capital, capital expenditures, debt service requirements, entering
into other renewable energy businesses, or other purposes;
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limiting our ability to use operating cash flow in other
areas of our business because we must dedicate a substantial portion of
these funds to service the debt;
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increasing our vulnerability to general adverse economic
and industry conditions;
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limiting our ability to or increasing the costs of
refinance indebtedness; and
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limiting our ability to enter into marketing, hedging,
optimization and trading transactions by reducing the number of
counterparties with whom we can transact and the volume of those
transactions.
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We have a need for substantial additional financing and
will have to significantly delay, curtail or cease operations if we are unable
to secure such financing.
The Company requires substantial additional
financing to fund the cost of continued expansion of and the development of our
projects. Also, the Company requires funds for other operating activities, and
to finance the growth of our business, including the construction and
commissioning of power generation facilities. We may not be able to obtain the
needed funds on terms acceptable to us or at all.
-48-
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 and any future financing we receive may be less
favorable to us than our current financing arrangements, either of which may
adversely affect our ability to expand our operations.
Our geothermal
power plants generally have been financed using leveraged financing structures,
consisting of non-recourse debt obligations and partnership arrangements. Each
of our projects under development and those projects and businesses we may seek
to acquire will require substantial capital investment. Our continued access to
capital with acceptable terms is necessary for the success of our growth
strategy. Our attempts to obtain future financings may not be successful or on
favorable terms,
and are dependent on numerous factors including general
economic and capital market conditions, investor confidence, the continued
success of current projects, the credit quality of the projects being financed,
the political situation in the state in which the project is located and the
continued existence of tax laws which are conducive to raising capital. Market
conditions and other factors may not permit future project and acquisition
financings on terms similar to those previously received. If we are not able to
obtain financing for our power plants on a non-recourse basis, we may have to
finance them using direct equity investments, which may have a dilutive effect
on our common stock or incur additional recourse debt.
It is very costly to place geothermal resources into
commercial production
.
Before the sale of any power can occur, it
will be necessary to construct a gathering and disposal system, a power plant,
and a transmission line, and considerable administrative costs would be
incurred, together with the drilling of production and injection wells. Future
expansion of power production and other opportunities may result in
significantly increased capital costs related to increased production and
injection well drilling and higher costs for labor and materials. To fund
expenditures of this magnitude, we may have to find a joint venture participant
with substantial financial resources or expand the current ownership of existing
joint venture partners. There can be no assurance that a participant can be
found and, if found, it would result in us having to substantially reduce our
interest in the project.
We may be unable to realize our strategy of utilizing the
tax and other incentives available for developing geothermal power projects to
attract strategic alliance partners, which may adversely affect our ability to
complete these projects.
Part of our business strategy is to utilize the
tax and other incentives available to developers of geothermal power generating
plants to attract strategic alliance partners with the capital sufficient to
complete these projects. Many of the incentives available for these projects are
new and highly complex. There can be no assurance that we will be successful in
structuring agreements that are attractive to potential strategic alliance
partners. If we are unable to do so, we may be unable to complete the
development of our geothermal power projects and our business could be
harmed.
-49-
Our debt instruments impose significant operating and
financial restrictions on us; any failure to comply with these restrictions
could have a material adverse effect on our liquidity and our operations.
The instruments governing our outstanding debt impose significant operating and financial restrictions on our geothermal
operating subsidiaries. These restrictions could adversely affect us by limiting
our ability to plan for or react to market conditions or to meet our capital
needs. These restrictions limit our ability to, among other things:
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make prepayments on or purchase indebtedness in whole or
in part;
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pay dividends to us or make other distributions to us
thereby limiting our ability to use available cash to pay dividends to
stockholders, repurchase our capital stock or make other investments in
geothermal projects or other renewable energy businesses;
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make certain investments, including capital expenditures;
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enter into transactions with affiliates;
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create or incur liens to secure debt;
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consolidate or merge with another entity, or allow one of
our subsidiaries to do so;
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lease, transfer or sell assets and use proceeds of
permitted asset leases, transfers or sales;
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incur dividend or other payment restrictions affecting
certain subsidiaries;
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engage in certain business activities; and
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acquire facilities or other businesses
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In addition, any debt facilities that we enter into in the
future are likely to contain similar or additional covenants.
Our ability to comply with these covenants may be affected by
events beyond our control, and any material deviations from our forecasts could
require us to seek waivers or amendments of covenants or alternative sources of
financing or to reduce expenditures. We cannot assure you that such waivers,
amendments or alternative financing could be obtained, or if obtained, would be
on terms acceptable to us.
If we are unable to comply with the terms of the documents
governing our indebtedness, we may be required to refinance all or a portion of
our indebtedness or to obtain additional financing or sell assets. However, we
may be unable to refinance or obtain additional financing because of our
existing levels of indebtedness and the debt incurrence restrictions under our
existing indentures and other debt agreements. If our cash flow is insufficient
and refinancing or additional financing is unavailable, we may be forced to
default on our indebtedness. Such a default or other breach of the covenants or
restrictions contained in any of our existing or future debt instruments could
result in an event of default under those instruments and, due to cross-default
and cross-acceleration provisions, under our other debt instruments. Upon an
event of default under our debt instruments, the debt holders could elect to
declare the entire debt outstanding thereunder to be due and payable and could
terminate any commitments they had made to supply us with further funds. If any
of these events occur, we cannot assure you that we will have sufficient funds
available to repay in full the total amount of obligations that become due as a
result of any such acceleration, or that we will be able to find additional or
alternative financing to refinance any accelerated obligations.
-50-
Risks Related to Government Regulation
We are subject to complex government regulation which
could adversely affect our operations.
Our activities are subject to complex and stringent
environmental and other governmental laws and regulations. The exploration and
production of geothermal energy requires numerous permits, approvals and
certificates from appropriate federal, state and local governmental agencies,
including state and local agencies, whose regulations typically are more
stringent than in other states or localities, as well as compliance with
environmental protection legislation and other regulations. While we believe
that we have obtained the requisite approvals and permits for our existing
operations and that our business is operated in accordance with applicable laws,
we remain subject to a varied and complex body of laws and regulations that both
public officials and private individuals may seek to enforce. Existing laws and
regulations could be changed or reinterpreted, or new laws and regulations may
become applicable to us that could increase our costs associated with compliance
or otherwise harm our business and results of operations. We may be unable to
obtain all necessary licenses, permits, approvals and certificates for proposed
projects. Intricate and changing environmental and other regulatory requirements
may necessitate substantial expenditures to obtain and maintain permits. If a
project is unable to function as planned due to changing requirements or local
opposition, it may create expensive delays, extended periods of non-operation or
significant loss of value in a project.
Under certain circumstances, the United States Office of
Natural Resource Revenue (ONR) may require that our operations on federal
leases be suspended or terminated. These circumstances include our failure to
pay royalties or our failure to comply with safety and environmental
regulations. The requirements imposed by these laws and regulations are
frequently changed and subject to new interpretations, and if such were to
occur, could negatively impact our results of operations and cash flows.
Rules adopted by the BLM, as directed by the Energy Policy Act
of 2005, require competitive auction of all geothermal leases on Federal lands.
Competitive leasing is significantly increasing the cost of obtaining leases on
Federal land, is adding to the capital costs needed to develop geothermal
projects, is increasing the total electrical power prices needed to make a
geothermal project viable and is making it more difficult to acquire additional
adjacent lands for reservoir protection and exploration.
If Federal lands or any Federal involvement are included in any
geothermal development, requirements of the National Environmental Policy Act
("NEPA") will be triggered. Most of the geothermal resources in the United
States are located in the western states, where the Federal Government often is
the largest landowner. If a NEPA action is triggered, such as an Environmental
Impact Statement or Environmental Assessment, a project delay of one to two
years and a cost of $1,000,000 to $2,000,000 or more may be incurred while the
environmental permitting process is completed. NEPA not only can impact the
property where the geothermal resource is located, but includes the siting and
construction of transmission lines. Environmental legislation is evolving in a
manner that means stricter standards, and enforcement, fines and penalties for
non-compliance are more stringent. Environmental assessments of proposed
projects carry a heightened degree of responsibility for companies and
directors, officers and employees. The cost of compliance with changes in governmental
regulations has a potential to reduce the profitability of operations.
-51-
In the states of Idaho, Nevada California, and Oregon, drilling
for geothermal resources is governed by specific rules. In Nevada drilling
operations are governed by the Division of Minerals (Nevada Administrative Code
Chapter 534A); in Idaho by the Idaho Department of Water Resources (IDAPA 37
Title 03 Chapter 04); in California by the Division of Oil, Gas, and Geothermal
Resources (Public Resources Code Title 14 Chapter 4); and in Oregon by the
Division of Oil, Gas and Mineral Industries (Division 20 Geothermal Regulation).
These rules require drilling permits and govern the spacing of wells, rates of
production, prevention of waste and other matters, and, may not allow or may
restrict drilling activity, or may require that a geothermal resource be
unitized (shared) with adjoining land owners. Such laws and regulations may
increase the costs of planning, designing, drilling, installing, operating and
abandoning our geothermal wells, the power plant and other facilities. State
environmental requirements and permits, such as the Idaho Department of
Environmental Quality, and Air Quality Permit to Construct, include public
disclosure and comment. It is possible that a legal protest could be triggered
through one of the permitting processes that would delay construction and
increase cost for one of our projects. The state of Oregon has an Energy
Facility Siting Council that must issue a site certificate for any geothermal
energy facilities of 35 megawatts or higher.
Because of these state and federal regulations, we could incur
liability to governments or third parties for any unlawful discharge of
pollutants into the air, soil or water, including responsibility for remediation
costs. We could potentially discharge such materials into the environment:
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from a well or drilling equipment at a drill
site;
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leakage of fluids or airborne pollutants from
gathering systems, pipelines, power plant and storage tanks;
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damage to geothermal wells resulting from
accidents during normal operations; and
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blowouts, cratering and explosions.
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Because the requirements imposed by such laws and regulations
are frequently changed, we cannot assure you that laws and regulations enacted
in the future, including changes to existing laws and regulations or bonding
requirements, will not adversely affect our business by increasing cost and the
time required to explore and develop geothermal projects. In addition, because
some of our project properties were previously operated by others, we may be
liable for environmental damage caused by such former operators.
Changes in the legal and regulatory environment affecting
our projects could significantly harm our business financial position and
results of operations
.
Our operations are subject to extensive
regulation and, therefore, changes in applicable laws or regulations, or
interpretations of those laws and regulations, could result in increased
compliance costs, the need for additional capital expenditures or the reduction
of certain benefits currently available to our projects. The structure of
federal and state energy regulation currently is, and may continue to be,
subject to challenges, modifications, the imposition of additional regulatory
requirements, and restructuring proposals. We may not be able to obtain all
regulatory approvals that may be required in the future, or any necessary
modifications to existing regulatory approvals, or maintain all required
regulatory approvals. In addition, the cost of operation and maintenance and the
operating performance of geothermal power plants may be adversely
affected by changes in certain laws and regulations, including tax laws.
-52-
The reduction or elimination of government incentives
could adversely affect our business, financial condition, future results and
cash flows.
Construction and operation of our geothermal power plants
have benefited, and may benefit in the future, from public policies and
government incentives that support renewable energy and enhance the economic
feasibility of these projects. The most important tax rule that affects our
business is the Production Tax Credit (PTC) or Investment Tax Credit (ITC),
which is available to encourage the development of new geothermal plants.
Legislation enacted as part of the 2016 Fiscal Cliff efforts resulted in the
extension of the 30% PTC or ITC with eligibility for projects that started
construction before December 31, 2016. There is not a cash grant component to
the ITC credit so there is a risk related to monetizing the credit. The loss of
the PTC or ITC is a risk that could result in making the development of new
projects uneconomic. Additionally, current IRS guidance states that projects
that are placed into service by December 31, 2018 do not have to show continuous
construction. Projects placed into service after that date could have some or
all of their tax credit eligibility challenged. Additional policies and
incentives include accelerated depreciation tax benefits, renewable portfolio
standards, carbon trading mechanisms, and rebates. Some of these measures have
been implemented at the federal level, while others have been implemented by
different states. The availability and continuation of these public policies and
government incentives have a significant effect on the economics and viability
of our development. Any changes to such public policies, or any reduction in or
elimination of such Government incentives could affect us negatively.
Risks Related to Ownership of Our Common Stock
The public market for our common stock is not that liquid
which could result in purchasers being unable to liquidate their investment.
The market price for shares of our common stock may be highly volatile
and could be subject to wide fluctuations. Some of the factors that could
negatively affect our share price include:
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actual or anticipated variations in our reserve
estimates and quarterly operating results;
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changes in electricity prices;
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changes in our funds from operations or
earnings estimates;
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publication of research reports about us or the
exploration and production industry;
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increases in market interest rates which may
increase our cost of capital;
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changes in applicable laws or regulations,
court rulings and enforcement and legal actions;
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changes in market valuations of similar
companies;
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adverse market reaction to any increased
indebtedness we incur in the future;
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additions or departures of key management
personnel;
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actions by our stockholders;
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speculation in the press or investment
community;
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-53-
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large volume of sellers of our common stock
pursuant to our resale registration statement with a relatively small
volume of purchasers; and
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general market and economic conditions.
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The market price of our common stock could be volatile,
which could cause the value of your investment to decline.
Securities
markets worldwide experience significant price and volume fluctuations. This
market volatility, as well as general economic, market or political conditions,
could reduce the market price of our common stock in spite of our operating
performance. In addition, our operating results could fall short of the
expectations of market analysts and investors, and in response, the market price
of our common stock could decrease significantly. You may be unable to resell
your shares of our common stock at or above the initial offering price.
The market for our common stock is volatile. The trading price
of our common stock on the NYSE American LLC (NYSE American) is subject to
fluctuations in response to, among other things, quarterly variations in
operating and financial results, and general economic and market conditions. In
addition, statements or changes in opinions, ratings, or earnings estimates made
by brokerage firms or industry analysts relating to our market or relating to
our company could result in an immediate and adverse effect on the market price
of our common stock. The highly volatile nature of our stock price may cause
investment losses for our shareholders.
You may experience dilution of your ownership interests
due to the future issuance of additional shares of our common stock.
We
may in the future issue our previously authorized and unissued securities,
resulting in the dilution of the ownership interests of our present
stockholders. We are currently authorized to issue 250,000,000 shares of common
stock. The potential issuance of such additional shares of common stock may
create downward pressure on the trading price of our common stock. We may also
issue additional shares of our common stock or other securities that are
convertible into or exercisable for common stock in connection with the hiring
of personnel, future acquisitions, future private placements of our securities
for capital raising purposes, or for other business purposes.
Failure to comply with regulatory requirements may
adversely affect our stock price and business
.
As a public
company, we are subject to numerous governmental and stock exchange
requirements, with which we believe we are in compliance. The Sarbanes-Oxley Act
of 2002 (SOX) and the SEC have requirements that we may fail to meet by the
required deadlines or we may fall out of compliance with, such as the internal
controls assessment, reporting and auditor attestation, as applicable, which are
required under Section 404 of SOX. The Company has documented and tested its
internal control procedures in order to satisfy the requirements of Section 404
of SOX. SOX requires an annual assessment by management of the effectiveness of
the Companys internal control over financial reporting, as well as an
attestation report by the Companys independent auditors on internal controls
over financial reporting. If we fail to achieve and maintain the adequacy of our
internal controls, as such standards are modified, supplemented or amended from
time to time, we may not be able to ensure that we can conclude on an ongoing
basis that we have effective internal controls over financial reporting in
accordance with Section 404 of SOX. Moreover, effective internal controls are
necessary for us to produce reliable financial reports and are important to help
prevent financial fraud. If we cannot provide reliable financial reports or
prevent fraud, our business and operating results could be harmed, investors could lose confidence in our
reported financial information, and the trading price of our stock could drop
significantly. Our failure to meet regulatory requirements and exchange listing
standards may result in actions such as the delisting of our stock impacting our
stocks liquidity; SEC enforcement actions; and securities claims and
litigation.
-54-
We do not anticipate paying any dividends on our common
stock in the foreseeable future.
We do not expect to declare or pay any cash or other dividends
in the foreseeable future on our common stock, as we intend to use cash flow
generated by operations to expand our business. We may enter into other
borrowing arrangements in the future that restrict our ability to declare or pay
cash dividends on our common stock.
A substantial percentage of our shares are held by a
small group of stockholders whose interests may conflict with the interests of
our other stockholders.
As of December 31, 2017, our largest three
shareholders consisted of JCP Investment Management, LLC beneficially owning
2,871,448 shares (14.8%), Bradley Louis Radoff beneficially owning 1,923,000
shares (9.9%), and Private Management Group, Inc. beneficially owning 1,818,042
shares (9.4%), collectively totaling approximately 34.0% of our outstanding
common stock. As a result of these stockholders beneficial ownership of our
outstanding common stock, they could exert significant influence on the election
of our directors and decisions on matters submitted to a vote of our
shareholders, including mergers, consolidations and the sale of all or
substantially all of our assets. This concentration of ownership of our shares
could delay or prevent proxy contests, mergers, tender offers, or other
purchases of our shares that might otherwise give our stockholders the
opportunity to realize a premium over the then-prevailing market price for our
shares. This concentration of ownership may also adversely affect our stock
price. Future sales of common stock by these stockholders could cause our stock
price to decline.
Future sales of common stock by some of our insider
stockholders could cause our stock price to decline.
As of the date of
this report, our directors and officers collectively held 4,060,809 shares of
and options for our common stock, representing approximately 16.9% of issued and
outstanding common stock. Sales of such shares in the public market, as well as
shares we may issue upon exercise of outstanding options, could cause the market
price of our common stock to decline.
If securities or industry equity analysts do not publish
research or reports about our business, our stock price and trading volume could
be adversely affected.
To the extent one develops, the trading market
for our common stock will depend in part on the research and reports that
securities or industry equity analysts publish about us or our business. Our
common stock is not currently and may never be covered by securities and
industry equity analysts. If no securities or industry equity analysts commence
coverage of our company, the trading price of our stock would be negatively
impacted. In the event we obtain securities or industry equity analyst coverage
of our common stock, if one or more of the equity analysts who covers us
downgrades our stock, our stock price would likely decline. If one or more of
these equity analysts ceases coverage of our company or fails to regularly
publish reports on us, interest in the purchase of our stock could decrease,
which could cause our stock price or trading volume to decline.
-55-
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.
Risks Related to the Merger
There are a variety of risks, contingencies and other
uncertainties associated with the Merger that could result in the delay or the
failure of the Merger to be completed.
The Companys ability to complete
the Merger is subject to risks and uncertainties, including, but not limited to,
failure to satisfy required closing conditions to the Merger, including the
failure to obtain necessary shareholder, regulatory or other approvals, or
complete the Merger in a timely manner or at all. No assurance can be given that
the required approvals will be obtained and, even if all such approvals are
obtained, no assurance can be given as to the terms, conditions and timing of
the approvals or that they will satisfy the terms of the Merger Agreement. Even
if certain necessary approvals are obtained, the Company may still be subjected
to conditions that could result in a material delay in, or the abandonment of,
the Merger or otherwise have an adverse effect on the Company. More generally,
the occurrence of any event, change or other circumstances that could give rise
to the right of a party to terminate the Merger Agreement, including such a
circumstance where the Company would be required to pay Ormat a termination fee
equal to 3% of the Merger Consideration (approximately $3.2 million). As a
result, one or more conditions to closing of the Merger may not be satisfied and
the Merger may not be completed.
Any delay in completing the Merger may adversely affect the
Company or shareholders, including but not limited to delaying the time at which
shareholders may receive consideration for their shares of the Company and
further subjecting the Merger to the occurrence of any other event, change or
circumstance that may lead to the abandonment of the Merger.
The Company is subject to certain risks during the
pendency of the Merger that may have an adverse effect on the Companys
business.
During the pendency of the Merger, the Company and its
subsidiaries may be subject to business uncertainties, merger-related costs and
certain operating restrictions. For instance, the Merger Agreement restricts the
Company from taking certain specified actions while the Merger is pending
without first obtaining Ormats prior written consent. These restrictions may
limit the Company from pursuing attractive business opportunities, change or
prevent certain strategic decisions from being made or cause or prevent any
other changes to the Companys business prior to completion of the Merger or
termination of the Merger Agreement.
Additionally, the ability of the Company or its subsidiaries to
retain customers, retain and hire key personnel and maintain relationships with
vendors and suppliers may be subject to disruption due to uncertainty associated
with the Merger, which could have an adverse effect on the results of operations, cash flows and financial position of the Company
and its operating subsidiaries. The Companys management may also be distracted
from ongoing business operations due to the Merger.
-56-
Further, the Companys directors and executive officers may
have interests in the Merger that are different from, or in addition to, the
interests of the Company shareholders generally. These interests may cause the
Companys directors and executive officers to view the Merger differently and
more favorably than the Company shareholders may view it.
Failure to complete the Merger and/or the restrictions on
the Company from pursuing alternatives to the Merger could negatively affect the
Companys share price, future business and financial results.
Completion
of the Merger is not assured and is subject to risks, including the risks that
approval of the transaction by our shareholders or by governmental agencies will
not be obtained or that certain other closing conditions will not be satisfied.
If the Merger is not completed, the Companys ongoing business and financial
results may be adversely affected and the Company will be subject to several
risks, including:
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having to pay certain significant transaction costs
relating to the Merger without receiving the benefits of the Merger;
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the trading price of the Companys shares changing, to
the extent that the current trading price of the Companys shares reflects
an assumption that the Merger will be completed;
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potentially having to pay Ormat up to 3% of the Merger
Consideration (approximately$3.2 million) in specific circumstances,
including without limitation, a change in or withdrawal of our board of
directors recommendation to our shareholders or termination to accept an
alternative takeover proposal;
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litigation related to any failure to complete the Merger;
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potential reduction of value offered by others to the
Company in any future business combination; and
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erosion of customer, vendor, supplier and employee
confidence in the Company.
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Further, the Companys legal remedy in the event of breach of
the Merger Agreement (whether willfully, intentionally, unintentionally or
otherwise) by Ormat or Merger Sub is limited to receipt of the Ormat termination
fee, equal to 3% of the Merger Consideration (approximately $3.2 million), and
the Company may not be entitled to such fee at all in certain circumstances.
Pursuant to the terms of the Merger Agreement, the Company is
restricted from pursuing alternative takeover proposals to the Merger. Should
the Company pursue an alternative takeover proposal instead of the Merger, there
can be no guarantee that such a pursuit would be more successful or favorable to
the Company or its shareholders, either in terms of the costs and expenses to
pursue an alternative takeover proposal, the type or amount of consideration
that may be received by shareholders, the likelihood or time it takes to
complete an alternative takeover proposal, or for any other reason. Restrictions
on the Company pursuing alternative takeover proposals may also deter and/or
make it difficult for an otherwise interested third party to acquire or propose
to acquire the Company prior to the completion of the Merger, even one that may
be deemed of greater value to the Companys shareholders than the current offer
by Ormat. Furthermore, the concept of a termination fee may result in that third
partys offering a lower value to the Companys shareholders than such third
party might otherwise have offered.
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The nature of the all-cash Merger Consideration prevents
the Companys shareholders from participating in future growth
.
The Companys shareholders will be receiving a fixed amount of cash for
their stock and will not be compensated for any increase in the value of the
Company or Ormat during the pre-closing period or following the closing, which
may prevent the Companys shareholders from realizing any further upside to the
Merger.
Legal claims or investigations could result in an
injunction preventing completion of the Merger, the payment of damages in the
event the Merger is completed and/or may otherwise adversely affect the
Companys business, financial condition or results of operations.
Transactions such as the Merger are often subject to
shareholder lawsuits and other legal claims or investigations by regulators,
legislators and law enforcement officials, and the Company cannot guarantee the
success in responding or defending against any such lawsuits, claims or
investigations. Further, responding or defending to these lawsuits, claims and
investigations, regardless of the merits, can incur additional time and
expenses, which may have an adverse effect on the Companys business, financial
condition or results of operations.
The Company has interests in nine different geothermal resource
areas in the Western United States and one area in Guatemala, Central America.
The resource areas in the United States are located in Idaho (1), Oregon (2),
and Nevada (5) and California (1). The properties include the Raft River area
located in southeastern Idaho, the two properties located in southeastern
Oregon, and four properties in northwestern Nevada, the WGP Geysers area located
in northern California at the Geysers, and the El Ceibillo area located in
central Guatemala (near Guatemala City).
The Company operates three commercial power plants located in
the Western United States. The Raft River Unit I, Idaho plant became
commercially operational on January 3, 2008. The Neal Hot Springs, Oregon plant
achieved commercial operation on November 16, 2012. The San Emidio, Nevada plant
was acquired in May 2008. The acquired facility was replaced with a new power
plant, located on private land that became commercially operational in May
2012.
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WESTERN UNITED STATES REGIONAL LOCATION MAP
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Neal Hot Springs, Oregon
Neal Hot Springs is a geothermal resource located in Eastern
Oregon. The Company acquired the Neal Hot Springs geothermal energy and surface
rights in September 2006. A 22 megawatt (net) annual average geothermal power
plant was developed by USG Oregon LLC, and is currently in operation at this
site. The project has four production wells and nine injection wells at the
project.
Significant Lease/Royalty Terms
Approximately 521 acres of geothermal rights at Neal Hot
Springs are owned by Cyprus Gold Exploration Corporation (50%), JR Land and
Livestock (25%), and USG Oregon LLC (25%). Royalty for the two private leases is
paid on the gross revenue from energy sales paid by Idaho Power Company under
the PPA. The JR Land & Livestock lease has a 3% royalty for the first five
years of production, increases to 4% for years 6-15, and then to 5% for the
remainder of the lease term. The Cyprus lease establishes a 2% royalty for the
first ten years and then escalates to 3% for the remainder of the lease.
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San Emidio, Nevada
In 2008, the Company acquired a 3.6 megawatt operating
geothermal power plant and all associated private and federal geothermal leases
and certain ground water rights in the San Emidio Valley and at Gerlach, Nevada.
The San Emidio project is located approximately 75 air miles north of Reno,
Nevada. The Gerlach property is locate immediately northwest of Gerlach Nevada.
The San Emidio assets include the geothermal power project, 17,846 (27.9 square
miles) acres of geothermal leases, and ground water rights used for cooling
water. The Gerlach assets include 2,986 acres (4.7 square miles) of BLM and
private geothermal leases. The Gerlach leases are located along a geologic
structure known to host geothermal features including the Great Boiling Spring
and the Fly Ranch Geyser.
In 2012, USG completed the San Emidio Phase I repower project;
a 9.0 megawatt (net) annual average facility located on private land owned by
USG Nevada. Phase I repowering was completed utilizing the existing production
and injection wells.
Significant Lease/Royalty Terms
A geothermal unit was established for the operating project by
the Company in 2010 with the approval and oversight of the Bureau of Land
Management. The Unit allows USG Nevada LLC to allocate expenses among the
federal and private geothermal leases within the Unit and legally establishes
the percentage of private and federal land that contributes to geothermal
production known as the Participating Area. The Participating Area at San Emidio
totals 583.68 acres and includes 336.93 acres (57.7%) of private property and 246.75
acres (42.3%) of federally managed land.
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The lease agreement with the Kosmos Company establishes a 1.75%
royalty on gross electricity sales for the first 120 months of production and
3.5% royalty thereafter. The federal leases have a 10% netback royalty. The
netback calculation is based on gross electricity sales less the transmission
and generation cost deductions. In 2014 the equivalent federal royalty is 1.6%
of gross electricity sales.
Raft River, Idaho
The Raft River project comprises two packages of property that
include the Raft River Energy I LLC (RREI) leases, and leases held by the
Company. RREI operates the Unit I facility at Raft River which became
commercially operational on January 3, 2008. Leases assigned to RREI by the
Company included eight private geothermal leases, one of which is owned by the
Company. The Company retains direct control over four private leases and one
federal lease outside the RREI position.
All of the leases may be extended indefinitely as long as
production is maintained from the lease either individually or as a geothermal
unit. The Company and RREI hold a total of 4830 acres; 720 acres of federal
geothermal rights and 4,316 acres of private leases.
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Significant Lease/Royalty Terms
The private leases have 10 year primary terms with the rights
of unitization and extensions. Private leases have varying royalty rates
commensurate with other federal and private leases held by the Company and our
subsidiaries. Most of the private leases are subject to a 10% netback royalty
which is based on gross electricity sales less the transmission and generation
cost deductions. In 2014, USGs equivalent federal netback royalty was
equivalent to 1.6% of gross electricity sales where it was applied.
The federal lease, established on August 1, 2007, is held by
the Company and has a primary term of 10 years. After the primary term, The
Company has the right to extend the contract in accordance with regulation 43
CFR subpart 3207. The royalty under the lease is 1.75% of gross proceeds for the
first 10 years of production and 3.5% thereafter. At Raft River, royalty rates
have not exceeded rental payments.
A private geothermal unit was established for the operating
project in December 2015. The Unit establishes the geologic production area. A
Participating Area of 1640 was established in May 2015. The Participating Area
is that area that is reasonably expected to contribute to power production.
Production is allocated based on the percentage of each property in relation to
the entire Participating Area.
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El Ceibillo, Republic of Guatemala
The Company successfully acquired a geothermal energy rights
concession in the Republic of Guatemala, which was granted by the Guatemalan
government. It consists of 24,710 acres (100 square kilometers) and is located
14 miles southwest of Guatemala City, the capital. The concession provides
sub-surface geothermal rights only, and does not provide access to the surface
that is owned by private landowners. The concession had an initial five year
term for the development and construction of a power plant, which was extended
by three years in 2015. There are no royalties due to the government for use of
the geothermal resource.
The primary area of interest within the concession is the El
Ceibillo project, located near the town of Amatitlan, in a developed industrial
zone immediately adjacent to the highway that connects Guatemala City to the
Port of San Jose on the Pacific coast. An office and staff are located in
Guatemala City, and 80 acres of surface land within the concession area is under
lease.
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Crescent Valley and Lee Hot Springs, Nevada
On December 16, 2014, U.S. Geothermal completed the acquisition
of EPR and EPRs lease holdings at Crescent Valley and Lee Hot Springs,
Nevada.
The Crescent Valley property encompasses 21,319 acres of
private and federal geothermal resources leased by EPR and 2,640 acres of
geothermal resources leased by U.S. Geothermal Inc. Upon closing the acquisition
the Company our first well. The well is located on private surface and mineral
estate in section 3, Township 28 North Range 49 East and is intended to qualify
potential future power plant construction for the 30% renewable energy
investment tax credit. The Crescent Valley property includes 55 independent
leases ranging in size from 10 acres to 4,100 acres and an average parcel size
of 314 acres. EPRs private leases have a 15 year term with annual rent that
escalates at year five and at year 10.
Significant Lease/Royalty Terms
Annual lease rental payment obligations at Crescent Valley are
approximately $109,138 and royalty obligations during potential future power
production vary for private leases from 3% to 5% of gross sales. Royalty rates
for federal geothermal leases are 1.75% of gross revenue for the first 10 years
and 3.5% thereafter.
The Lee Hot Springs property encompasses 2,560 acres of federal
lands located approximately 17 miles south of Fallon, NV. The federal leases are
N-73679 and N-73930. The annual rental is $2,560 and a standard federal royalty is 1.75% of gross
revenue for the first 10 years and 3.5% thereafter.
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WGP Geysers, California
Western GeoPower Inc. (WGP) is a wholly owned subsidiary of
U.S. Geothermal Inc. WGPs property includes surface and geothermal rights that
consist of federal geothermal lease CA-51000 and one private geothermal lease
with no expiration. The total project acreage is 2,267 acres. The site has been
re-permitted with Sonoma County for construction and operation of up to a 38.5
megawatt geothermal power plant.
The project is located at the site of the former Pacific Gas
and Electric (PG&E) Unit 15 project, which once had a 62 megawatt (gross)
capacity power plant. During 10 years of operation, the PG&E plant declined
in production to approximately 38 megawatts before it was shut down in l989 and
all of the wells were plugged and abandoned. The project is located within the
broader Geysers geothermal field which covers a total of approximately 20,000
acres in the Mayacamas Mountains in Sonoma County and Lake County, California,
approximately 75 miles north of San Francisco. The Geysers geothermal resource
is the largest producing geothermal field in the world, and has been generating
greater than 850 megawatts of power for more than 30 years.
Significant Lease/Royalty Terms
There is no annual rental or royalty for the 421 acre private
parcel owned by WGP. The Abril Ranch mineral lease payment for an additional 410
acres of geothermal rights is $10,500 annually. The Filly-Brown properties
include 214 acres of surface access rights and 50% of the mineral rights owned by Western GeoPower. During production,
the geothermal royalty payment for Abril Ranch is 4.25% of gross revenue at a
power price of $100/MW or less and is consistent with market conditions.
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Vale Butte, Oregon
Vale Butte and the Vale Butte Geothermal Resource Area is
located in Eastern Oregon and borders the east side of the City of Vale. In the
first quarter of 2014, U.S. Geothermal Inc. acquired 393 acres of geothermal
energy and surface rights under six (6) leases. The leased area is immediately
adjacent to the City of Vale and includes private surface and mineral estate,
Vale City owned resources and Malheur County owned resources. The Vale Butte
resource area has been used for direct use heating for many years. Geochemical
analysis indicates a potential reservoir temperature of 311ºF to 320ºF and
historical drilling in the area has encountered ground (rock) temperatures in
excess of 300°F. Fault structures and hydrologic characteristics have been
identified that are similar to the Neal Hot Springs site, and those geologic
structures are contained within the acquired leases.
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Significant Lease/Royalty Terms
Four private leases and the Vale City lease are issued for a
period of 10 years with renewal options while the Malheur County lease was
issued for a period of 40 years with renewal options. The lease agreements are
consistent in terms of financial and development requirements and have a 2%
royalty payment on actual energy paid for by Idaho Power for the first 10 years
of commercial production.
Boise Administration Office, Idaho
On August 12, 2013, the Company signed a five year lease
agreement for office space and janitorial services. The lease payments are due
in monthly installments starting February 1, 2014. The monthly payments that
begin February 1, 2014 have two components which include a base rate of $3,234
that is not subject to increase and a rate beginning at $6,418 that is adjusted
annually according to the cost of living index. The contract includes a five
year extension option.
Land and Leases
The Company and its domestic subsidiaries control 65,434 acres
of land in California, Idaho, Nevada, and Oregon. U.S. Geothermal owns
approximately 2,536 acres of surface rights and 2,539 acres of geothermal rights
while approximately 64,064 acres are controlled through geothermal development
leases signed with the BLM, local governmental entities and private owners. The
companys average per acre lease rate is $9.00 per acre/year.
BLM Leases
The Company and its subsidiaries have 27 federal geothermal
leases issued in accordance with the Geothermal Steam Act by the BLM.
BLM geothermal leases grant the lessee the right to drill for,
extract, produce, remove, utilize, sell, and dispose of geothermal resources
from the leased lands, along with the right to build and maintain necessary
improvements on the leased land. Ownership of the geothermal resources and other
minerals beneath the land is retained in the federal mineral estate. The
geothermal lease grants exclusive geothermal development rights. The BLM will,
through authority granted by federal regulations and planning requirements,
ensure that other federal activities do not unreasonably interfere with the
geothermal lessees uses of the same land. Most federal leases include
stipulations and are governed by federal regulations, that require geothermal
development to be conducted in a workmanlike manner and in accordance with all
applicable laws and BLM directives and to take all actions required by the BLM
to protect the surface of and the environment surrounding the land. Surface
protections and environmental protection requirements include protection of
water quality, cultural and archeological resources, threatened or endangered
plants or animals, migratory birds, wildlife, and visual quality standards.
The BLM also authorizes geothermal lessees to enter into unit
agreements on federal lands to cooperatively develop a geothermal resource. The
BLM reserves the right to specify rates of development and to require the
geothermal lessee to commit to a unitization agreement.
Typical BLM leases have a primary term of ten years and may be
renewed as long as geothermal resources are being explored. If resources are
produced or utilized in commercial quantities, the lease can be renewed for up to forty years. If at the end of
the forty-year period geothermal steam is still being produced or utilized in
commercial quantities and the lands are not needed for other purposes, the
geothermal lessee will have a preferential right to renew the lease for a second
forty-year term, under terms and conditions as the BLM deems appropriate. During
the lease term the lessee is required to pay an annual per acre rental fee. The
fee escalates according to a schedule until geothermal production begins. After
production has commenced, the geothermal lessee is required to pay royalties on
the amount or value of energy production, and any by-products that may be
derived from geothermal production.
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BLM leases issued after August 8, 2005 (The Energy Policy Act
of 2005) also have a primary term of ten years. If the geothermal lessee does
not reach commercial production within the primary term, the BLM may grant two
five-year extensions. If the lessee is drilling a well for the purposes of
commercial production, the lease may be extended for five years and thereafter
as long as steam is being produced and used in commercial quantities the lease
may be extended for up to thirty-five years. If, at the end of the extended
thirty-five year term, geothermal steam is still being produced or utilized in
commercial quantities and the lands are not needed for other purposes, the
geothermal lessee will have a preferential right to renew the lease under terms
and conditions as the BLM deems appropriate.
BLM leases are issued either competitively or
non-competitively. Under the Energy Policy Act of 2005 Lessees who obtain leases
issued through a non-competitive process pay an annual rental fee equal to $1.00
per acre for the first ten years and $5.00 per acre each year thereafter.
Lessees who obtain a lease through a competitive bid process pay a rental of
$2.00 per acre for the first year, $3.00 per acre for the second through tenth
year and $5.00 per acre each year thereafter. For BLM leases issued, effective,
or pending on August 8, 2005, royalty rates are fixed between 1.0 -2.5% of the
gross proceeds from the sale of electricity during the first ten years of
production under the lease.
The royalty rate set by the BLM for geothermal resources
produced for the commercial generation of electricity but not sold in an arms
length transaction is 1.75% for the first ten years of production and 3.5%
thereafter. The royalty rate for geothermal resources sold by the geothermal
lessee or an affiliate in an arms length transaction is 10.0% of the gross
proceeds from the arms length sale.
Private Geothermal Leases
U.S. Geothermal and its subsidiaries hold geothermal rights
through leases with 73 individuals and companies. The leases authorize
geothermal development and operations on privately owned geothermal estates. In
some cases, the surface ownership is split from the mineral or geothermal
ownership.
Geothermal leases grant the exclusive right and privilege to
drill for, produce, extract, take and remove water, brine, steam, steam power,
minerals (other than oil), salts, chemicals, gases (other than gases associated
with oil), and other products produced or extracted through geothermal
development. The Company and its project subsidiaries are also granted
non-exclusive rights pertaining to the construction and operation of plants,
structures, and facilities on the leased land. The leases also grant the right
to dispose of waste brine and other waste products as well as the right to
re-inject into the leased land water, brine, steam, and gases in a well or wells
for the purpose of maintaining or restoring pressure in the productive
zones beneath the leased land or other land in the vicinity.
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Lessors reserve the right to conduct other activities on the
leased land in a manner that does not unreasonably interfere with the geothermal
lessees uses of the same land. Activities include agricultural use (farming or
grazing), recreational use and other energy developments. Geothermal leases are
typically issued for a primary term of 10 years and continue for as long as
leased products are being produced or the lessee is drilling, exploring,
extracting, processing, or reworking operations on the leased land.
Lease payments typically include annual rental that is based on
a rate per acre under lease and royalty payments on gross revenue from the
generation of electricity. Leases also include a provision for royalty payment
on all revenue from geothermal by-products. Leases typically have requirements
for drilling, extraction or processing operations on the leased land within the
primary term or to conduct operations with reasonable diligence until lease
products have been found, extracted and processed in quantities deemed paying
quantities by the lessee. The lessee has the right at any time within the
primary term to terminate the lease and surrender the relevant land. If the
lessee has not commenced operations on leased land within the primary term, the
annual rentals typically increase. The purpose of the increasing annual rental
is to encourage development which, in some cases may generate higher payment to
the lessor in the form of monthly royalty.
Our leases typically require the lessee to carry insurance,
conduct operations in accordance with all local, state, and federal regulations,
prevent waste, protect environmental quality, and promptly address any default
by lessee. The lessor and lessee are protected from automatic lease termination
through a notice requirement which must be received by the lessee by certified
mail, and a 30 day period in which the lessee must make diligent efforts to
correct the alleged default.
Geothermal Development Concession in Guatemala
U.S. Geothermal Guatemala S.A. has acquired a 24,700 acre
geothermal concession from the Ministry of Energy and Mines Guatemala C.A. The
site is located 12.5 miles southwest of Guatemala City and 2.5 miles west
southwest of the City of Amatitlan. The geothermal concession grants the rights
for subsurface geothermal development, and established milestones for
development and production. The Company has negotiated and acquired a surface
lease from one landowner and controls 80 acres enabling geothermal development.
The lease is similar in term and conditions to our leases with private
landowners in the United States for surface fee land.