annual information form

Transcription

ANNUAL INFORMATION FORM
FOR THE YEAR ENDED JUNE 30, 2010
SEPTEMBER 28, 2010
GENERAL MATTERS
In this Annual Information Form, unless otherwise noted or the context otherwise indicates, “Magma”
refers to Magma Energy Corp. alone and the “Company”, “we”, “us” and “our” refers to Magma Energy
Corp. and its direct and indirect subsidiaries.
FORWARD-LOOKING INFORMATION
This Annual Information Form contains certain “forward-looking information” which may include, but is
not limited to: statements with respect to future events or future performance; management’s expectations
regarding our growth; results of operations; business prospects and opportunities; expansion programs at
HS Orka hf’s (“HS Orka”) Svartsengi and Reykjanes power plants and the Soda Lake Operation; the
negotiation of an improvement in pricing under the current Soda Lake power purchase agreements
(“PPAs”); programs to upgrade and develop inferred and indicated resources at HS Orka’s properties and
the Soda Lake Operation; qualification of expenditures at the Soda Lake Operation for U.S. Federal
Treasury Grants; permitting for Magma’s expansion and exploration programs; negotiation of a PPA for
expansion to HS Orka’s Svartsengi and Reykjanes power plants; potential legislation in Iceland to ensure
public ownership of important energy enterprises and restrictions on private ownership; the potential
stopping, winding-down or invalidation of Magma Energy Sweden A.B.’s (“Magma Sweden”) business
transactions involving shares of HS Orka; the Company’s intention to co-operate with the government of
Iceland in respect of the government of Iceland’s announced intention to develop a strategy for the
operating environment for the Icelandic energy sector; the timing and substance of reports of the Special
Committee (as defined below); estimates of recoverable geothermal energy “resources” or energy
generation capacities; estimates or predictions of gas content, porosity, permeability, fractures, reservoir
temperature, reservoir pressure, steam cap temperature, well-head pressure and scaling; data collection,
expansion, upgrade, development, reinjection, rework or inhibition plans for any of the Company’s
properties; and permitting and regulatory requirements related to any such plans. Such forward-looking
information reflects management’s current beliefs and is based on information currently available to
management. Often, but not always, forward-looking statements can be identified by the use of words
such as “plan”, “expect”, “is expected”, “budget”, “estimates”, “goals”, “intend”, “targets”, “aims”,
“appears”, “likely”, “typically”, “potential”, “probable”, “continue”, “strategy”, “proposed”, or “believes”
or variations (including negative variations) of such words and phrases or may be identified by statements
to the effect that certain actions “may”, “could”, “should”, “would” or “shall” be taken, occur or
be achieved.
A number of known and unknown risks, uncertainties and other factors, may cause our actual results or
performance to materially differ from any future results or performance expressed or implied by the
forward-looking information. Such factors include, but are not limited to: new production wells at our
Soda Lake Operation may not define sufficient additional and commercially viable geothermal resources
to support our planned expansion programs; failure to discover and establish economically recoverable
and sustainable geothermal resources through our exploration and development programs; geothermal
exploration and development programs are highly speculative, are characterized by significant inherent
risk and costs, and may not be successful; we have a limited operating history; our financial performance
depends on our successful operation of geothermal power plants, which is subject to various operational
risks; our geothermal resources may decline over time and may not remain adequate to support the life of
our power plants; imprecise estimation of probability simulations prepared to predict prospective
geothermal resources or energy generation capacities; imprecise estimation of resources and reserves of
geothermal energy; variations in project parameters and production rates; geological occurrences beyond
our control may compromise our operations and their capacity to generate power; inability to obtain the
financing we need to pursue our growth strategy; it is very costly to place geothermal resources into
commercial production; we may continue to incur negative operating cash flow for the foreseeable future;
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energy prices are subject to dramatic and unpredictable fluctuations; industry competition may impede
our ability to access suitable geothermal resources; we may be unable to enter into PPAs on terms
favourable to us, or at all; the cancellation or expiry of government initiatives to support renewable
energy generation may adversely affect our business; impact of significant capital cost increases;
unexpected or challenging geological conditions; changes to regulatory requirements, both regionally and
internationally, governing development, geothermal resources, production, exports, taxes, labour
standards, occupational health, waste disposal, toxic substances, land use, environmental protection,
project safety and other matters; failure to obtain or maintain necessary licenses, permits and approvals
from government authorities; the success of our business relies on attracting and retaining key personnel;
the risk of human error; our officers and directors may have conflicts of interests arising out of their
relationships with other companies; we may face adverse claims to our title; developments regarding
Aboriginal, First Nations and Indigenous peoples; a significant portion of our revenue is attributed to
payments made by a single power purchaser under the Soda Lake PPAs; fluctuations in foreign currency
exchange and interest rates may affect our financial results; we may not be able to successfully integrate
businesses or projects that we acquire in the future; our insurance policies may be insufficient to cover
losses; the government of Iceland may take action which results in fines or other penalties levied against
Magma or HS Orka; the government of Iceland may invalidate or wind-down the Final Acquisition (as
defined below); the government of Iceland may invalidate or wind-down the prior privatization of
Hitaveita Sudurnesja (now HS Orka); the government of Iceland may pass legislation or constitutional
amendments to nationalize or restrict private or foreign ownership in Iceland’s energy sector or to reduce
the term of utilization rights for water or Geothermal resources owned by municipalities or the state,
increase levies for such utilization rights or restrict transfers of such utilization rights; Magma may not be
compensated for certain government action relating to Magma’s interest in HS Orka; integration of HS
Orka following the completion of the Final Acquisition; aluminum price risk; undisclosed liabilities
associated with the Final Acquisition; the results of operations of the companies in which we hold a
significant interest; risks associated with inter regional transmission grids; host country economic, social
and political conditions can negatively affect our operations; economic, social and political risks arising
from potential inability of end-users to support our properties; the fluctuation of our common share price
could result in investors losing a significant part of their investment; we have no dividend payment policy
and do not intend to pay any cash dividends in the foreseeable future; the issuance of additional equity
securities may negatively impact the trading price of our common shares; the risk of volatility in global
financial conditions, as well as significant decline in general economic conditions; and other development
and operating risks. There may be other factors that cause actions, events or results not to be as
anticipated, estimated or intended. These factors are not intended to represent a complete list of the risk
factors that could affect us. Additional risk factors are discussed in the section entitled “Risk Factors” in
this Annual Information Form. These factors should be considered carefully and investors should not
place undue reliance on forward-looking information.
The forward-looking information contained in this Annual Information Form is based upon what
management believes to be reasonable assumptions, including, but not limited to: the government of
Iceland invalidating or winding-down the Final Acquisition; the government of Iceland winding-down the
prior privatization of Hitaveita Sudurnesja (now HS Orka); the government of Iceland passing legislation
or constitutional amendments to nationalize or restrict private or foreign ownership in Iceland’s energy
sector or to reduce the term of utilization rights for water or Geothermal resources owned by the
municipalities or the state, increase levies for such utilization rights or restrict transfers of such utilization
rights; the effects of any increase in power production from HS Orka or our Soda Lake Operation; the
success and timely completion of planned exploration and expansion programs, including improvements
to facilities at HS Orka’s Svartsengi and Reykjanes power plants or our Soda Lake Operation; our ability
to comply with local, state and federal regulations dealing with operational standards and environmental
protection measures; our ability to negotiate and obtain PPAs on favourable terms; our ability to obtain
necessary regulatory approvals, permits and licences in a timely manner; the availability of materials,
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components or supplies; our ability to solicit competitive bids for drilling operations and obtain access to
critical resources; the growth rate in net electricity consumption; support and demand for nonhydroelectric renewables; government initiatives to support the development of renewable energy
generation; the accuracy of volumetric reserve estimation methodology and probabilistic analysis used to
estimate the quantity of potentially recoverable energy; the accuracy of the analysis used to estimate
resources and reserves of geothermal energy; environmental, administrative or regulatory barriers to the
exploration and development of geothermal resources on our properties; geological, geophysical,
geochemical and other conditions at our properties; the reliability of technical data, including extrapolated
temperature gradient, geophysical and geochemical surveys and geothermometer calculations; capital
expenditure estimates; availability of capital to fund exploration, development and expansion programs;
our competitive position; and general economic conditions. Forward-looking information is also based
upon the assumption that none of the identified risk factors that could cause actual results to differ
materially from the forward-looking information will occur.
There can be no assurance that the forward-looking information included in this Annual Information
Form will prove to be accurate, as actual results and future events could differ materially from those
anticipated in such information.
Accordingly, investors should not place undue reliance on
forward-looking information. Forward-looking information is made as of the date of this Annual
Information Form and, other than as required by applicable securities laws, we assume no obligation to
update or revise such forward-looking information to reflect new events or circumstances.
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TABLE OF CONTENTS
GENERAL MATTERS ................................................................................................................................. i
FORWARD-LOOKING INFORMATION ................................................................................................... i
INTRODUCTION ........................................................................................................................................ 1
Reporting Currency ................................................................................................................................ 1
Accounting Policies................................................................................................................................ 1
Scientific and Technical Information ..................................................................................................... 1
CORPORATE STRUCTURE ...................................................................................................................... 3
Name, Address and Incorporation.......................................................................................................... 3
Intercorporate Relationships................................................................................................................... 3
GENERAL DEVELOPMENT OF THE BUSINESS................................................................................... 3
DESCRIPTION OF THE BUSINESS.......................................................................................................... 7
General ................................................................................................................................................... 7
Overview of our Operations and Properties ........................................................................................... 9
I. Iceland............................................................................................................................................ 11
HS Orka Properties ................................................................................................................... 11
II. United States .................................................................................................................................. 35
United States Geothermal Leases ............................................................................................. 35
Overview of Volumetric Resource Estimate Methodology...................................................... 35
Soda Lake Operation ................................................................................................................ 36
McCoy Property ....................................................................................................................... 51
Panther Canyon Property.......................................................................................................... 58
Desert Queen Property.............................................................................................................. 64
Thermo Hot Springs Property................................................................................................... 69
Early-Stage Exploration Properties .......................................................................................... 75
III. South America ............................................................................................................................... 80
Mariposa Property .................................................................................................................... 80
Early-Stage Exploration Properties .......................................................................................... 94
DIVIDENDS............................................................................................................................................. 101
DESCRIPTION OF CAPITAL STRUCTURE ........................................................................................ 101
MARKET FOR SECURITIES ................................................................................................................. 102
ESCROWED SECURITIES ..................................................................................................................... 102
DIRECTORS AND OFFICERS ............................................................................................................... 103
Committees of the Board of Directors................................................................................................ 105
Audit Committee ................................................................................................................................ 105
Compensation Committee .................................................................................................................. 107
Governance and Nominating Committee ........................................................................................... 107
Corporate Cease Trade Orders and Bankruptcies............................................................................... 108
Penalties and Sanctions ...................................................................................................................... 109
Conflicts of Interest ............................................................................................................................ 109
PROMOTERS........................................................................................................................................... 109
LEGAL PROCEEDINGS ......................................................................................................................... 109
RISK FACTORS ...................................................................................................................................... 110
Risks Relating to our Business and Industry ...................................................................................... 110
Risks Relating to HS Orka ................................................................................................................. 119
Risks Relating to the Political and Economic Climates of Countries in which we Operate .............. 121
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Risks Relating to the Common Shares and Trading Market .............................................................. 122
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS........................ 124
TRANSFER AGENT AND REGISTRAR............................................................................................... 125
MATERIAL CONTRACTS ..................................................................................................................... 125
INTEREST OF EXPERTS ....................................................................................................................... 125
ADDITIONAL INFORMATION............................................................................................................. 126
GLOSSARY OF TERMS ......................................................................................................................... G-1
METRIC CONVERSION TABLE........................................................................................................... G-6
APPENDIX “A” – Audit Committee Charter........................................................................................... A-1
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INTRODUCTION
Unless otherwise indicated, the information contained herein is as at June 30, 2010.
Reporting Currency
Unless otherwise indicated, all references to “$” or “dollars” or in this Annual Information Form are to
United States dollars. References to “Cdn.$” are to Canadian dollars. References to “ISK” are to
Icelandic Krona. References to “AR$” are to Argentine Pesos.
Accounting Policies
All financial information in this Annual Information Form is prepared in accordance with Canadian
generally accepted accounting principles.
Scientific and Technical Information
The disclosure in this Annual Information Form of scientific or technical information for each of the HS
Orka Properties, the Soda Lake Operation and the McCoy, Panther Canyon, Desert Queen, Thermo Hot
Springs and Mariposa Properties is based on the following technical reports, respectively:

Geothermal Resources and Properties of HS Orka, Reykjanes Peninsula, Iceland:
Independent Technical Report dated January 29, 2010 prepared by Mannvit hf (the “HS
Orka Report”);

Independent Technical Report: Geothermal Resources and Reserves at Soda Lake Project,
Churchill County, Nevada USA dated April, 2010 prepared by GeothermEx, Inc.
(“GeothermEx”) (the “Soda Lake Report”);

Independent Technical Report Resource Evaluation of the McCoy Geothermal Project,
Churchill and Landers Counties, Nevada dated April 29, 2009 prepared by Dr. J. Douglas
Walker (Ph.D.) (the “McCoy Report”);

Independent Technical Report Resource Evaluation of the Panther Canyon/Leach
Geothermal Project, Pershing County, Nevada dated April 29, 2009 prepared by Dr. J.
Douglas Walker (Ph.D.) (the “Panther Canyon Report”);

Independent Technical Report Resource Evaluation of the Desert Queen Geothermal Project,
Churchill County, Nevada dated May 12, 2009 prepared by Dr. J. Douglas Walker (Ph.D.)
(the “Desert Queen Report”);

Independent Technical Report Resource Evaluation of the Thermo Hot Springs Geothermal
Project, Beaver County, Utah dated May 15, 2009 prepared by Dr. J. Douglas Walker (Ph.D.)
(the “Thermo Hot Springs Report”); and

Mariposa Geothermal Resource, Laguna Del Maule and Pellado Concessions, Chile dated
July 17, 2010 prepared by Philip James White of Sinclair Knight Merz Limited (“SKM”)
(the “Mariposa Report”).
Each of the authors of the foregoing technical reports is independent of the Company. Geothermal
properties and operations differ from mining or oil and gas properties and operations and Canadian
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securities regulators have not prescribed a form of technical report for geothermal properties, such as
ours. Accordingly, the foregoing technical reports have not been prepared in accordance with National
Instrument 43-101 – Standards of Disclosure for Mineral Projects (“NI 43-101”) or National
Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Furthermore, the
authors of these technical reports are not qualified persons for the purposes of NI 43-101 or qualified
reserves evaluators or auditors for the purposes of NI 51-101. The HS Orka Report has been prepared in
accordance with the standards set by the Australian Geothermal Reporting Code (the “Australian
Code”). On January 18, 2010, the Canadian Geothermal Energy Association announced the release of the
Canadian Geothermal Code for Public Reporting (the “Canadian Code”). The Mariposa Report and the
Soda Lake Report comply with the Canadian Code. The Australian and Canadian Codes are considered
as the geothermal standard for several countries in the world. All of the other technical reports have been
prepared in accordance with accepted practices within the geothermal industry. The technical reports are
available for review on the Internet on the system for electronic document analysis and retrieval
(“SEDAR”) at www.sedar.com.
For an explanation of the technical terms used in this Annual Information Form, please see “Glossary of
Terms” beginning on page G-1 of this Annual Information Form.
This Annual Information Form contains information from public sources on properties adjacent to our
geothermal projects. The accuracy and completeness of this data are not guaranteed. The information
presented in this Annual Information Form regarding adjacent properties is not necessarily indicative of
the geothermal resources on our properties.
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CORPORATE STRUCTURE
Name, Address and Incorporation
Magma was incorporated under the Business Corporations Act (British Columbia) on January 22, 2008.
Our head office is at Suite 410, 625 Howe Street, Vancouver, British Columbia, Canada, V6C 2T6.
Magma’s registered and records office is at Suite 1200, 200 Burrard Street, Vancouver, British Columbia,
Canada, V7X 1T2. We also have offices in Reno, Nevada, Santiago, Chile and Reykanesbaer, Iceland.
Intercorporate Relationships
The following diagram illustrates the organizational structure of Magma, including all its material
subsidiaries, as at September 28, 2010.
MAGMA ENERGY CORP.
(British Columbia)
100%
100%
MAGMA ENERGY
ITALIA S.R.L.
(Italy)
100%
MAGMA ENERGIA
ARGENTINA S.A.
(Argentina)
100%
MAGMA ENERGY
CHILE LIMITADA
(Chile)
100%
100%
MAGMA ENERGIA
GEOTERMICA S.A.
(Peru)
ISLA VERDE
ENERGIA S.A.
(Nicaragua)
100%
COMPANIA de
ENERGIA
LIMITADA
(Chile)
100%
MAGMA ENERGY
(U.S.) CORP.
(Nevada)
MAGMA ENERGY
SWEDEN A.B.
(Sweden)
100%
MAGMA ENERGY
ICELAND EHF.
(Iceland)
98.53%
Properties
MAGMA ENERGY
SERVICIOS LTDA.
(Chile)
100%
Sabancaya;
Huaynaputina; Tiscani;
Ccollo; Casiri; Crucero; San
Pedro
Properties
Svartsengi; Reykjanes;
Eldvörp; Krýsuvík;
Trölladyngja
HS ORKA HF
(Iceland)
100%
Properties
Properties
Tuzgle-Tocomar
Coranzuli
SODA LAKE
HOLDINGS I
LLC
(Delaware)
Properties
Mariposa
McCoy; Desert Queen; Panther Canyon; Thermo
Hot Springs; Baltazor Hot Springs; Beowawe;
Buffalo Valley; Columbus Marsh; Dixie Valley;
Glass Buttes; Granite Springs; Soda Lake East;
Upsal Hogback
100%
SODA LAKE
HOLDINGS II
LLC
(Delaware)
1%
99%
SODA LAKE
LIMITED
PARTNERSHIP
100%
AMOR IX LLC
(Delaware)
(Nevada)
50%
50%
SODA LAKE
RESOURCES
PARTNERSHIP
(Nevada)
Soda Lake
GENERAL DEVELOPMENT OF THE BUSINESS
The general development of our business since the incorporation of Magma has focused on the
acquisition of the Soda Lake Operation, our interest in HS Orka and our portfolio of advanced and
early-stage exploration properties, the recruitment of our management team and raising equity capital.
We have also conducted an extensive review of historic exploration databases for a number of prospective
geothermal exploration properties, including all of our advanced and early-stage exploration properties,
and initiated exploration programs on our Soda Lake Operation, Desert Queen Property, and our
Mariposa Property.
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Magma was incorporated under the Business Corporations Act (British Columbia) on January 22, 2008.
On February 26, 2008, Magma Energy (U.S.) Corp. (“Magma US”), was incorporated in Nevada, USA.
During February and March 2008, we completed the acquisition of the Tuzgle-Tocomar and Coranzuli
Properties in Argentina for an aggregate purchase price of $17,000. On March 6, 2008, Magma Energia
Argentina S.A. was incorporated in Argentina for the purpose of holding title to the Tuzgle-Tocomar and
Coranzuli Properties.
On April 24, 2008, Magma completed an issuance of its common shares to certain seed shareholders
totalling 110,500,000 common shares at a price of Cdn.$0.001 per common share, for gross proceeds of
Cdn.$110,500. The net proceeds of this common share issuance were used to fund acquisitions and for
general and administrative purposes.
During May and June, 2008, we completed the acquisition of the Carrán and Laguna Del Maule
Properties in Chile for an initial aggregate purchase price of $600,000. The acquisition was funded
through a loan from a director in the amount of Cdn.$545,895. On June 12, 2008, Magma Energy Chile
Limitada was incorporated in Chile. The following day, Compania de Energia Limitada was incorporated
in Chile. These entities were formed for the purpose of holding title and conducting further exploration
activities in Chile.
On June 26, 2008, Magma issued 21,646,667 common shares to private investors at a price of Cdn.$0.60
per common share, for gross proceeds of Cdn.$12,988,000. The net proceeds from this common share
issuance were principally used to conduct due diligence on potential property acquisitions and to acquire
U.S. Bureau of Land Management (“BLM”) leases at auction.
On August 5, 2008, we acquired leases in Nevada comprising the McCoy, Panther Canyon, Beowawe,
Columbus Marsh and Quartz Mountain Properties, and a portion of the Desert Queen Property, at an
auction conducted by the BLM for an aggregate purchase price of $10,171,345.
After applying for concessions comprising the Sabancaya, Huaynaputina, Tiscani, Ccollo and Casiri
Properties in Peru, on August 20, 2008, Energia Geotermica S.A. was formed for the purpose of holding
title to these properties. The Peruvian concessions were purchased for a total price of $57,000.
On August 25, 2008, we acquired the Thermo Hot Springs Property in Utah from a private leaseholder
for $528,237.
On September 29, 2008, Magma issued 5,000,000 special warrants (the “Special Warrants”) to private
investors pursuant to a brokered private placement at a price of Cdn.$2.00 per Special Warrant (subject to
adjustment), for gross proceeds of Cdn.$10,000,000. The Special Warrants were adjusted and converted
into common shares on February 23, 2009 (see below). The net proceeds from the Special Warrant
issuance were used for the acquisition of the Soda Lake Operation.
On October 1, 2008, we acquired an additional lease at the Desert Queen Property from an independent
operator for $164,000.
On October 3, 2008, we acquired the Soda Lake Operation from Constellation Energy Group, Inc.
(“Constellation”) and Harbert Management Corporation for $17,557,906. In connection with this
acquisition, we acquired the membership interests in Soda Lake Holdings I, LLC, thereby indirectly
acquiring the membership interests in Amor IX, LLC (“Amor IX”) and the partnership interests in Soda
Lake Limited Partnership (“SLLP”) and Soda Lake Resource Partnership (“SLRP”). Amor IX is the
operator of the Soda Lake Operation. SLLP is the owner of the plant and production assets at the Soda
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Lake Operation and SLRP is the owner of the resource for the Soda Lake Operation. Soda Lake Holdings
I, LLC is a wholly owned subsidiary of Magma US and Soda Lake Holdings II, LLC is wholly owned by
Soda Lake Holdings I, LLC. See “Overview of Our Operations and Properties – Soda Lake Operation”.
On December 16, 2008, we acquired the Glass Buttes Property in Oregon at a BLM geothermal lease sale
for $77,014.
On January 1, 2009, we acquired additional leases at the Desert Queen Property from various private
landowners. Under this agreement, Magma US will make annual lease payments based on the total
acreage leased.
On January 15, 2009, Magma issued a total of 23,145,000 common shares in a non-brokered private
placement at a price of Cdn.$1.25 per common share, for gross proceeds of Cdn.$28,931,250. In this
private placement, 8,000,000 common shares were issued to AltaGas Ltd. (“AltaGas”) and the remainder
of the common shares were issued to private investors as well as to certain of our directors and officers.
In connection with its purchase of common shares, AltaGas was granted a right of first offer for a period
of three years following the closing of the private placement to participate as a co-investor, if a coinvestor is sought by us for any direct geothermal interest held by us in North America, provided AltaGas
maintains its ownership of the purchased common shares.
On January 26, 2009, we entered into an agreement to acquire additional federal leases near the Soda
Lake Operation from Sierra Geothermal Power Inc. and Western Geothermal Partner LLC for $184,842.
On February 23, 2009, we amended the terms of the Special Warrant indenture entered into in connection
with the September 29, 2008 private placement of Special Warrants to allow for the early exercise of the
Special Warrants at an exchange ratio equal to 1.6 common shares for each Special Warrant. On that
date, the Special Warrants were exercised in exchange for the issuance of a total of 8,000,000 common
shares.
On April 28, 2009, we acquired additional leases at the Desert Queen Property from the Gabrych Family
Trust. Under this agreement, Magma US will make an annual lease payment based on the total
acreage leased.
On June 19, 2009, Magma Energy Servicios Limitada was incorporated in Santiago, Chile.
On July 7, 2009, Magma completed its initial public offering and commenced trading on the Toronto
Stock Exchange (“TSX”) by issuing 66,667,000 common shares at a price of Cdn.$1.50 per common
share for aggregate gross proceeds of Cdn.$100,000,500.
On July 14, 2009, Magma acquired 17 additional leases for a purchase price of $2,559,227. These
acquisitions added 67,949.65 acres to our Nevada BLM leaseholds. The effective date of the leases is
August 1, 2009.
On July 20, 2009, Magma issued 6,933,334 common shares at a price of Cdn.$1.50 per common share for
aggregate gross proceeds of Cdn.$10,400,001 pursuant to a partial exercise of the over-allotment option
granted to the underwriters in connection with Magma’s initial public offering.
On July 25, 2009, upon review of exploration work conducted to date on Magma’s Carrán Property in
Chile, the leases associated with the Carrán Property were allowed to lapse.
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On October 22, 2009, Magma issued 11,652,639 common shares pursuant to a private placement at a
price of Cdn.$1.85 per common share for aggregate gross proceeds of approximately Cdn.$21.56 million
and net proceeds of Cdn.$20.78 million. Magma’s CEO, Ross Beaty purchased 25% of the common
shares issued pursuant to the private placement offering.
On November 17, 2009, Magma completed an acquisition of 8.62% of shares of HS Orka from Geysir
Green Energy ehf (“Geysir Green”) for 2.5 billion ISK (approximately $17 million).(1)
On December 14, 2009, Magma completed an acquisition of 32.32% of shares of HS Orka from Reyjavik
Energy and two other HS Orka shareholders for 3.7 billion ISK (approximately $29.8 million)(1) and by
issuing three bonds totalling approximately $70 million payable on December 14, 2016 with an interest
rate of 1.52% per annum. Combined with its previous holding of HS Orka, Magma then held a 40.94%
direct interest in HS Orka.
On January 20, 2010, Magma was awarded the 100,000 hectare Pellado property, 300 kilometres south of
Santiago, by the Government of Chile. Pellado adjoins the Laguna Del Maule Property.
On March 31, 2010, Magma completed an acquisition of an additional 2.25% of HS Orka from Geysir
Green and subscribed for newly issued shares of HS Orka from treasury for a total acquisition cost of
approximately $13 million. Combined with its previous holding of HS Orka, Magma then held a 43.19%
direct interest in HS Orka.
On May 5, 2010, Magma was awarded a 24 square kilometre exploitation permit on the Laguna del
Maule Property in Chile. This permit will allow a geothermal operation of up to 50 megawatts (“MW”)
to be developed within the permit area. The Laguna del Maule Property adjoins the Pellado Property, and
together these properties encompass the Mariposa Property.
On May 11, 2010, Magma completed the acquisition of an additional 2.99% of HS Orka from Geysir
Green for 625 million ISK ($4.9 million).(1) Combined with its previous holding of HS Orka, Magma
then held a 46.18% direct interest in HS Orka.
On May 11, 2010, Magma acquired two additional leases covering an area of 1,022.9 hectares at the
Desert Queen Property from the BLM, and 2,084.7 additional hectares were also acquired in the area of
the Granite Springs Property.
On May 17, 2010, Magma announced that it had entered into a share purchase agreement with Geysir
Green to acquire the remainder of Geysir Green’s interest in HS Orka for 10.56 billion ISK
(approximately $84.5 million) and by Magma assuming a bond issued by Geysir Green to the
Municipality of Reykjanesbær with a face value of 6.3 billion ISK (approximately $50.5 million) (the
“Municipal Bond”). Completion of the acquisition (the “Final Acquisition”) will result in Magma’s
direct interest in HS Orka increasing to 98.53%.
In June 2010, HS Orka took possession of a 50 MW Fuji Electric turbine generator for its Reykjanes
power plant which currently produces 100 MW from twin Fuji units. HS Orka plans to undertake
programs to expand the Reykjanes plant’s output to 180 MW in two phases pending permitting and new
PPAs with one or more power purchasers.
To proceed with the expansion of the Reykjanes plant, HS Orka has applied for and will require an
expansion to its operating permit from the National Energy Authority (“Orkustofnun”). Orkustofnun
has indicated that it is waiting for the results from well R-29 and further details on HS Orka’s reinjection
strategy prior to granting the permit.
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On July 5, 2010, the Company entered into a credit agreement (the “2010 Credit Agreement”) with Ross
Beaty, the Company’s Chairman and Chief Executive Officer, pursuant to which the Company is able to
borrow up to Cdn.$10,000,000 to pay amounts coming due by the Company to Geysir Green respecting
the Final Acquisition of shares of HS Orka, and to fund general working capital requirements. All funds
advanced under the 2010 Credit Agreement are repayable on the earlier of twelve months from the date of
the initial advance, a change of control of the Company or on a default by the Company. Interest at the
rate of 8% per annum, compounded daily, is payable monthly commencing on July 30, 2010. In addition,
a standby fee in the amount of 1% of the credit facility and a drawdown fee in the amount of 1.5% of the
amount advanced is payable in cash. As of the date of this Annual Information Form the full principal
amount of the credit facility has been advanced to the Company to be used in connection with the Final
Acquisition of shares of HS Orka.
On July 27, 2010, Magma closed a public offering by issuing 40,334,628 common shares at a price of
Cdn.$1.12 per common share, including 4,620,342 common shares issued upon partial exercise of the
underwriters’ over-allotment option, for aggregate gross proceeds of Cdn.$45,174,783 and total proceeds,
net of underwriting fees, of Cdn.$43,305,629.
On August 17, 2010, Magma’s wholly-owned subsidiary, Magma Sweden, closed a portion of the Final
Acquisition by acquiring 38.03% of HS Orka’s outstanding shares from Geysir Green for payment of
3,871,195,513 ISK ($32.5 million)(1) and the issuance of 24,808,569 subscription receipts of Magma on
August 17, 2010 and a subsequent payment on November 30, 2010 of 3,062,612,586 ISK (approximately
$25.6 million) subject to certain adjustments. Each subscription receipt will convert into one common
share of Magma on December 18, 2010 for payment of no additional consideration. Magma has the right
at its sole option to repurchase the subscription receipts, in whole or in part, at prices ranging from 135.90
ISK to 142.24 ISK per subscription receipt at certain times between September 4, and December 11,
2010. The maximum aggregate cost to repurchase all of the subscription receipts will be approximately
$29.5 million. Following completion of this portion of the Final Acquisition, Magma Sweden held an
84.21% interest in HS Orka.
On September 3, 2010, Magma’s wholly-owned subsidiary, Magma Sweden closed the final portion of
the Final Acquisition by acquiring Geysir Green’s remaining interest in HS Orka representing 14.32% of
the outstanding shares by assuming the Municipal Bond. The Company now holds 98.53% of the
outstanding shares of HS Orka.
_______________________
Note:
(1)
United States dollar conversion is based upon the exchange rates quoted by the Bank of Canada as of the date of the
acquisition.
DESCRIPTION OF THE BUSINESS
General
We are a geothermal power company and are actively engaged in operating, developing, exploring and
acquiring geothermal energy projects. We currently own two power generation plants (the Svartsengi and
Reykjanes Geothermal Plants) and three exploration properties (the Eldvörp, Krýsuvík and Trölladyngja
Properties) in Iceland through our 98.53% interest in HS Orka. In addition, we currently own one power
generation plant in Nevada (the Soda Lake Operation), five advanced-stage exploration properties
(the McCoy, Panther Canyon and Desert Queen Properties in Nevada, the Thermo Hot Springs Property
in Utah and the Mariposa Property in Chile) and eighteen early-stage exploration properties located in
Nevada, Oregon, Argentina and Peru. Each of these projects is described in detail below. Our head
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office is located in Vancouver, British Columbia, Canada. We also have offices in Reno, Nevada,
Santiago, Chile and Reykjanesbær, Iceland. In total and including HS Orka, we have 135 officers and
employees.
We currently have two distinct business segments: the production and sale of geothermal power and the
exploration of geothermal properties. All revenue and production was generated by our Soda Lake
Operation in Nevada and one customer accounted for 100% of revenues. Revenue for the years ended
June 30, 2009 and June 30, 2010 was as follows:
Year Ended
Energy Sales
Portfolio Energy
Credit Sales
Total Revenue
June 30, 2009
$3,963,167
521,963
$4,485,130
June 30, 2010
$5,055,751
nil
$5,055,751
We will continue to investigate, evaluate and, where appropriate, acquire additional exploration and
development properties.
Developments related to our acquisition of HS Orka
Subsequent to June 30, 2010, Magma’s wholly-owned subsidiary, Magma Sweden closed the Final
Acquisition by acquiring Geysir Green’s remaining interest in HS Orka. The Company now holds
98.53% of the outstanding shares of HS Orka. HS Orka accounts for the vast majority of Magma’s
current production of geothermal power and, accordingly, the performance of HS Orka has a significant
impact on our financial results.
HS Orka produces 175 MW of power from two operating plants located in the Reykjanes peninsula of
Iceland. Both operations are connected to the Icelandic transmission grid with a 132 kilovolt (“kV”)
transmission line. HS Orka has three PPAs: one with Landsvirkjun that terminates at the end of 2019 and
two with Nordural, an operator of aluminum smelters in Iceland, that terminate in October, 2011 and
June, 2026. A majority of the electricity demand in Iceland comes from the aluminum industry. In 2009,
73% of Iceland’s total electricity consumption went to aluminum smelters and 6% was consumed by
other heavy industries.
Economic Dependence
Approximately 46% of current revenue for HS Orka is derived from energy prices linked to aluminum
market prices. Therefore, HS Orka’s financial results and in turn Magma’s financial results are dependent
on aluminum prices. In addition, HS Orka sells approximately 50% of its power to Nordural and the
balance to the retail market. As such, much of HS Orka’s revenue is dependent on one customer.
The Soda Lake Operation sells all of its current electricity output to NV Energy Company (“NV
Energy”) under two 30-year PPAs that terminate in 2018 and 2020. We have commenced discussions
with NV Energy and one other party to negotiate an improvement in the pricing under the current PPAs
and for the planned increase in electricity output from the on-going expansion at the Soda Lake
Operation. There is no guarantee that these negotiations will prove successful. However, given our plans
to expand and increase the output of the Soda Lake Operation, we are optimistic that a successful renegotiation of the existing agreements and/or a new agreement on more favourable terms may be
achieved.
-8-
Competitive Conditions
The geothermal development industry is intensely competitive. The Company competes with many
companies possessing similar or greater financial and technical resources for the acquisition of early-stage
development properties and for access to the capital required to develop those properties. In addition to
competition for exploration properties and activities, the Company competes for capital to develop its
operating assets.
The Company’s competitive position is maintained by its access to capital and its focus solely on
geothermal assets. The Company has since its inception focussed on the acquisition and development of
geothermal assets. In addition, the Company is focussed on development of assets through exploration
and has assembled a strong technical team to locate and explore new properties.
Environmental Protection
The Company’s operations are subject to environmental regulation in the various jurisdictions in which it
operates. To the best of management’s knowledge, the Company’s activities were, and continue to be, in
compliance in all material respects with such environmental regulations applicable to its operations,
development and exploration activities. The Company accepts its corporate responsibility to practice
environmental protection and provide a safe and healthy workplace for its employees, and commits to
comply with all relevant industry standards, environmental legislation and regulations in the countries
where it carries on business.
Overview of our Operations and Properties
The following provides a brief overview of our operations and properties.
Property Type
Area
(Ha)
Potential
Megawatt
Capacity P90(1)(2)
(MW)
Svartsengi
Production
175
n/a
75 / 0(3)
Currently producing 75
MW and 150 MW of
thermal heat
Reykjanes
Production
340
n/a
100 / 80-100
Currently producing 100
MW with expansion
planned to 180 MW
Eldvörp
Advanced
Exploration
1,007
n/a
0 / 50
Under Development
Krýsuvík
Advanced
Exploration
29,500
n/a
0 / 500
Under Development
Trölladyngja
Advanced
Exploration
3,161
n/a
0 / 150(4)
Under Development
34,183
n/a
Property and Location
Reserves/ Resources
(MW)
Status
Iceland – HS Orka
Total ...............................
-9-
175 / 630-650
Property Type
Area
(Ha)
Potential
Megawatt
Capacity P90(1)(2)
(MW)
Reserves/ Resources
(MW)
Status
United States
14.2 (net)/ 28.5 (net)(5) Currently producing at
11 MW net annually;
Near-term expansion
program to 16 MW net
annually; Extension of
30-year PPAs being
negotiated
Soda Lake
Nevada
Production
2,881
n/a
McCoy
Nevada
Advanced
Exploration
4,621
80
n/a
Extensive exploration,
52 temperature gradient
holes and three slim
holes (late 1970s to early
1980s)
Panther Canyon
Nevada
Advanced
Exploration
4,515
34
n/a
Extensive exploration
and heat flow holes
(1975-76);
holes (late 1970s to early
1980s)
Desert Queen
Nevada
Advanced
Exploration
4,672
36
n/a
Extensive exploration,
holes, one stratigraphic
hole (1973-76); shallow
temperature probe
survey (2007)
Thermo Hot Springs
Utah
Advanced
Exploration
706
20
n/a
Extensive exploration
and 2,050 metre well
(1980s); 21 temperature
gradient holes (late
1970s to early 1980s)
Baltazor Hot Springs,
Beowawe, Buffalo
Valley, Columbus
Marsh, Dixie Valley,
Granite Springs, Soda
Lake East, Upsal
Hogback
Nevada
Early-Stage
Exploration
25,085
n/a
n/a
Under Development –
Exploration Activity
varies
Glass Buttes
Oregon
Early-Stage
Exploration
3,607
n/a
n/a
Mapping, temperature
gradient holes, resistivity
survey and soil-mercury
survey (1974 to early
1980s)
46,087
170
Total ...............................
- 10 -
14.2(net) / 28.5(net)
Property Type
Area
(Ha)
Potential
Megawatt
Capacity P90(1)(2)
(MW)
Reserves/ Resources
(MW)
Status
South America
Mariposa
Chile
Advanced
Exploration
104,000
n/a
0 / 320(6)
Tuzgle – Tocomar,
Coranzuli
Argentina
Early-Stage
Exploration
39,057
n/a
n/a
Geophysics,
hydrochemistry and
short holes drilled
(1970s to mid 1980s)
Sabancaya,
Huaynaputina, Tiscani,
Ccollo, Casiri, Crucero,
San Pedro
Peru
Early-Stage
Exploration
7,900
n/a
n/a
Preliminary exploration
work conducted to date
150,957
n/a
0 / 320
Total ...............................
Geophysics,
Magnetotelluric (“MT”)
Survey completed, slim
hole drilling underway
Notes:
(1)
Geothermal resources and probabilistic estimates of MW capacity have a great amount of uncertainty as to their
existence and as to whether they can be accessed in an economically viable manner. It cannot be assumed that all of, or
any part of, a geothermal resource will be commercially extracted or that estimates of MW capacity will be achieved.
(2)
Potential MW capacity estimates have been prepared using the volumetric estimation method developed by the U.S.
Geological Survey (“USGS”) and modified to account for uncertainties in some input parameters. For a description of
this methodology see “Overview of Volumetric Resource Estimate Methodology”.
(3)
The Reserves and Resources estimates for the HS Orka Properties are reported in accordance with the Australian Code.
Reserves and Resources estimates for geothermal properties are not prepared in accordance with NI 43-101.
(4)
The Trölladyngja resource estimate is contained within the Krýsuvík resource estimate.
(5)
Assuming 12% recovery factor, 8% conversion efficiency and a 30-year project life. The Reserves and Resources
estimates for the Soda Lake Operation are reported in accordance with the Canadian Code. Reserves and Resources
estimates for geothermal properties are not prepared in accordance with NI 43-101.
(6)
The Reserves and Resources estimates for the Mariposa Property are reported in accordance with the Canadian Code.
Reserves and Resources estimates for geothermal properties are not prepared in accordance with NI 43-101.
I.
Iceland
HS Orka Properties
The following is a description of the HS Orka Properties. Certain statements in the following summary of
HS Orka’s geothermal resources and properties are based on and, in some cases, extracted directly from
the HS Orka Report prepared on behalf of Magma by Mannvit hf who is independent from the Company.
See “Scientific and Technical Information”. Reference should be made to the full text of the HS Orka
Report which is available for review on SEDAR located at www.sedar.com.
As a result of Magma’s completed and proposed acquisitions of shares of HS Orka, Magma has obtained
an indirect interest in all of HS Orka’s geothermal resources and properties. HS Orka’s geothermal power
- 11 -
plants (Svartsengi and Reykjanes) and its exploration properties (Eldvörp, Krýsuvík and Trölladyngja) are
all located on the Reykjanes peninsula, southwest of Reykjavík, the capital of Iceland.
Property Description and Location
The head office of HS Orka is located in Reykjanesbær town (14,000 inhabitants) approximately five
kilometres from the Keflavík International airport and 45 kilometres from downtown Reykjavík. No
other energy company or geothermal developer has any stake or interest in close proximity to HS Orka’s
properties. The nearest is the Hellisheiði power plant, owned by Reykjavík Energy, in the Hengill
volcanic centre which is approximately 50 kilometres away.
Accessibility, Climate, Local Resources, Infrastructure and Physiography
The climate of the Reykjanes peninsula is characterized by warm winters and cool summers. The annual
average temperature is about 5 degrees Celsius (“°C”). During winter the average temperature is about
0°C and 10°C during summer. The annual average rainfall is approximately 1,100 millimetres per year in
the lowlands but in the range of 1,500 to 2,000 millimetres per year in the mountainous areas. All
rainwater percolates into the bedrock through fractures and the porous lava flows. No rivers are found in
the Reykjanes peninsula but fresh groundwater is found in abundance.
The lowland of the Reykjanes peninsula does not accumulate much snow during the winter unlike the
mountainous areas where snow accumulation is common. Storms with average wind speeds in the range
of 20 to 30 metres per second can be expected several times throughout the winter, usually carrying salt
spray from the ocean. The climate is very similar in all of HS Orka’s properties and development areas.
The areas are generally not impacted by weather, and geothermal exploration and development activities
may typically be conducted throughout the year.
Svartsengi
The Svartsengi property is leased by HS Orka from the Reykjanesbær municipality for 65 years from
2009 and includes exploitation rights. It is comprised of 175 hectares surrounding the geothermal plant
and well field including the injection area two kilometres to the southwest.
The Svartsengi geothermal field is located approximately 20 kilometres southeast from Keflavík airport
and 45 kilometres from downtown Reykjavík. The Svartsengi field is accessible by all weather paved
roads from either Reykjavík or Keflavík airport. The Svartsengi geothermal field is approached from
Reykjanesbær and Reykjavík by “Reykjanesbraut” highway 41 and road 43, due south from highway 41.
The Svartsengi power plant is connected to the Icelandic electrical transmission grid with a 132 kV
transmission line. Cold water is abundant in the Svartsengi field and supplied by shallow groundwater
wells. The Svartsengi geothermal field is located in a relatively flat level terrain at an elevation of 20 to
30 metres above sea level.
The Svartsengi geothermal power plant is a combined heat and power plant. It currently provides 75 MW
of electricity and 150 MW of thermal district heat. The first power plant system was built in 1976 and
has been upgraded in several stages since that time. The power plant has ten turbine/generator units of
various sizes ranging from 1.2 MW to 30 MW.
- 12 -
Reykjanes
The Reykjanes geothermal power plant is located at the southwest tip of the Reykjanes peninsula. HS
Orka owns 340 hectares of land surrounding the Reykjanes power plant and current well field. The
property includes exploitation rights to the geothermal resource.
The Reykjanes geothermal field and power plant is located approximately 20 kilometres south of Keflavík
airport and Reykjanesbær town. The field is accessible by all weather paved roads. From Reykjanesbær
access is along road 44 to the small suburb of Reykjanesbær eight kilometres southwest, named Hafnir
(150 inhabitants), and then continuing 12 kilometres south on road 425. The Reykjanes geothermal
power plant is connected to the Icelandic electrical transmission grid by a 132 kV transmission line.
The Reykjanes geothermal power plant is a steam driven power plant that has a capacity of 100 MW. It
was built in 2006 and has two steam turbine generator units.
The Reykjanes geothermal field is characterized by a lava shield partly covered with sand. The elevation
of the field is approximately 20 metres above sea level. The Stampar historic eruptive fissure and the
associated lava field are prominent to the west of the Reykjanes power plant. A hyaloclastite ridge (lava
representing ineractions with water), approximately 20-40 metres in height, cuts through parts of the
geothermal field in the northeast-southwest direction. A zone with dense northeast-southwest faults is
prominent east of the main well field. The vegetation around the Reykjanes power plant and the well
field is sparse and consists mainly of grass.
Eldvörp
The property containing the Eldvörp geothermal field is 1,007 hectares and is owned by the Icelandic
State. HS Orka has an exclusive exploration and exploitation license in the Eldvörp geothermal field until
2057.
The Eldvörp geothermal field is located approximately five kilometres west southwest from the
Svartsengi plant and is accessed by gravel road from the Svartsengi field.
The area is characterized by rugged postglacial lava fields and the Eldvörp fissure that erupted about
2,500 to 2,100 years ago. The terrain is relatively flat at an elevation of 30-40 metres above sea level.
The vegetation consists mostly of moss covering the lava fields with dwarf shrubs and low herbs found in
depressions in the lava field.
Krýsuvík
The Krýsuvík geothermal area, including the Sandfell and Trölladyngja geothermal field, covers
approximately 29,500 hectares and is mostly owned by the Hafnarfjörður municipality and private land
owners. HS Orka has exclusive exploration license over the complete Krýsuvík geothermal area until
2016.
From either Reykjanesbær or Reykjavík, the Krýsuvík geothermal area is accessed along highway 41,
followed by road 42 southeast past the Kleifarvatn Lake. Road 42 is paved for half of the way from
Hafnarfjörður but in the mountain area the road is gravel. Several dirt roads are in the Krýsuvík area and
some of them require four-wheel drive vehicles. Most parts of the Krýsuvík area can be accessed by dirt
roads from road 427 south of the field. No roads cross the mountain ridges in the area. The dirt roads
will require upgrades in the future in order to accommodate large trucks and major development
- 13 -
activities. No high-voltage transmission lines are directly adjacent to the Krýsuvík field; however, the
closest substation is approximately 20 kilometres away in Hafnarfjörður.
The topography of the Krýsuvík high-temperature geothermal area is characterized by extensive postglacial lavas and steep sided mountains and ridges of pillow lavas, pillow breccias and hyaloclastites
trending approximately northeast-southwest. Two main ridges are in the area and are several kilometres
long, about a kilometre wide and approximately 200 metres high above the surroundings. The elevation
range of the area is about 160 to 400 metres above sea level.
Trölladyngja
In the years 1997 to 2001, HS Orka bought 3,161 hectares in the Trölladyngja geothermal field, but the
majority of the geothermal field is owned by private land owners. HS Orka has an exploration license in
the Trölladyngja geothermal field, as part of the Krýsuvík exclusive exploration license, until 2016.
The Trölladyngja field can be accessed from highway 41 at the intersection with road 420 along a dirt
road approximately ten kilometres south to the geothermal field. The dirt road can accommodate vehicles
and large trucks but will require upgrades in the future for power project development.
The Trölladyngja geothermal field is a sub field of the Krýsuvík geothermal area and has similar
geological characteristics as the Krýsuvík area. The Trölladyngja geothermal field is characterized by
steep ridges trending approximately northeast-southwest with lava fields in between. The elevation of the
area is roughly 160 to 400 metres above sea level.
History
Svartsengi
The first two wells in the Svartsengi geothermal field were drilled in 1971 and 1972 and the first heat
exchange experiments for a district heating system started with a small pilot plant in 1974. In 1976, the
pilot plant started production of hot water, which was enough to heat the town of Grindavík. The first
electrical power plant in Svartsengi was built in 1976 to 1978 and consisted of two 1 MW electrical
backpressure units. It was the first geothermal power plant in the world that used a high-temperature
geothermal system to produce electricity and hot water for consumption and district heating.
Since 1976, the power plant has been upgraded in several stages parallel to extensive geothermal research
and exploration activities in the field through the years. Today, 24 wells have been drilled in the field.
The geothermal reservoir is well understood and the reservoir response to production has been thoroughly
monitored and modeled since the start of production in 1976.
The capacity of the Svartsengi thermal plant is currently 150 MW thermal and installed electrical
generation capacity is 74.4 MW electrical. The power plant consists of ten turbine/generator units,
consisting of: seven 1.2 MW electrical Ormat ORC units; a six MW electrical Fuji Electric back pressure
unit; and two 30 MW electrical Fuji condensing units.
Reykjanes
The first well in the Reykjanes field was drilled in 1956, followed by geothermal research and
exploration. Systematic drilling began in 1968 and two years later seven wells had been drilled. Most of
the wells were shallow but three wells were deeper than 1,000 metres and well RN-8, the deepest, was
1,754 metres in depth. Well RN-8 was utilized until 1983 when well RN-9 was drilled and replaced well
- 14 -
RN-8 as the main production well in the field. The wells were used in a salt-processing plant that
operated for years at Reykjanes. All the above mentioned wells have been abandoned.
HS Orka started investigations for power production in 1998 when well RN-10 was drilled. The
Reykjanes power plant was designed according to findings from well RN-10. In the years 2002 to 2006,
wells RN-11 to RN-24 were drilled to supply high-pressure steam for the Reykjanes power plant. Two
50 MW electrical turbine/generation units were procured from Fuji Electric in 2004 and the Reykjanes
power plant started commercial operation in May 2006 with an installed capacity of 100 MW electrical.
Today, a total of 29 wells have been drilled in the Reykjanes geothermal field. Substantial research and
exploration data has been collected during the research history of Reykjanes, spanning over 40 years,
especially in the last seven years with high drilling activity.
Eldvörp
The Eldvörp high-temperature geothermal field is located in the western part of the Reykjanes peninsula,
approximately five to six kilometres west southwest from Svartsengi and approximately 11 kilometres
northeast from the Reykjanes geothermal field. Eldvörp is located within the Reykjanes fissure swarm as
both the Reykjanes and Svartsengi geothermal field. The Eldvörp geothermal field has been studied to
some extent and has been included in several surveys as part of investigations of the Svartsengi
geothermal field since the 1980’s.
One exploration well exists in the field, well EV-02, which was drilled down to 1,265 metres depth in
1982. Several reports are available on the geothermal field, which describe the geology, field
characteristics, fluid chemistry and production characteristics of the exploration well. Temperature and
pressure has been measured in well EV-02 systematically since 1983 as part of the monitoring program of
the Svartsengi geothermal field. Monitoring data and exploration results show that the Eldvörp and
Svartsengi geothermal fields are two parts of the same geothermal resource. HS Orka has exploration
rights in Eldvörp and plans to develop the geothermal field to the point of power production.
Krýsuvík
The Krýsuvík high-temperature geothermal area is located in the Reykjanes peninsula and belongs to the
Krýsuvík volcanic centre and the associated fissure swarm. It is considered to cover approximately
80 square kilometres. The Krýsuvík geothermal area is divided into three sub-geothermal fields named
Krýsuvík, Trölladyngja and Sandfell. The area has been known for a long time to be geothermally active
and geothermal investigations have dated back to 1756. The Krýsuvík geothermal area was considered as
the fourth-largest accessible geothermal field of approximately 30 fields in the National Assessment of
Geothermal Resources of Iceland in 1985.
Systematic exploration started in the 1940’s with the drilling of 20 shallow wells at depths of
approximately 200 metres. In 1960, three deeper exploration wells were drilled and the deepest one
reached a depth of 1,275 metres. Systematic exploration efforts were continued in the 1980’s including
wells drilled to depths of approximately 800 to 900 metres, resulting in detailed research reports. From
1997 to 2001, resistivity campaigns were conducted to outline the extent of the geothermal resource.
Despite the long research history, more exploration is needed to improve the understanding of the
geothermal resource. HS Orka has exclusive exploration rights in the Krýsuvík geothermal area and plans
to drill three deep (>2,000 metres) exploration wells as the next steps in the development of the field with
the final aim of geothermal power production.
- 15 -
Trölladyngja
The Trölladyngja geothermal field is a sub-field in the northern part of the Krýsuvík geothermal area.
Several research and exploration studies have been conducted in the Trölladyngja field since the 1960s as
part of the studies for the Krýsuvík geothermal area. These studies included detailed geological mapping,
geophysical and geochemical surveys and drilling of two exploration wells in 1971 and 1972 to depths of
843 and 931 metres, respectively.
Geological Setting
Iceland lies on the Mid-Atlantic ridge, the boundary between the North American and Eurasian tectonic
plates. More than 200 volcanoes are located within the active volcanic zone running through the country
from the southwest to the northeast. Earthquakes are frequent but rarely cause serious damage. In this
volcanic zone there are at least 30 high-temperature geothermal areas containing steam fields with
underground temperatures reaching above 200°C within 1,000 metres depth. The geothermal areas are
directly linked to the active volcanic systems. Approximately 250 separate low-temperature areas with
temperatures below 150°C in the uppermost 1,000 metres in the crust are mostly in the areas flanking the
active zone.
The Icelandic basaltic plateau was formed as the result of a mantle plume and the constructive margin of
the sea floor spreading (rift zone) between the North American plate and the Eurasian plate which spreads
two centimetres per year. The existence of the mantle plume leads to the dynamic uplift of the Icelandic
plateau and increased volcanic activity in the rift zone between the two plates. The high-temperature
areas in Iceland are only found within the area of active volcanism within the rift zone characterized by
central volcanoes or volcanic complexes and associated fissure swarms.
The sub-marine Mid-Atlantic Ridge connects to the rift zone of Iceland on the southwest tip of the
Reykjanes peninsula. The Reykjanes, Eldvörp and Svartsengi geothermal fields are all located within the
Reykjanes fissure swarm while the Krýsuvík geothermal area is related to the Krýsuvík fissure swarm.
The fissure swarms are directed approximately in southwest-northeast direction which is the main
direction of active faults and fractures which govern the direction of subsurface fluid flows.
Svartsengi
The Svartsengi geothermal field is one of the three high-temperature geothermal fields located in the rift
zone on the western part of the Reykjanes peninsula. The geothermal field is liquid dominated with
temperature in the range of 235 to 240°C with natural steam zone found in the eastern part of the
geothermal field. The produced fluid is approximately two-thirds seawater and one-third freshwater in
composition.
The stratigraphy of the field consists of shallow groundwater zone in a basaltic formation, 300 metres in
thickness. That is followed by a 300 metres thick hyaloclastite series that forms the caprock of the
geothermal reservoir. Below the caprock are series of flood basalts and at 1,000 to 1,300 metres depth
intrusions become dominant. Fractures related to the fissure swarm across the reservoir in the eastern part
of the well field.
Reykjanes
The Reykjanes geothermal system is located at the southwest tip of the Reykjanes peninsula, where the
sub-marine Reykjanes Ridge connects to the volcanic rift zone of Iceland. The Reykjanes geothermal
system belongs to the Reykjanes fissure swarm. The geothermal system is a liquid dominated high-
- 16 -
temperature geothermal system with sea water as the reservoir fluid. The highest temperature in the
system has been measured approximately 320°C, but the dominate reservoir temperature is around 295°C.
The stratigraphy of the Reykjanes geothermal field can be divided into four main units. The uppermost
120 metres consist of a few sub-area lava flows, underlain by a formation of pillow basalt. Below this
unit is a series dominated by hyaloclastite tuff formations. Below 470 metres and down to 970 metres are
tuff formations with pillow basalts. Below 970 metres depth, the majority of the rocks are crystalline
basalts. The pertinent surface geological features are lava shields and the historic Stampar fissure, which
erupted in 1226. Volcanic eruptions in Stampar are expected to occur every 1,000 years or so. The
Reykjanes field is situated within the Reykjanes fissure swarm and therefore contains dense northeastsouthwest fissure and fault zones.
Eldvörp
The Eldvörp high-temperature geothermal field is located in the western part of the Reykjanes peninsula,
approximately five kilometres west southwest from Svartsengi and about 11 kilometres northeast from the
Reykjanes geothermal field. The area is characterized by rugged postglacial lava fields and the Eldvörp
fissure that erupted about 2,500 to 2,100 years ago.
The Eldvörp geothermal reservoir is a liquid dominated high-temperature geothermal system with a steam
zone from surface down to approximately 800 metres depth. The reservoir temperature in Eldvörp is
about 270°C. The chemistry of the reservoir fluid in Eldvörp is approximately two-thirds seawater and
one-third fresh water.
Krýsuvík
The Krýsuvík high-temperature geothermal area is located in the centre of the Reykjanes peninsula and
belongs to the Krýsuvík volcanic centre with the associated fissure swarm. The Krýsuvík geothermal area
is sub-divided into three geothermal fields: Krýsuvík, Sandfell and Trölladyngja and all belong to the
same volcanic system and fissure swarm.
The area is characterized by an extensive post-glacial lava fields, steep-sided mountains and ridges of
pillow lavas, pillow breccias, and hyaloclastites. The latter formations are of upper Quaternary age, in all
likelihood from the last glaciations, formed during volcanic eruptions in melt water chambers within the
glacial ice sheets. All the rocks are of basaltic composition. The area shows high intensity of geothermal
activity, presented in several mud pits, many fumaroles and hot springs. Topographically, the Krýsuvík
area is characterized by two major northeast-southwest striking hyaloclastites ridges.
Trölladyngja
The Trölladyngja geothermal field is a sub geothermal field of the greater Krýsuvík geothermal area, so
the geological setting is similar to the Krýsuvík geothermal area. The most significant geological features
of the area are the northeast-southwest trending hyaloclastite ridges reaching approximately 300 to
400 metres above sea level. The dominant rock units in the Trölladyngja are hyaloclastit tuff and
breccias, and quaternary lava flows that cover the areas between the ridges.
- 17 -
Geothermal Exploration
Svartsengi
Geothermal investigations started in 1969, so the Svartsengi geothermal field has been studied for
40 years. Extensive research activities and exploration campaigns have been conducted through the
years. The exploration history includes: geological and tectonic mapping; geochemistry analysis;
resistivity explorations; gravity surveys and elevation surveys; Interferometric Synthetic Aperture Radar
(“InSAR”) for remote sensing using radar satellite images; tracer testing; numerical modeling; and
drilling of numerous wells.
To date, 24 wells have been drilled in the field. Eight wells produce from the liquid dominated part of the
reservoir, while five wells produce dry steam from the steam cap. Two reinjection wells (SV-17 and SV24) have been drilled in the reinjection location in the Svartsengi field, which is located 2.5 to
3.0 kilometres southwest of the production field. The average depth of the wells in use in the Svartsengi
field is approximately 1,200 metres.
Reykjanes
Systematic exploration in the Reykjanes field started in the late sixties and several studies have been
made on the geological and hydrothermal alteration. Fluid inclusions have been studied and several
resistivity campaigns have been carried out. Substantial data has been collected during the research
history of Reykjanes spanning over 40 years, especially in the last seven years with high drilling activity.
The data collected should be sufficient to obtain quite good knowledge on the geological structure of the
geothermal system. Much of the data is in the drilling and completion reports as well as well testing
reports. The data has, however, not been compiled in an overview report that reflects the findings since
2002.
The first well in the Reykjanes field was drilled in 1956 followed by geothermal research and exploration.
Systematic drilling began in 1968 and two years later seven wells had been drilled. Most of the wells
were shallow, but three wells were deeper than 1,000 metres and well RN-8, the deepest, was
1,754 metres in depth. Well RN-8 was utilized until 1983 when well RN-9 was drilled and replaced well
RN-8 as the main production well in the field. The wells were used in a salt-processing plant that
operated for years at Reykjanes. All the wells mentioned above have been abandoned.
Investigations for power production started in 1998 when well RN-10 was drilled. In the years 2002 to
2006, wells RN-11 to RN-24 were drilled to supply high-pressure steam for the Reykjanes power plant.
Today, a total of 29 wells have been drilled in the Reykjanes geothermal field. The average measured
depth of all the wells in use in the Reykjanes field is approximately 2,200 metres and three directionally
drilled wells have been drilled to depths in excess of 3,000 metres (measured depth, not true vertical
depth).
The fluid flow in the Reykjanes geothermal field is dominated by the Reykjanes fissure swarm and fault
zones with northeast-southwest direction. A fault zone trended approximately northwest-southeast has
also been suggested by analyzing loss zone in wells temperature distributions. The up-flow zone is
believed to be along the northeast-southwest and northwest-southeast faults and the centre of the
geothermal system is at their cross section. The two faults and the centre of the geothermal system and
the volume below the geothermal surface manifestation has been the main drilling target in the reservoir.
The main feed-zones in the Reykjanes field are found on two depth intervals: 800 – 1,200 metres; and
1,900 – 2,300 metres depths.
- 18 -
Transient Electromagnetic (“TEM”) resistivity measurements were done in 2005 in the Reykjanes field.
The resistivity measurements show that the main up-flow zone is narrow, like a chimney, with natural
horizontal run off from the centre. Low resistivity (indicating temperature above 240°C) is found at 800
– 1,000 metres depth in area of approximately 11 square kilometres.
MT measurements were done in 2008 across the Reykjanes geothermal field. They show the same
location of the up-flow zone as the TEM measurement and support the TEM results of a chimney-like
geothermal system. The MT measurements indicate that the geothermal field has roots deep within the
crust.
The geothermal fluid in the Reykjanes reservoir is seawater and is therefore believed to have a sealing
anhydrite boundary like the Svartsengi reservoir. The chimney-like appearance supports this. The
Reykjanes reservoir has low permeability sedimentary formations at 500 to 800 metres depth that
provides a cap rock to the system. A steam cap started to develop at 800 to 1,200 metres depth in the
reservoir due to the mass extraction during the initial operational months of Reykjanes power plant.
Eldvörp
The Eldvörp geothermal field has been studied to some extent since the 1980’s and has been included in
several surveys as part of investigations of the Svartsengi geothermal field. Geothermal research and
exploration in the Eldvörp geothermal field include detailed geological mapping, several resistivity
exploration campaigns, geochemistry analysis of the reservoir fluid and drilling of one full size
exploration well, EV-02, to a depth of 1,265 metres.
Well EV-02 is drilled through two intrusive dikes in the Eldvörp fissure that were the feeders for the two
eruptions, one occurring approximately 12,000 years ago and the other occurring approximately
2,200 years ago. The active hydrothermal system is closely related to the intrusions as the majority of
feed-zones in the well relate to fractures created by the intrusions.
Results of TEM exploration survey conducted in 1996 and interpretation of older measurements indicate
strongly that Eldvörp and Svartsengi are part of the same geothermal system.
Twelve new TEM measurements were done in the Eldvörp field in 2008 in order to improve the coverage
in the field and obtain a better picture of the outline of the geothermal anomaly in the field. The older
measurements were re-interpreted with the 2008 measurements, resulting in a more detailed portrayal of
the field. The results show that the Eldvörp and Svartsengi fields are connected and are part of the same
geothermal resource.
Two main feed-zones are in well EV-02 at 575 metres and 1,250 metres depths. Well tests show that the
upper feed-zone produces steam due to the pressure drawdown, caused by the mass extraction in
Svartsengi. The average enthalpy of the fluid produced from the well increased from approximately
1,350 kilojoules per kilogram in 1983 to approximately 1,650 kilojoules per kilogram in 1996. The
enthalpy, however, changes with flow rates due to the different flow through the feed-zones at different
well-head pressure. In 1983, the maximum well output was about 170 kilograms per second at 16 bar
well-head pressure, but 110 kilograms per second in 1996 at same well-head pressure. The reason for
declined productivity is the pressure drawdown caused by the mass production in Svartsengi. In 1996,
the well was considered to be able to produce about five kilograms per second of steam in the long run.
Today, the well is considered to be able to produce between 15 and 20 kilograms per second of steam.
There are indications that the well is drilled on the boundary of more permeable formations that feature
higher reservoir temperature. This is supported with geothermometer and fluid chemistry analysis.
- 19 -
During the well tests in 1983 and 1996, the temperature of the inflow was considered about 250°C and
270°C, respectively.
Pressure measurements made in 2008 in well EV-02 show pressure drawdown of about 16 bar due to the
mass extraction in Svartsengi. Eldvörp has responded with increased reservoir pressure because of the
reinjection in well SV-17 in Svartsengi, which is in a distance of about three kilometres. The pressure
history shows obvious pressure interference between the two geothermal fields.
Trölladyngja
Several research and exploration studies have been conducted in the Trölladyngja field since the 1960’s
as part of the studies for the Krýsuvík geothermal area. These studies included detailed geological
mapping, geophysical and geochemical surveys and drilling of two exploration wells in 1971 and 1972 to
depths of 843 and 931 metres.
HS Orka drilled two exploration wells in the Trölladyngja field in 2002 and 2006. The wells penetrated
to depths in the range of approximately 2,200 and 2,300 metres, respectively. Both wells showed high
bottom-hole temperature, in the range of approximately 320 to 340°C. However, temperature reversals
are observed over the 1,000 to 1,500 metre depth interval in both wells, indicating horizontal fluid flow
around the wells. The temperature profiles in both wells show indications of convective cell in the
geothermal system, the wells are therefore, considered to be in some unknown distance to the main upflow or a hydraulically convective fracture zone in the geothermal field. The upper and cooler convective
part is more permeable than the deeper and hotter zone. Both wells are marginal producers and are not
able to sustain constant flow when discharged.
Geothermal Resource and Geothermal Reserve Estimates
In summary, the resource and reserve estimates of the HS Orka properties are as follows:
Property
Reserves
(MW Electrical)
Proven Probable
Svartsengi
75
Reykjanes
100
80-100
Eldvörp
50
Krýsuvík
500
150(1)
Trölladyngja
Total............
Resources
(MW Electrical)
Indicated
Inferred
Reserves = 175
Resources = 630-650
_______________________
Note:
(1)
The Trölladyngja resource estimate is contained within the Krýsuvík
resource estimate.
For further discussion regarding the resource and reserve estimates of each of the HS Orka properties,
please see below.
- 20 -
Svartsengi
Production History
Mass extraction from the Svartsengi geothermal field started in 1976 when the Svartsengi power plant
started operation. The average annual mass production increased to over 200 kilograms per second in
1980 and reinjection tests started in the field in 1983. The net mass extraction peaked in 2000 with
roughly 350 kilograms per second but declined considerably when reinjection became an integral part of
the reservoir management. Since 2003, the annual average net mass extraction has been around
200 kilograms per second. The annual average net mass extraction has decreased since the 1990’s, but
the installed capacity of the plant has increased more than 60 MW electrical.
The total mass production in 2008 was 13.8 million metric tons or 438 kilograms per second on average.
The total reinjection was approximately 6.1 million metric tons, or 193 kilograms per second, on average.
The net mass production is therefore approximately 7.7 million metric tons or 245 kilograms per second,
on average. Substantial and consistent reinjection commenced in 2003 with a reinjection/production ratio
of 32%. It has increased steadily and is now 44% as of 2008. Reinjection has therefore become an
integral part of the reservoir management. This has resulted in decreased net mass extraction from the
geothermal reservoir.
In 2008, the total production from the steam wells was about 2.85 million metric tons, which represents
about 90 kilograms per second, on average. This is about 21% of the total mass production from the
reservoir.
Reservoir Monitoring
Several important reservoir parameters have been continuously monitored during the utilization history of
the Svartsengi field since 1976. These parameters are mass production, water level, reservoir pressure,
well-head pressure, reservoir temperature, fluid chemistry, depth of scaling in production wells, gravity
and elevation.
Production and Reinjection
The total mass flow from each well in Svartsengi is calculated from the well-head pressure and the
opening position of the control valve. The flow characteristics of the production wells in Svartsengi are
known and the flow from each well is calculated by a formula calibrated against the well-head pressure,
the control valve opening and the orifice in the flow line.
Vatnaskil Consulting Engineers (“Vatnaskil”) have been responsible for reviewing the collected data,
calculating the production flow rates and reporting the total production and reinjection data as well as the
water level changes annually, since 1985. Vatnaskil is also responsible for developing and maintaining a
numerical model (the “AQUA model”) to simulate the water level changes in the fields and make
forecasts on future water levels, given future production scenarios. This model has been used to assess
the resource and reserves of the Svartsengi and Eldvörp geothermal fields.
Water Level and Pressure
Well SV-7 is producing from the liquid dominated part of the reservoir and was monitored for 20 years
from 1979 to 1999 when failure in the well-head prevented measurements. Well SV-12 was drilled in
1982 and served as a production well from 1998 to 2000. Since then the well has only been used for
- 21 -
monitoring purposes. The water level and down-hole pressures have been monitored in these wells three
to four times each year (at a depth of 1,000 metres in well SV-7 and a depth of 900 metres in well SV-12).
The rate of pressure drawdown in Svartsengi was the highest, at about 2.5 bar per year in the first years
after the six MW electrical unit was put online in 1980. The drawdown rate leveled off and was about
0.6 bar per year in 1999. The rate of drawdown increased to about two bar per year when the 30 MW
electrical unit was put on line in December 1999. After the reinjection became an integral part of the
reservoir management, in 2002, the drawdown in the Svartsengi field stabilized and the well in Eldvörp
shows indication of pressure recovery. Unit 6 (30 MW electrical) came on line in late 2007. Observed
pressure in well SV-12 in early 2008, shows about a one bar pressure drop, most likely in response to
increased production. However, from mid 2008, the observed pressure recovered about two bar. In 2008,
the second injection well was put into service. That well had total circulation loss at a depth of
approximately 840 metres and may have better connection to the production field than the first well,
resulting in improved pressure recovery in the production field.
The total pressure drawdown in Svartsengi is approximately 30 bar since the start of production in 1976.
Reservoir Temperature
The initial reservoir pressure before the start of production was about 16 bar lower than the surrounding
hydrostatic pressure. This pressure difference, in addition to the 30 bar pressure drawdown due to the
mass extraction, introduces the risk of cooling of the production water due to influx of cold water from
surrounding water reservoirs. Because of this risk factor the temperature in the Svartsengi geothermal
field has been thoroughly monitored since 1980.
The temperature profile in the monitoring wells is usually measured concurrently with pressure and water
level measurements. This is done three to four times each year.
The separation pressure of the Svartsengi plant is about 5.5 bar gauge (6.5 bar absolute), corresponding to
a temperature of 211°C. If the temperature at the well-head declines to 211°C or the well-head pressure
drops to 5.5 bar gauge, the wells will not be able to supply steam to the plant at current operation level.
The following cut-off pressure levels of the steam supply system from the well field for the Svartsengi
power plant have been defined:

ten bar gauge standard operational; and

eight bar gauge minimum preferred.
Steam zone temperatures
The boiling of the water in the steam zone is effectively a heat mining process and natural water recharge
to the boiling zone will eventually cause a decrease in temperature, which will result in lower well-head
pressure and less well output. Even after over 30 years of production from the field, the temperature is
still around 240°C and there are no signs that indicate that the temperature is decreasing in the steam
zone. Therefore it is considered unlikely that the reservoir temperature will decrease below 211°C in the
next few decades, assuming a similar utilization mode and no unexpected geological events.
In 1983 and 1986 the temperature of the produced fluid cooled down suddenly. Some of the wells cooled
down temporarily as much as 12°C. This is believed to be caused by sudden influx of cold water that
resulted in the cooling of the production water and lower well-head pressures. This drop in temperature
- 22 -
recovered in a few weeks time and normal operating temperatures were maintained. These two
incidences are the only know cooling events in the reservoir. The reason for these events is unknown.
Geochemistry and Scaling
Samples from the produced fluid have been collected and the chemical composition of the fluid analyzed
continuously since production started in the Svartsengi field in 1976. Samples are collected four times
per year. These investigations are part of the monitoring system in the field. The purpose is to monitor
chemical changes of the fluid that reflect changes in the reservoir.
In the early years of the power plant operation, calcite scaling used to form in the boiling zone in the
production wells at depths of 400 to 600 metres. The scaling had to be cleaned by drilling approximately
every two years. A drilling method was developed which made it possible to drill out the scaling while
the well was kept flowing and the debris was brought to surface. Due to lowered carbon dioxide content
of the geothermal fluid during the recent years the calcite scaling problem has almost disappeared in the
Svartsengi field.
Land Subsidence Measurements
Elevation and gravity changes have been measured around the Svartsengi, Eldvörp and Reykjanes fields
since the start of production in Svartsengi.
The subsidence rate was highest right after exploitation started (approximately 14 millimetres per year)
and was approximately seven millimetres per year between 1987 and 1992. The subsidence rate
increased again from 1992 to 1999 to about 14 millimetres per year. The subsidence bowl in Svartsengi
has a north northeast-south southwest direction, extending to the Eldvörp geothermal field where the
subsidence rate was four to ten millimetres per year from 1976 to 1999.
By reinjecting the produced fluid back into the reservoir the net mass extraction from the field is reduced.
The reinjection will, therefore, help to mitigate the land subsidence due to mass extraction. Reinjection is
probably the only method available to mitigate this effect.
Land subsidence has not caused any damage to infrastructure, the steam field or the power plant and it is
unlikely to cause any damages in the future.
Reservoir Modeling of Svartsengi
Several methods and models, including the AQUA model, have been developed and used to simulate
water level and pressure changes due to the mass extraction of the Svartsengi geothermal field since the
1980s. The models have then been used to forecast the reservoir response given future production and
reinjection scenarios. The latest models simulate the 30 years of pressure history at Svartsengi with good
confidence. Reservoir models and have been used in the decision making process of HS Orka, and it
predecessors, for successfully expanding the power production capacity of the Svartsengi geothermal
power plant.
Mechanics of the Geothermal Reservoir
Geothermal systems with seawater reservoir fluids have different characteristics than geothermal systems
with reservoir fluid originated as meteoric (fresh) water. The seawater has abundant chemical content
compared to the meteoric water. Silica is the predominant substance in the rock matrix and when the
fluid percolates in the reservoir rocks it dissolves the silica and other minerals and salts. The solubility
- 23 -
increases with increased temperature. Also present in colder seawater are anhydrites, among other
chemicals which form a sealing boundary when recharged into the hot geothermal system. The
precipitation of anhydrates can therefore, create a low permeability sealing boundary in the upper parts of
geothermal reservoirs containing seawater as the geothermal fluid. The caprock and anhydrate sealing
boundary frame ideal conditions for the creation of a steam cap.
The boiling zone separating the one and two phase zones moves upward and downward, depending on the
pressure in the steam cap and the reservoir pressure on the single phase zone deeper in the reservoir.
Increased production from the steam zone results in lower pressure in the two phase zone and the boiling
zone moves upward and the steam zone reduces in size. In contrast, the steam zone expands with
increased production in the deeper wet part and lowers the reservoir pressure. Reinjection into the
reservoir creates pressure support that has the same effect as reduced production from the deeper wet part
of the reservoir. This setup shows that the size of the steam zone can be managed by production from the
one and two phase zones as well as with reinjection.
Production Capacity of the Geothermal Reservoir
In order to investigate whether the current 74 MW electrical production capacity of Svartsengi plant could
be maintained by the geothermal resource, the AQUA model was used to forecast the reservoir pressure
response by using constant current production and reinjection rates for the next 30 years, that is
438 kilograms per second mass production and 44% reinjection.
Modeling results show that the forecasted additional reservoir pressure decline from 2010 to 2040 is
approximately 25 bar. The approximate 30 bar current pressure decline in the reservoir from 1976 to
2009 has resulted in approximately a four bar average well-head pressure decline over the past 33 years.
It is therefore reasonable to assume that the forecasted 25 bar additional pressure decline will also result
in approximately four bar well-head pressure decline. According to this assumption the well-head
pressure should drop from 14 bar in 2009 to about ten bar in 2040, which is within the standard
operational parameters of the Svartsengi power plant, and sufficient to maintain current plant output.
Future Well-Head Pressure
In order to more accurately investigate the impact of future reservoir pressure drawdown on the future
well-head pressure, Vatnaskil performed a simulation study on the subject. The study was based on
calculating, numerically, the two phase flow in a typical production well and simulating the observed
well-head pressure as a function of the observed reservoir pressure. Well SV-8, which is producing from
the deeper wet part of the reservoir, was selected as a representative well.
According to the future forecast the well-head pressure will be eight bar in 2030, which is the minimum
preferred operational pressure. The well-head pressure will stay above seven bar until 2040 which is
higher than the 5.5 bar operational pressure of the power plant. The forecast presented assumes the
current production mode to be constant throughout the forecast time.
- 24 -
Figure 1: Measured, simulated and forecasted well-head pressure in well SV-8 in Svartsengi from 1982-2040 (provided by Vatnaskil).
The future well-head calculations are based on the reservoir response calculated by the AQUA model,
which simulates the pressures in the reservoir. The increased reservoir drawdown will result in further
expansion of the steam cap, which is expected to lead to higher enthalpy of the produced fluid. Higher
enthalpy will call for reduced mass extraction from the reservoir which will result in less reservoir
pressure drawdown than is assumed in the forecast. The well-head pressures in the Svartsengi field are
therefore considered to be higher than the minimum preferred operational pressure of the Svartsengi
power plant through 2040. It is therefore concluded, with confidence, that the Svartsengi reservoir is
expected to be able to supply the power plant for the next 30 years.
Reserve Estimate and Classification
The Svartsengi geothermal resource has been under production since 1976. Numerous wells have been
drilled in the field and the monitoring history is continuous and valid. The geothermal field has been
under investigation and exploration for approximately 40 years, resulting in a comprehensive
understanding of the reservoir and its response to long term mass extraction. A detailed numerical model
of the geothermal reservoir exists, which simulates the production and monitoring history with a high
degree of confidence, resulting in reliable forecasts of the reservoir response to long term utilization since
the start of production 33 years ago. In particular, the AQUA model was used for the resource
classification.
As defined and in accordance with the Australian Code and with fluid temperature of approximately
240°C, the Svartsengi geothermal field is classified as a proven reserve containing recoverable thermal
energy of 75 MW electrical for 30 years, relative to the operational parameters of the Svartsengi
geothermal power plant.
- 25 -
Reykjanes
Production History
The Reykjanes geothermal field has been utilized since 1969. Before the Reykjanes power plant began
operation in May 2006, the annual production was never more than 100 kilograms per second. The mass
production from the field increased more than tenfold with the commissioning of the Reykjanes power
plant.
The power plant design assumed that 800 kilograms per second of fluid at 290°C with enthalpy of
1,290 kilojoules per kilogram were needed to supply the power plant. Because of the creation of the
steam cap in the field, the enthalpy has been increasing with time. The enthalpy was on average about
1,335 kilojoules per kilogram in 2007 and the mass needed to supply the plant was about 736 kilograms
per second on average.
Reinjection
During the development of the Reykjanes power plant, the intention was to reinject part of the geothermal
brine from the separators of the Reykjanes power plant back to the reservoir, as part of the reservoir
management. That way, reservoir pressures would be supported and pressure drawdown mitigated.
Reinjection, however has been postponed to date principally due to the fact that the brine is chemically
complex. Without proper fluid handling before reinjection the reinjection wells would clog up in due
time and loose injectivity. HS Orka has been conducting studies on the fluid handling and estimates that
the brine dilution with steam condensate from the plant is the best way to handle the scaling in the
reinjection wells. The amount of reinjection fluid available therefore depends on the amount of available
condensate. It is estimated that up to 300 kilograms per second or 30 to 50% of the mass extracted can be
reinjected back to the reservoir. The available condensate flow with three 50 MW electrical units in
operation is about 250 kilograms per second. No problems are foreseen in reinjecting all of the pure
oxygen free condensate mixed with brine until the fluid mix amounts to 50% of the fluid production. At
this dilution level, the scaling problem associated with the reinjection is considered to be immaterial.
Well RN-20 was drilled in the spring of 2005 to a total depth of 2,126 metres with the aim of being a
production well. It had limited output and casing failure at a depth of 230 metres depth and was therefore
never used as production well. In the summer of 2008, the well was sidetracked and directionally drilled
about 800 metres to the south southeast for the purpose of being a reinjection well and was renamed RN20B. This well is the easternmost well in the Reykjanes field. Its location seems to be ideal for a
reinjection test. The well is believed to be close enough to create pressure support in the main production
zone, within reasonable time limits, and distant enough to prevent premature cooling in the production
wells.
Reinjection into well RN-20B started in July 2009, and the reinjection rate is about 75 to 80 kilograms per
second, or approximately 13% of the total mass extraction. A tracer test is currently being conducted in
the field in order to investigate the connectivity between the reinjection well and other production wells in
the field. Based on the result of the test it is possible to identify flow paths within the reservoir and
estimate the risk of cooling of the production water.
Currently, one additional reinjection well will be required. This well has been located about three
kilometres northeast of the main production field, in the main direction of faults in the area. The distance
of three kilometres is believed to be a sufficient distance from the production field. The planned
additional reinjection well is within the recharge area of the Reykjanes geothermal field, according to the
- 26 -
InSAR results, so all water reinjected into the well will eventually be produced again. It is expected that
the reinjection will provide pressure support for the geothermal field.
Well-Head Pressure and Mass Flow
Information on well-head pressures, control valve openings of the wells in Reykjanes are automatically
measured, recorded, sent and stored on servers, similar to the Svartsengi field. The monitoring system
has been in operation at Reykjanes since 2004.
The total mass flow from each well in Reykjanes is calculated from the well-head pressure and the
opening position of the control valve. The flow characteristics of the production wells are known from
well testing. The flow from each well is calculated by a formula calibrated against the well-head
pressure, the control valve opening and the orifice in the flow line.
Reservoir Pressure and Temperature
Down hole temperature and pressure profiles have been collected for the last 35 years, but the time series
are discontinuous. No well has served the single purpose of being a monitoring well. The first
measurements were done around 1970 when well RN-08 was drilled. The number of temperature and
pressure logs increased substantially in 2002 when new wells were drilled for the Reykjanes power plant.
Little is known about the pressure history from 1970 to 2002, but the pressure drawdown in that period
due to the production is not believed to be more than two or three bar.
Between 2002 to mid-2009, the temperature at a depth of 1,600 metres in most of the wells in the
Reykjanes geothermal field was demonstrated to be generally increasing due to temperature recovery
from drilling, as well as boiling in the steam zone. Additionally, the temperature in the production wells
at the Reykjanes geothermal field was demonstrated to be gradually increasing from approximately 280°C
to close to 300°C during the same period. Wells RN-16 and RN-17 have demonstrated slightly lower
temperatures than the other wells as they are located within the perimeter of the main well field.
There are two likely explanations for the reduced drawdown: reduced mass extraction in the Reykjanes
field; or increased natural recharge to the production part of the reservoir. The production from the field
at the plant start-up was close to 790 kilograms per second, but was approximately 615 kilograms per
second in 2008 due to higher fluid enthalpy. This represents an over 20% reduction in mass extraction
which should eventually result in a reduced rate of pressure drawdown. Increased pressure difference
between the main reservoir and the recharge system, due to the net mass extraction, will most likely
stimulate the natural recharge to the main geothermal reservoir, which also should result in reduced
pressure drawdown. It is believed that both reasons can explain the change in pressure drawdown, but
this can only be investigated with reservoir modeling.
Monitoring Program
The enthalpy of the produced fluid from the Reykjanes geothermal reservoir has been increasing since the
start of operation of the Reykjanes power plant because of the formation of the steam zone found below a
depth of 800 metres in the main production field. The steam zone plays an important role in the
production plan since the planned 50 MW electrical plant expansion will mostly be supplied by shallow
steam wells tapping the steam zone. Enthalpy changes in the production wells in the field are therefore
important to monitor in order to see how the steam zone develops over time.
The reservoir pressure drawdown is the most important parameter to monitor in order to obtain
information on the health of the geothermal reservoir. Currently, the pressure is measured systematically
- 27 -
in one well in the Reykjanes geothermal field, well RN-16, which is roughly 600 metres from the centre
of the production field.
Land Subsidence and Reservoir Recharge Area
In the fall of 2008, the subsidence was about 80 millimetres per year in the area near the Reykjanes power
plant. The subsidence rate was stable in 2003 to 2005 but increased to about 27 to 28 millimetres per year
in 2006 to 2007. The subsidence rate appears to have reduced slightly between 2006 and 2007 compared
with 2007 to 2008. This is presumably due to gradual production decrease from the Reykjanes field from
2006 to 2008.
The subsidence bowl is elongated southwest-northeast parallel to the Reykjanes fissure swarm and
extends some eight to nine kilometres to the northeast from the power plant, or almost all the way to the
Eldvörp geothermal field.
Subsidence rates due to mass production from geothermal fields have also been observed in geothermal
fields outside Iceland, for example in The Geysers in California, Cerro Prieto in Mexico and Wairakei in
New Zealand. The observed subsidence at Svartsengi and Reykjanes are similar to what is observed in
The Geysers and Cerro Prieto, but an order of magnitude less than what has been observed in Wairakei.
In Wairakei, subsidence rates reached almost 500 millimetres per year in the 1970’s but have declined to
about 100 millimetres per year. The total subsidence in Wairakei in 2001 was estimated to be
approximately 15 metres near the centre of the subsidence bowl. That has resulted in damage to wells,
pipelines, infrastructures, buildings and land changes. The land subsidence is not reported to have
impacted the field productivity in any of the fields.
Reservoir Modeling
The Reykjanes geothermal field has been simulated by two detailed numerical models: the AQUA model
and a detailed 3D numerical model (the “ÍSOR model”) developed in 2007. Both the models were used
to simulate the monitoring history and make forecasts on the reservoir pressure response to different
future production scenarios.
Production Capacity of the Geothermal Reservoir
Both the AQUA and the ÍSOR models have been used to forecast the reservoir pressure change in two
wells in Reykjanes, RN-12 in the main well field and RN-16 in the outskirts. These calculations were
done in 2008 and 2009 for HS Orka to assess the impact of the 50 MW electrical expansion of the
Reykjanes plant on the geothermal reservoir and are used to assess the power production capacity.
The ÍSOR model forecasts more pressure drawdown in the field than the AQUA model. Both models
expect the pressure drawdown to level off with time, as actual pressure drawdown data indicate.
The gross mass extraction from the Reykjanes reservoir was, on average, approximately 736 kilograms
per second in 2007 and the enthalpy approximately 1,335 kilojoules per kilogram. The forecasts made by
the ÍSOR model were done in early 2008 and are based on the 2007 mass extraction and enthalpy
numbers. The forecast made in September 2009 by the AQUA model were done with same mass
extraction and enthalpy number in order to make model comparisons for HS Orka. The mass extraction
values in the scenarios do not, therefore, reflect the current mass extraction in the Reykjanes field.
Because of the steam cap creation in the Reykjanes reservoir, the average mass extraction from the
reservoir has reduced from 2007 and was, in 2008, approximately 614 kilograms per second. The
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enthalpy increased from 1,335 kilojoules per kilogram to 1,400 kilojoules per kilogram. The mass
extraction is therefore about 18% higher in scenario 1 than the 2008 average. HS Orka plans to drill four
additional wells to supply the 50 MW electrical expansion. The assumption is that three wells will be
drilled to the steam cap and one well to the “wet and deeper” part of the reservoir. The steam wells can
be assumed to have enthalpy of approximately 2,800 kilojoules per kilogram and the wet well
1,400 kilojoules per kilogram. The expansion of the steam cap and the drilling of new wells will
therefore increase further the enthalpy of the produced fluid from the field.
If one assumes an average future enthalpy of 1,600 kilojoules per kilogram, the steam fraction at 18 bar
operational pressure will therefore increase from about 26% to approximately 37%. This results in a
needed mass extraction of approximately 800 kilograms per second, which is about 10% higher than the
base case scenario resulting from reservoir modeling. If 25% reinjection is assumed, the net mass
extraction will be around 600 kilograms per second, or about 17% lower than the base case scenario
resulting from reservoir modeling.
The method used for the Svartsengi field to forecast the future well-head pressure was also used to
forecast the future well-head pressure for a typical well in the Reykjanes field. However, the monitoring
data on well-head pressure in the Reykjanes field was not used in the calculations because of short
monitoring history and fluctuation in the observed values. Instead constants were selected by comparing
the calculated output curve of a hypothetical production well representing other wells in the field, to the
family of all measured output curves in the different production wells in the field.
According to this forecast, the following cut-off pressure levels are defined for the steam supply system
for the Reykjanes power plant:


24 bar standard operational; and
22 bar minimum preferred.
Production 725 kg/s and 0 kg/s reinjection
Figure 2: Forecasted future well-head pressure in well RN-12 in Reykjanes for scenarios 1, 2, and 3 (provided by Vatnaskil).
- 29 -
The future well-head pressures of the hypothetical well in Reykjanes are higher than the standard
operational cut-off pressure of 24 bar at all times until 2040 in all future forecast scenarios resulting from
reservoir modeling.
Production Considerations
Since the steam supply commenced in May 2006, a steam cap was created at depths of approximately 800
to 1,200 metres. The development of the steam cap has resulted in higher fluid enthalpy and reduced
mass extraction from the field. The reduced production, and most likely increased recharge to the
geothermal reservoir, has resulted in a reduced rate of pressure drawdown as observed in well RN-16.
Shallow production wells have been drilled in the field with the objective of producing from the steam
cap. The 50 MW electrical expansion of the Reykjanes plant is planned to be supplied in two parts, with
two-thirds coming from the steam zone and the other one-third from deeper parts of the reservoir. The
future production strategy is therefore highly depended on the expansion and the health of the steam cap.
The three forecasted production scenarios created with the ÍSOR model give important indications about
the steam cap developments until 2040. According to the forecasts, the steam zone will expand in size
until 2040. However, the temperature in the steam cap will decrease roughly 30 to 40°C in all scenarios.
This is natural since the boiling and the water recharge into the steam zone is effectively a heat mining
process from the reservoir rocks which results in lower reservoir rock temperature. The boiling is not
expected to go much below 1,500 metres. The temperature in the single phase fluid deeper in the
reservoir does not change profoundly according to the model forecasts. The pressure drawdown at a
depth of 1,600 metres in the reservoir is expected to reach 50 to 60 bars in 2040.
Two of the three future scenarios assume that the net mass extraction is 935 kilograms per second on
average without reinjection and 805 kilograms per second with reinjection. This net mass extraction is
higher than the 614 kilograms per second annual average of 2008. The future scenarios are therefore on
the conservative side and pressure drawdown should be less than the 50 to 60 bar forecasted, since the
production will be increased from the steam zone. The increased production from the steam zone and
planned reinjection will mitigate the pressure drawdown in the field.
It is clear that utilization of the steam zone will result eventually in lower temperatures of the steam cap.
The saturation pressure for current reservoir temperatures of 295°C in the steam zone is about 80 bar
absolute, but about 47 bar absolute for reservoir temperatures of 260°C. Whether the temperature
decrease in the steam is 30 to 40°C or 20 to 30°C, the change in temperature will, however, definitely
impact well-head pressure and the output of wells producing from the steam cap. The reduced
temperature of the steam zone and declined well output will probably call for the drilling of make-up
wells to replace the declining well output. The need for make-up wells is currently not known, nor is the
expected timing of these needs.
Expansion of the Production Well Field
In order to supply the 50 MW electrical expansion of the Reykjanes power plant, new production wells
need to be drilled. HS Orka assumes five more wells are needed for the expansion of the power plant and
three wells are needed as stand-by wells.
The average output of the 12 production wells that supply the 100 MW electrical power plant is about
8.3 MW electrical, so a minimum of six to seven wells are needed to supply the 50 MW electrical
expansion if they produce from the deeper, wet part of the reservoir. The wells producing from the steam
zone are twice as powerful as the wet wells so by utilizing the steam zone the expansion is assumed to be
supplied by four steam wells.
- 30 -
Resource and Reserve Estimate and Classification
The forecasts of the reservoir pressure drawdown and the forecasts of the well-head pressure indicate that
the Reykjanes geothermal reservoir is capable of supplying high-pressure steam to the current 100 MW
electrical Reykjanes power plant plus the 50 MW electrical expansion through 2040. However, it can be
assumed that replacement wells may be needed sometime in the future to make up for declining well
output rates.
HS Orka plans to add the fourth unit in 2014, a secondary flash turbine anticipated to be 30 MW
electrical. The unit uses the secondary flash energy from the existing primary flash turbines. The mass
extraction from the reservoir will not increase and no new drilling will be required to support the
installation of the secondary unit. The installation of the secondary unit will therefore increase the plant
energy conversion efficiency and not impact the geothermal resource.
The resource and reserves of the Reykjanes geothermal system are estimated with numerical models and
calculations by considering future forecasts of reservoir pressure response and well-head pressure decline.
In accordance with the Australian Code the Reykjanes geothermal system contains a proven reserve with
recoverable thermal energy of 100 MW electrical for 30 years and an indicated resource with electrical
generation capacity of 80-100 MW electrical for 30 years, relative to the current operational parameters of
the Reykjanes geothermal power plant and with the planned secondary flash unit successfully installed.
At this time and in light of the known data, the Reykjanes geothermal reservoir has been classified as an
indicated resource, capable of producing 80 to 100 MW electrical for 30 years, with additional proven
reserves of 100 MW electrical for 30 years. As the production continues with time and the monitoring
program improves, the numerical models will be calibrated in order to continually improve the confidence
level of future forecasts.
HS Orka’s expansion plans of adding another 50 MW electrical turbine and a 30 MW electrical secondary
turbine to the existing operation is within the production capability of the current resource, with the
assurance that continued reservoir monitoring, reinjection and active numerical modeling is maintained in
order to ensure the continued sustainability of the reservoir for 30 years, and beyond.
Eldvörp
HS Orka has plans to develop a 50 MW electrical geothermal power plant in Eldvörp by 2015. The
Eldvörp and Svartsengi geothermal fields are connected and both are part of the same geothermal
reservoir. This is confirmed by the results of the resistivity explorations, monitored pressure interference
between the fields and the InSAR measurements. Because of the known interference between the fields, a
power plant in Eldvörp could be envisioned as an expansion to the existing power plant in Svartsengi. It
is therefore important to investigate the Svartsengi reservoir pressure response to the future mass
extraction in Eldvörp.
Forecast on Future Response to Production
In order to investigate the impact that the planned 50 MW electrical unit in Eldvörp will have on the
Svartsengi plant, the AQUA model was used to analyze future production scenarios for 30 years. The
main conclusion of the modeling is that large scale reinjection is essential if the Eldvörp geothermal
project is going to be feasible. The modeling results indicate that the reservoir pressure drawdown in
Eldvörp will be similar to what is observed in Svartsengi as the result of the future mass extraction in both
fields.
- 31 -
The rock permeability is not well known in Eldvörp so the future pressure drawdown caused by the mass
extraction is not accurately determined. New wells drilled in the field will give more information that can
be used to improve the calibration of the AQUA model in the vicinity of Eldvörp.
Both the Eldvörp and the Svartsengi geothermal fields are part of the same geothermal reservoir. The
model studies show mass extraction needed to supply the Eldvörp power plant will result in increased
reservoir pressure drawdown at Svartsengi and well-head pressure decline of production wells.
In two modeled injection scenarios, if an Eldvörp power plant started operation in 2009, the well-head
pressure of SV-8 at Svartsengi would reach the eight bar minimum preferred operational pressure of the
Svartsengi plant in years around 2020. However if the Eldvörp power plant starts operations in 2015, the
well-head pressure decline will therefore reach the eight bar level some years later, perhaps by 2025. It
should be noted that the forecast reservoir pressure drawdown is conservative resulting in conservative
well-head pressure decline.
Figure 3: Forecasted well-head pressure in SV-8 as function of different production scenarios in Eldvörp (provided by Vatnaskil). The
middle line represents the forecast based on an assumption of 50 MW production and 50% re-injection.
Before the reducing well-head pressures reaches the eight bar level, the operational strategy must be
changed in the field to maintain well-head pressure above the minimum preferred level. The current
operational scheme is to operate the wells at constant flow rate, resulting in declining well-head pressures.
A different operational scheme is to operate the well on constant well-head pressure and with decreased
well output. This is done by throttling the wells and reducing the flow rate to maintain the well-head
pressure. The reduced production well output will call for drilling of make-up wells to make up for the
reduced well outputs and maintain the steam needs of the Svartsengi power plant. Increased reinjection in
Svartsengi will also mitigate the reservoir pressure decline resulting in less well-head pressure decline.
- 32 -
The Eldvörp geothermal field is in the exploration phase and more drilling is needed in the field to
investigate further the production characteristics of the geothermal reservoir. It is concluded in the HS
Orka Report that it is practical to plan for a 50 MW electrical unit in Eldvörp and probable that the
geothermal resource can supply such a power plant with high-pressure steam.
Resource Estimate and Classification
Based on the results and interpretations predicted by the AQUA model and in accordance with the
Australian Code, the Eldvörp geothermal resource is classified as an indicated resource containing
sufficient recoverable thermal energy of 50 MW electrical for 30 years, assuming 50% reinjection and
energy utilization parameters similar to the parameters defined by the Svartsengi geothermal power plant.
Krýsuvík
A volumetric assessment was done for the Krýsuvík geothermal area as part of the national assessment.
The assumptions used in the Krýsuvík volumetric assessment are the following:

Geothermal field area is 60 square kilometres. It is based on the area covered by geothermal
surface manifestations and geothermal alteration covering approximately 56 square
kilometres and the outline of a low resistivity anomaly at 600 metres depth from surface,
enclosing all the surface manifestation and the geothermal alteration area, covering
approximately 60-65 square kilometres.

The thickness of the geothermal system is three kilometres (from surface to three kilometres
depth).

The temperature distribution in the overall field is estimated 70% of the boiling point curve
with depth from surface to three kilometres depth. It is based on temperature profiles from
all wells in the area at the time.

Porosity is 10%

Cut-off temperature is 130°C

Geothermal recovery factor is 20%

Geothermal efficiency factor is 7%

Accessibility 80%

Plant load factor 100%

The geothermal system is closed with no energy exchange with the surroundings, i.e. it is not
considered renewable.
The thermal energy in place in the Krýsuvík geothermal area was estimated to be 105,000 petajoules,
relative to 5°C. The thermal energy in place converts to recoverable thermal energy of approximately
300 MW electrical for 50 years by assuming a cut-off temperature of 130°C, geothermal recovery factor
of 20% and geothermal efficiency of 7%. It is further assumed in the resource estimate that 80% of the
land is accessible for geothermal development. The approximate recoverable thermal energy of 300 MW
electrical for 50 years is equivalent to about 500 MW electrical for 30 years.
- 33 -
The geological and exploration results obtained in the Krýsuvík geothermal area provide good evidence
that the geothermal resource exist in a form, quality and quantity sufficient for eventual economic
extraction. However, temperature data from geothermal wells and other geothermal information available
are limited, compared to the indicated extent of the resource, to accurately predict the temperature
distribution of the Krýsuvík geothermal resource.
The geothermal resource at Krýsuvík area, including Sandfell and Trölladyngja sub-geothermal resources,
is classified according the Australian Code as an inferred geothermal resource with approximately
105,000 petajoules of thermal energy in place, relative to 5°C. The recoverable and converted energy is
equivalent to approximately 500 MW electrical for 30 years, by assuming 20% thermal energy recovery
and 7% efficiency factor.
The resource in the Krýsuvík geothermal area may be upgraded to indicated geothermal resource as more
exploration wells are drilled and more information on the temperature distribution becomes available.
Trölladyngja
The Trölladyngja geothermal field is a sub-field of the Krýsuvík geothermal field. The Trölladyngja
resource has only been estimated as part of the greater Krýsuvík geothermal resource. The boundaries of
the Trölladyngja resource, as part of the total Krýsuvík resource, have not been identified.
The Trölladyngja resource can be estimated and classified by using the Krýsuvík resource classification
and estimate. That can be done by estimating Trölladyngja’s proportion of the entire Krýsuvík resource,
since the volumetric assessment used for Krýsuvík assumes that the temperature distribution is 70% of the
boiling point curve in the overall Krýsuvík geothermal resource.
In preparing the HS Orka Report, Mannvit hf assumed that approximately 30% of the entire Krýsuvík
resource belongs to the Trölladyngja resource therefore the assumed thermal energy in place in the
Trölladyngja geothermal resource is approximately 32,000 petajoules. The assumed thermal energy in
place converts to recoverable thermal energy of approximately 150 MW electrical for 30 years, by
assuming cut-off temperature 130°C, geothermal recovery factor of 20% and geothermal efficiency of
7%.
The geothermal information obtained from the two deep exploration wells in Trölladyngja show that a
geothermal resource exists in the field. However, the temperature information available is limited and
insufficient to confidently estimate the temperature distribution of the Trölladyngja geothermal resource.
Similar to the greater Krýsuvík geothermal resource, the Trölladyngja geothermal resource is also
classified as an inferred geothermal resource according to the Australian Code with approximately
32,000 petajoules thermal energy in place, relative to 5°C. The recoverable and converted energy is
equivalent to approximately 150 MW electrical for 30 years, by assuming 20% thermal energy recovery
and 7% efficiency factor. The Trölladyngja geothermal resource is included in the Krýsuvík geothermal
resource.
The confidence in the estimate of the Trölladyngja geothermal resource is not sufficient to allow the
results of the exploration and research completed to date to identify the technical and economical
parameters for detailed planning of a geothermal power project. The feasibility of a geothermal project in
Trölladyngja geothermal field can, therefore, not be evaluated given the current knowledge and
understanding of the geothermal resource. Further exploration drilling, research and development
combined with bankable feasibility studies are required.
- 34 -
With further exploration and drilling in the field, and by assuming that high permeability zones can be
found in the field, there are reasonable prospects for eventual economic energy extraction in the
Trölladyngja field. It is also reasonable to expect that the Trölladyngja geothermal resource may be
upgraded to indicated geothermal resource as more information becomes available.
II.
United States
United States Geothermal Leases
We have acquired a large portfolio of properties in the United States. Typically, when we acquire an
interest in a property with geothermal potential in the United States, we do so by entering into a lease with
the owner of the property. The lease grants us the right to explore and develop the geothermal resources
on the property. In addition, the lease allows us to use as much of the surface of the property as required
to accomplish these objectives.
Many of the leases presently held by us cover public lands and have been issued by the BLM. In some
cases, the BLM leases were acquired by us through a competitive bidding process and we are the initial
holder of the lease and the beneficiary of the full term of the lease. For example, the rights to the McCoy,
Panther Canyon, portions of Desert Queen, Beowawe, Columbus Marsh, Granite Springs, and Glass
Buttes Properties were acquired by us in this fashion. In other cases, we have taken an assignment of
BLM leases from other leaseholders during the existing term of a BLM lease. Our Thermo Hot Springs
Property is an example of an assignment acquisition. In some cases, we have supplemented our holdings
in certain areas by entering into leases with private landowners. In the case of a lease with a private
landowner, we generally pay an annual rental payment for the right to explore and develop the geothermal
resources on the property. If a geothermal plant is placed in service on the property, the lease generally
requires the payment of royalties in place of the annual rental payment. In most cases, the annual rental
payments are credited against any royalties payable to the owner.
The BLM leases we acquired at competitive lease sales for Nevada and Oregon have a primary term of
ten years, with the possibility of obtaining certain extensions of the lease term. If a geothermal plant is
developed on the property, the leases convert to a royalty structure. Rental fees are payable annually to
the U.S. Minerals Management Service (“MMS”) in the amount of $2.00 per acre in year one, $3.00 per
acre in years two through ten, and $5.00 per acre thereafter. These rental fees are payable even after the
leases are in production status, however, rental fees are credited against royalties due. Once production
commences, royalties are payable to MMS in the amount of 1.75% of gross proceeds on the sale of
electricity for the first ten years, increasing to 3.5% of gross proceeds after the first ten years of
production and for as long as the property produces power; provided, however, that a royalty of 10% of
gross proceeds is payable on arms-length sales of electricity.
BLM leases grant the holder the exclusive right to explore for and develop the geothermal resources
found beneath the lease, subject to the satisfactory completion of requisite administrative, operational,
environmental, and cultural resource permitting requirements, and compliance with the Geothermal
Steam Act of 1970, as amended, the regulations thereunder, the National Environmental Policy Act,
as amended, and related environmental protection statutes governing endangered species, clean air, clean
water, and cultural resource management.
Overview of Volumetric Resource Estimate Methodology
Geo Hills Associates LLC (“GHA”) calculated several MW capacities for the McCoy, Panther Canyon,
Desert Queen and Thermo Hot Springs Properties using the volumetric estimation method developed by
the USGS. This approach has been modified to account for uncertainties in some input parameters by
- 35 -
using a probabilistic approach known as a Monte Carlo simulation. Using this method, it is possible to
estimate reserves associated with a particular geothermal property based on a volumetric calculation of
the heat-in-place with reasonable assumptions made about the percentage of the heat that can be expected
to be recovered at the surface, and the efficiency of converting that heat to electrical energy.
The goal of a volumetric reserve estimation using a probabilistic technique is to estimate the quantity of
energy as of a given date to be potentially recoverable from undiscovered accumulations by future
development projects. Prospective resources have both an associated chance of discovery and a chance of
development. Prospective resources are further subdivided in accordance with the level of certainty
associated with recoverable estimates assuming their discovery and development, with the following
definitions:
“P90” – The quantity for which there is a 90% probability that the recoverable geothermal energy
expressed in MW will equal or exceed the estimate.
“P50” – The median or the quantity for which there is a 50% probability that the recoverable geothermal
energy expressed in MW will equal or exceed the estimate.
While the GHA report provides a P50 estimate for some properties, we have elected to use the P90 estimate
for evaluating the resource potential of the McCoy, Panther Canyon, Desert Queen and Thermo Hot
Springs Properties.
For the MW capacity estimate, GHA has estimated reasonable ranges for the parameters needed for a
volumetric heat calculation (areal extent of the reservoir, thickness of the reservoir, and an average base
temperature of the reservoir), based on the best available field data and analogies to other geothermal
power projects in similar geological environments. The ranges of heat recovery factors and plant
performance parameters are also estimated based on current technology and industry experience. The
ranges of input parameters were then sampled statistically, and the calculations of an equivalent MW
capacity repeated thousands of times (approximately 100,000 times) by computer using a probabilistic
simulation, yielding an overall probability distribution. It is important to note that the presence of a
certain amount of heat in place does not guarantee that this heat can be commercially extracted.
Commercial operations depend on having geothermal wells with adequate productivity, which can only
be demonstrated by drilling.
The heat recovery factor was assumed to range from 5% to 15%. Another parameter that is used in the
volumetric reserve estimation methodology is the conversion efficiency, which is the ratio between the
useful output of electric power and the input in terms of energy. A conservative value of 40% was
assumed for the simulations. The rejection temperature is the ambient temperature at the wellhead (e.g.,
15°C, or more often the condenser temperature) which is often assumed to be about 40°C, which value
was used in the calculations.
Soda Lake Operation
The following is a description of the Soda Lake Operation. Certain statements in the following summary
of the Soda Lake Operation are based on and, in some cases, extracted directly from, the Soda Lake
Report prepared on behalf of Magma by GeothermEx who is independent from the Company. See
“Scientific and Technical Information”. Reference should be made to the full text of the Soda Lake
Report which is available for review on SEDAR located at www.sedar.com.
- 36 -
Property, Permit, Environmental and Infrastructure
Location
The Soda Lake Operation is located in the southwest portion of Churchill County, Nevada, approximately
11 kilometres northwest of the City of Fallon, Nevada and 115 kilometres east of Reno. The Soda Lake
Unit Agreement (“SLUA”) consists of a total of 2,070.7 hectares of both private (1,003.2 hectares) and
federal lands (1,067.5 hectares). All of these leased lands are committed to the SLUA, which defines the
project area.
The Soda Lake Operation lies within the Carson Desert, a large extensional depression in the Basin and
Range Province of western Nevada, and south of the Carson Sink. Ground elevations in the Soda Lake
area range from 1,219 to 1,280 metres. The project area is nearly level with slopes ranging from 0 to
15%. The Carson Desert, which surrounds the Carson Sink, is the largest intermountain basin in northern
Nevada. The Carson Desert basin is elongated northeastward, and is 113 kilometres long and 13 to
48 kilometres wide. Interrupting the lowlands south of the Carson Sink are three low volcanic hills:
Rattlesnake Hill, the Soda Lakes maars, and the Upsal Hogback. The Stillwater Range borders the
Carson Desert on the east and reaches an elevation of 2,438 metres. Along the south and west borders of
the Carson Desert are several groups of low mountains that have crest elevations of 1,371 to 1,829 metres.
Property, Tenure and Permits
Project Property
The SLUA was initially proposed by Chevron Resources Company (“Chevron”) and approved by the
BLM on September 16, 1977. At that time, the SLUA was comprised of 9,800.4 hectares. Following the
completion of certain geophysical studies and the drilling of slim holes and full-diameter wells, Chevron
opted to reduce the size of the SLUA to 4,802.2 hectares. Upon Chevron’s documentation of two
successful wells, the BLM approved the initial participating area on February 15, 1987. The Participating
Area (“PA”) is the portion of the SLUA that was reasonably proven productive based on well testing
performance. As required under terms of the SLUA, the unit area later contracted to the current size of
2,070.7 hectares. For that reason the boundaries of the SLUA and the PA are the same.
The lands within the PA are a combination of federal and privately held leased properties which provide
for surface access as well as mineral (geothermal) rights. Three of the four federal geothermal leases
located within the SLUA have been in effect since October 1975. The fourth lease has been in effect
since 1988, and was committed to the SLUA at that time. All four leases have been in production status
since commercial well production in the SLUA commenced in 1988, and the leases will continue to
remain in effect for 50 years from the effective date as long as any production from the SLUA continues.
A subsequent preferential right to renew for a 40-year term may be granted if production in commercial
quantities exists at the end of the 50 year period and the lands are not needed for other purposes.
All private lands located within the SLUA also have been leased since the late 1970s or early 1980s.
These private leases are committed to the SLUA. According to the lease terms, these private leases will
continue to remain in effect as long as any production from the SLUA continues.
Additionally, a Right of Way Agreement on federal lands and Right of Way Grants on private lands are in
place, granting the use of the involved lands for the transmission line. The transmission line is
approximately seven miles long and runs outside of the immediate project area to the substation for
connection with the Nevada Energy grid.
- 37 -
Adjacent Properties
Magma has numerous federal lands under lease which are located in proximity to the SLUA. Geothermal
resource development may occur on these lands with appropriate permit approval. The SLUA may be
expanded, with BLM approval, if or when the results of additional exploration and development indicate
there is a geological basis for doing so.
Magma has six federal leases surrounding the SLUA and one private lease. Four of the federal leases
were obtained in 2009, with the remaining two obtained in 2002. The federal leases provide for a ten year
primary term, and retain the same surface and mineral (geothermal) rights as Magma’s other federal
leases.
The private lease provides for both surface and mineral rights, with a five year term and an option for five
one-year extensions if activity is conducted at the expiration of the prior term. Once production has been
established, the lease will remain in effect as long as production occurs on the lease, or as long as the
lease, or a portion thereof, is located within a producing unit.
Infrastructure and Access
The Soda Lake Operation area is accessible by paved and gravel roads. From Fallon, the project area is
accessed by traveling west on U.S. Highway 50 for ten kilometres, and then turning north onto Soda Lake
Road and proceeding north for eight kilometres. From Reno, travel east on I-80, exit at Fernley, then
proceed east on U.S. Highway 50A until reaching Soda Lake Road. The power plants and all production
and injection wells are accessible on all-weather gravel and dirt roads. Snowfall and rain have not had
any impact on access to the site.
The City of Fallon is the county seat of Churchill County, and provides basic needs for the staff working
at the power plant and supplies limited equipment requirements. Additional equipment needs can be
supplied from Reno or from major cities in California or Utah, which are located approximately ten hours
driving time from the Soda Lake project area. Two major highways, Interstate 80 and U.S. Highway 50,
are located in close proximity to the project area.
Additionally, the area is served by a regional railroad line, which passes several kilometres to the south of
the project area. The project area is in close proximity to 120 kV, 230 kV and 345 kV transmission lines.
Environmental
All proposed activities related to the development of the geothermal resource are subject to local, state,
and federal regulations and permitting requirements. These regulations and permitting requirements
establish the operational standards and environmental protection measures which all resource
development activities must meet. Permit applications, which explain how operations will comply with
operational and environmental standards, must be reviewed and approved by involved regulatory agencies
before any new development occurs within or surrounding the SLUA. This approval insures compliance
with operational standards, such as how a well will be drilled and completed, and environmental
standards, such as adequately protecting cultural resources, rare and endangered species, clean water and
air, and limiting the use of hazardous materials.
Exploration and development operations are not impacted by weather and may be conducted throughout
the year.
- 38 -
Soils within the Soda Lake Operation consist primarily of loose sand. Soil alkalinity ranges from
moderate to very strong. The vegetation, which reflects the aridity, is the northern desert shrub
association, dominated by desert shrubs, and is closely controlled by soil conditions and drainage.
Land Use
All lands within the SLUA are leased for geothermal development, as are many of the lands located
outside the SLUA. As such, geothermal development is the primary use of these leased lands. The lands
are also occasionally used by recreationalists exploring the area, and a few people following the Carson
River route of the California Trail, which runs through the geothermal field.
History and Status
The beginnings of geothermal activity on the Soda Lake geothermal power plant site surrounded a
naturally occurring, weak steam vent or fumarole located northwest of the Soda Lake 2 facility. Churchill
County locals constructed a bathhouse on the property and used the steam for recreational pursuits in the
last half of the 20th century. Since that time, the cinder block structure has disappeared and the fumarole
is no longer active as a result of natural weathering.
Commercial development of the geothermal resource began in the 1970s. The development of the power
plant for generating electricity commenced in 1985 as a collaborative effort between Western States
Geothermal Inc. (“WSG”) (a Chevron subsidiary) and Ormat Nevada Inc. (“Ormat”). Sierra Pacific
Power Company awarded the first PPA for generation from Soda Lake 1 in 1987, and construction on the
facility, which began soon thereafter, was completed in December of 1987. A shallow water well was
successfully drilled in the same year. The plant was commissioned in mid-December 1987.
Soda Lake 1 consisted of three Ormat Energy Converters (“OEC”) (OEC 11, 12, and 13); each rated at
1,200 kilowatts (gross) at 600 volts nominal generating voltage. The plant operated in this configuration,
with production from well 84-33 and injection into well 77-29, from late 1987 until mid-1990.
Soda Lake 1 experienced unqualified success for the first three years of production in the form of
consistent temperatures and stable flow rates from the 84-33 well coupled with no increase in injection
pressure from 77-29.
Ormat alone initiated the expansion of the Soda Lake project after WSG left the project in 1990.
Construction of Soda Lake 2, approximately one kilometre west of Soda Lake 1, commenced in 1990
after the second PPA was reassigned to the project from the Stillwater location farther to the east in
Churchill County. This new PPA was subsequently blended with the Soda Lake 1 agreement for
simplicity of accounting. Drilling for Soda Lake 2 continued through the 1990-1992 period to supply
sufficient geothermal fluid and injection capacity. The Soda Lake 2 facility was completed by the third
quarter of 1990 with six new three MW OEC units, each with two turbines and one generator, and a bank
of air-cooled condensers. Additionally, OEC 21 was added to the tail stream of Soda Lake 1. OEC 21
consists of a single turbine generator rated at 1,500 kilowatts (gross) generated at 4,160 volts. Soda Lake
2 was put into commercial operation in early 1991.
Additional drilling was required because the plant was not able to generate at its full rated capacity due to
inadequate fluid production rate. During its first three years of operation, Soda Lake 2 was unable to
fulfill the contractual obligations of the PPA. As a result, the utility enforced the de-rating provision of
the PPA, and the rated output of the facility was dropped from 14.2 to 9.2 MW. This rating effectively
terminated exploration for additional resource because the PPA had limited revenue potential.
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Ownership of the facility changed from OESI Power Corporation (an Ormat subsidiary) and
Constellation, to Constellation and Harbert Power Corporation (“Harbert”) in 1997. The designated
operator of the facility also changed from Nevada Operations, Inc. to Constellation Operating Services
Inc.
This latter group drilled one production well in 2002 to a depth of 1,451 metres where they encountered
ample permeability and fluids at temperatures of 193°C. During subsequent testing of the well, the lower,
uncased portion of the hole caved in. Subsequent attempts to re-establish the wellbore were unsuccessful,
and the well was abandoned. The Soda Lake facility was sold by Constellation and Harbert to Magma in
October 2008.
Shortly following the acquisition, Magma designed a two phased expansion approach as follows:

Phase 1 – a drilling/exploration and plant upgrade program to restore the generating capacity
back to the original nameplate of 23.1 MW gross (16 MW net) by drilling new production
wells and upgrading and refurbishing the existing power plant equipment; and

Phase 2 - conditional upon the successful completion of the Phase 1 drilling/exploration
program and additional reservoir definition, a further expansion program to increase
nameplate capacity to realize the ultimate reservoir potential. The minimum expansion target
for Phase 2 is an additional capacity of ten MW net.
In April 2010, a reserve and resource estimate was prepared for Soda Lake by GeothermEx (the Soda
Lake Report). The estimate concluded that the Soda Lake reservoir contains a proved reserve of
14.2 MW net and an additional 28.5 MW net indicated resource. This compares with a previous P90
estimate of the geothermal reservoir’s gross generation capacity of 29 MW.
Progress on the Phase 1 program includes the completion of two production wells to depths of 4,468 feet
(45A-33) and 8,995 feet (41B-33) respectively. In an ongoing effort to ensure sustainable production
from the well field, the Company is currently analyzing data from all wells drilled to date at Soda Lake
which includes an optimization review of the current production and reinjection strategy. As part of this
optimization program, the Company incorporated an established oil and gas stimulation technique known
as deflagration on production well 45A-33. Following this stimulation/rework treatment, a flow test was
successfully completed in late December 2009. At that time the test demonstrated the well to be capable
of delivering 1,200 gallons per minute (“GPM”) of sustained flow at a temperature of 385 degrees
Fahrenheit (“°F”), sufficient to provide three MW of net power. The well was successfully connected to
the plant in late April 2010 and started up as scheduled on May 1, 2010. This is the first new well that
has been connected to the plant in over 17 years and represents one of the hottest pumped wells in the
world with one of the industry’s deepest setting depths at over 2,000 feet. Since commencing commercial
production it has been observed that the current scaling inhibition program utilized in this well is not
adequate which has led to decreased productivity. A new inhibition program is currently being
incorporated in order to regain the full production potential from the well.
Production well 41B-33, the second well drilled in 2009, initially demonstrated very poor permeability
and was not able to sustain production flow. As part of the field optimization program for this well
several rework options were outlined in order to achieve either commercial production or injection. The
well was perforated and deflagrated at depth which targeted a high temperature range and subsequently
several injection tests were performed in order to establish an injectivity index to determine whether or
not the stimulation techniques were successful. Following a high pressure injection test conducted in
June 2010, it was determined that the well was not able to accommodate injection at commercially
acceptable levels. As part of the rework options identified for this well, a final option for consideration is
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to initiate production from the very shallow aquifer (at approximately 1000 feet) through which the well
was originally drilled. This rework is expected to commence shortly.
As part of the efforts associated with increasing productivity from the well field for the Phase 1 expansion
in January 2010 the Company attempted to re-enter and flow a decommissioned production well, 41-33,
which was shut down in 2002 due to ongoing pump failures. As part of this exercise it was quickly
realized that a steam cap had formed in this area of the field and what followed was an exhaustive three
month steam flow test from this well in order to determine the sustainable level of flow deliverability.
The test was completed at the end of April 2010 at which point it was concluded that the well was a
marginal steam producer. A heat and mass balance analysis was conducted on the resulting steam quality
in order to determine how to incorporate this thermal energy into the facility. The Company initiated a
conceptual engineering study whereby a portion of the plant discharge brine would be mixed with the
steam from this well, and re-injected into the facility in order to boost production. A system will be
designed and tested incorporating proven steam mixing equipment in order to quantify the overall net
gain to the facility.
In order to complete the Phase 1 expansion, the Company has decided to drill a third production well.
Drilling of well 25A-33 commenced in June 2010 and is currently on-going. In addition to drilling
activities, the Company completed a detailed engineering assessment of power plant upgrades and
refurbishments that would be required in anticipation of the new production wells. A significant portion
of the refurbishment program was completed in September and October 2009 when the plant was partially
shut down for annual maintenance. The refurbishments completed to date have contributed an additional
one MW of net output commencing in December 2009.
In summary, the Phase 1 expansion highlights include the following key activities in order to achieve
nameplate capacity:

Addition of new production well 45A-33

Addition of new production well 41B-33

Addition of steam/mixing system well 41-33

Plant refurbishments

Drilling new well 25A-33
The Company expects to complete the Phase 1 expansion by the end of 2010. With the commencement
of drilling a third production well, the original budget of $18.2 million has increased to $25 million with
approximately $18 million spent to date. Upon completion of Phase 1 and at an ‘in-service’ state, the
Company will apply for the US Federal Treasury Grant which is valued at up to 30% of the eligible
project costs.
The Soda Lake Operation sells all of its current electricity output to NV Energy under two 30-year PPAs
that terminate in 2018 and 2020. The Company has commenced discussions with NV Energy and one
other party to negotiate an improvement in the pricing under the current PPAs and for the planned
increase in electricity output from the plant expansion. There is no guarantee that these negotiations will
prove successful. However, given the Company’s plans to expand and increase the output of the Soda
Lake Operation, management is of the opinion that a re-negotiation of the existing agreements and/or a
new agreement for additional production will be required.
The Phase 2 expansion commenced in June 2010 with the receipt of the necessary environment permits
from the BLM to conduct a 3D/3C Seismic survey on the Soda Lake property as part of a $5 million U.S.
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Department of Energy Grant received by Magma. The survey is scheduled to commence in July 2010 and
it is currently anticipated that should a successful target be recognized through the efforts of this geophysical survey that production drilling will commence in the fall of 2010.
In addition to the seismic survey Magma intends to commence a thermal gradient drilling program in
early September 2010 following receipt of permits from the BLM which are currently under review.
These two activities combined with the updated resource assessment received by GeothermEx will define
the overall size and drilling and development strategy for the Phase 2 expansion. The minimum
expansion target for Phase 2 is an additional capacity of ten MW net expected to be on line by the end of
2013 in order to maintain eligibility for the US Federal Treasury Grant.
Surface and Shallow Sub-Surface Data and Information
Geological Setting
Regional Geology
The Soda Lake Operation is located in the Carson Desert basin in western Nevada. The basin is bounded
on the west by the Hot Springs Mountains (which host the Desert Peak and Bradys Hot Springs
geothermal projects) and Dead Camel Mountains, and on the east by the Stillwater Range, the Bunejug
Mountains, the Cocoon Mountains and the Sand Springs Range. Two other operating geothermal projects
(Stillwater and Salt Wells) and at least two hot springs also lie within the Carson Desert basin. At Soda
Lake, formerly steaming and hydrothermally altered ground is present above the area where a shallow
geothermal aquifer is known to be present.
The Carson Desert basin lies within the western part of the Basin and Range geologic province, a region
where the earth’s crust is relatively thin and extending. This results in a regional high heat flow that is
approximately twice that of most of the North American continent. Quaternary alluvium and lacustrine
deposits cover thick layers of Tertiary volcanic rocks in the basins.
Tertiary volcanic rocks generally overlie Mesozoic sedimentary and metamorphic rock units in the basinbounding ranges. The region has a distinct north northeast structural “grain” with major ranges and many
faults oriented in that direction. The Carson Desert basin also has a north northeast orientation, and
contains mapped and inferred north northeast-trending faults to the northeast of the Soda Lake project
area. The northeastern part of the Carson Desert basin is referred to as the Carson Sink, and is the
terminal sink of the Carson and Humboldt Rivers.
Local Geology
The surface of the Carson Desert Basin consists mainly of Quaternary alluvium and colluvium (the Fallon
and Paiute Formations) and lacustrine deposits from the ancient Lake Lahontan, which intermittently
occupied much of northwestern Nevada during the Pleistocene and early Holocene epochs of the
Quaternary period. The basalt at Soda Lake is also thought to be Quaternary in age.
The Quaternary rocks overlie a thick sequence of Tertiary volcanic and sedimentary rocks, including:

Andesitic and dacitic welded ash-flow tuff and basalt flows, possibly correlated with the
Bunejug Formation (comprised of basaltic, andesitic and dacitic lava flows and ash-fall tuffs);

Lacustrine and volcano-sedimentary deposits of likely Pliocene age;
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
Older basalts and tuffs of late Miocene to Pliocene age; and

Basalts and tuff units and associated andesitic to rhyolitic units of Oligocene to Miocene age.
The Tertiary package rests unconformably on Triassic and Jurassic metasedimentary rocks and plutonic
rocks of likely Jurassic and Cretaceous age.
Structurally, the north northeast fault trend of the basin-bounding ranges is mimicked by the north
northeast alignment of the Soda Lakes maars, the geothermal field, and the Upsal Hogback volcanic field.
This alignment, together with the north northeast elongation of the shallow temperature anomaly
discussed below, has been interpreted to define a locally permeable fault zone.
Stratigraphic correlations made using mud logs and geophysical logs permit a north northeast-trending
fault passing through the field.
Thermal Features, Ground/Soil Temperatures and Hydrothermal Alteration
Although hot springs were reported to have discharged in the area through the end of the 19th century, at
present there are no visible and/or active thermal features within or around the Soda Lake Operation area.
A shallow water well drilled in the early 1900s encountered steam and hot water at a depth of about
18.3 metres.
Hydrology
The Soda Lake Operation lies near the southern end of the Carson Sink, a large basin into which the
Carson River flows. The basin also takes some overflow from the Humboldt River and adjacent
Humboldt Sink. Since the early 20th century, the Truckee Canal has diverted water from Truckee River
to the Lahonton Reservoir as part of the Newlands Agricultural project. Leakage from the canal system
and irrigation from the south and southwest of the geothermal field augment the shallow groundwater
recharge and has locally raised the water table near Soda Lake by approximately 18.3 metres. The Carson
Sink receives an average of about 11.43 centimetres of precipitation a year and much of this returns to the
atmosphere through evapotranspiration; therefore, precipitation is not a large component of recharge.
The volumes and origin of the thermal fluid available to the Soda Lake Operation system have not been
thoroughly studied.
The shallow hydrologic system is contained in the Quaternary sediments of the basin (a combination of
unconsolidated lacustrine, fluvial and aeolian deposits). Porosity in the upper 305-457 metres is primarily
intergranular. Locally within the Soda Lake Operation field there is silica deposition resulting from
precipitation as geothermal fluids rise and cool. The majority of the fluid cools by conduction, but there
has been minor boiling at the top of the reservoir in the vicinity of the old bath house resulting in
steaming ground being observed.
Geophysical Surveys
Gravity
Earlier generations of gravity survey data collected at Soda Lake have been validated and augmented by
Magma as part of its resource development program by broader and more detailed coverages acquired
during 2008 and 2010. Interpreted positive gravity anomalies seen in this refined data spatially correlate
with the drill hole thermal anomaly pattern, suggesting relatively deep basement features control the up-
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flow of the hottest geothermal fluids. These gravity data also show other similar unexplored basement
features in the immediate vicinity of the known resource, which represent possible future exploration
areas.
There is a northwest-trending gravity high across the project area.
Detailed ground magnetics were collected by Magma over the complete Soda Lake Operation area lease
holdings to augment an existing detailed survey over the geothermal field. Merged and processed to
residual anomaly maps these data record the magnetic signatures of possible intense hydrothermal
alteration within and peripheral to the main geothermal field. The peripheral anomalies are a contributing
indicator of possible additional resource around the developed field.
An MT resistivity survey of 75 stations was conducted during the fall of 2009 to map the deep and
shallow electrical resistivity expression of the geothermal resource over Magma’s lease holdings at the
Soda Lake Operation. The inverted MT soundings were assembled into a 3D model and interpreted by
Magma in the context of the complete Soda Lake geoscience model.
The task of imaging the geothermal system was aided by its occurrence in and beneath a sub-horizontal
610-metre thick sequence of lacustrine and volcanic deposits with minimal vertical fault displacements.
This originally (pre-geothermal) laterally homogenous strata presented an optimal geologic environment
in which to record the localized overprint of argillic and silicic hydrothermal alteration and outflow of
geothermal fluids through relatively permeable sedimentary units. As such, the MT depth section across
the Soda Lake Operation depicts the expression of the known upper geothermal resource with good
fidelity. The lowest resistivity values of 1.0 to 1.5 ohm-metres are associated with geothermal fluid flow
into the highest permeability strata above a depth of approximately 243.8 metres. The conductive
side-lobes between depths of approximately 243.8 to 548.6 metres are interpreted to mark outflows from
possible deeper resources sources (out of the MT cross-section plane) which have been additionally
characterized by favorable magnetic, gravity anomalies and proximity to elevated temperatures and
thermal gradients. Deeper conductive anomalies at depths between approximately 1,524 and
2,133.6 metres suggest possible core thermal sources which are future investigation targets.
Heat Flow and Inferred Heat Source
The thermal component of the hydrologic system originates from deep convective flow that brings hot
water up from depths of perhaps two or three miles in the Carson Desert basin, where it mixes and flows
laterally along the regional groundwater gradient to the north northeast. Vertical movement from depth is
likely facilitated by either up-dip flow in permeable stratigraphic horizons, or flow along faults, or a
combination of the two.
Deeper Subsurface and Well Discharge Data
Deep Wells
A well drilled as a potential producer or injector well is considered to be a “deep well,” regardless of the
actual depth. The focus of the following is mainly on the active deep wells in the Soda Lake Operation.
All wells were rotary-drilled and cuttings were collected and analyzed by many different individuals
throughout the developmental history of the field. As a result, questions remain about nomenclature and
stratigraphic correlation to mapped units in the region.
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Numerous temperature and pressure logs have been run in most wells at the Soda Lake Operation.
Flowing and/or injecting spinner logs have been run in some wells.
Several different types of geophysical logs have been run in some of the wells at the Soda Lake
Operation. Wellbore image logs and other geophysical logs have been run in the two new wells drilled by
Magma.
Drilling and temperature data show that thermal waters with temperatures above 187.8°C are found at
shallow, intermediate and deep levels at the Soda Lake Operation. The shallow thermal system is found
within the Quaternary section from just below the surface at the old steam vent to a depth of
approximately 305 metres. The 41-33 and 41A-33 wells produce from this shallow thermal aquifer, and
injection wells 77-29 and 87-29 dispose fluid into it.
An intermediate aquifer is found in the northern part of the field, at a depth of approximately 610 metres,
within the shallower tuffs and basalts of the Tertiary section. Only injection well 45-28 has directly
utilized this aquifer.
The deep aquifer lies between 975.4 and 1,280 metres in the southeastern part of the field. It is indicated
primarily by the lowering of temperature gradients relative to the overlying section. Although not
confined to a single horizon or unit within the Tertiary section, this aquifer is (or has been) tapped by
several wells.
Multi-Well Interference Tests and Tracer Tests
The only multi-well interference tests conducted at the Soda Lake Operation involved flowing and
monitoring the 84-33 and 77-29 wells in the early 1980s; at that time, they were the only deep wells in
existence. These tests were relatively short and reportedly showed some pressure declines in the wells
being used for observation purposes and poorly defined pressure recoveries. Once the Soda Lake 1 power
plant began operating in 1987, the opportunity to perform simple interference tests involving new wells in
a static reservoir was lost.
In 2009, we conducted a tracer test involving the four active injection wells and the four active production
wells. This has demonstrated the hydraulic connections between various pairs of injection and production
wells. Four different high-temperature naphthalated sulfonate tracers developed at the Energy and
Geoscience Institute were injected into wells 77-29, 87-29, 81-33, and 45-28 (the last, which has been
used very intermittently since the beginning of 2003, was returned to service solely to perform this test).
Samples were collected from all four operating wells for tracer analysis and the sampling is ongoing. In
addition, well 45A-33 was sampled during its short-term flow testing operations on two occasions, and
these samples were analyzed for tracers.
In general, the tracer testing showed rapid fluid movements in the north-south direction but much less in
the east-west direction. The tracer injected into well 81-33 (which was accepting injection fluid at a rate
of approximately 63.1 litres per second) returned to the 84A-33 and 84B-33 wells within four or five
days, with a sharp peak return at 30 to 40 days. The tracer injected into well 81-33 did not appear in the
32-33 or 41A-33 production wells to the west.
The tracer injected into well 45-28 (which was accepting injection fluid at a rate of only a few hundred
GPM appeared in production well 41A-33 after four to five days. This confirmed that the cooling in
production well 41A-33 has been caused largely by injection returns from well 45-28. The tracer injected
into well 45-28 took 29 days to first reach the 32-33 production well. This was the longest initial return
time seen in any of the tracer tests and indicates that injection into well 45-28 has not been the principal
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cause of the modest cooling seen in production well 32-3 3. The tracer injected into well 45-28 first
appeared at very low concentrations (less than 0.25 parts per billion) in wells 84A-33 and 84B-33 after
20 days. It is unclear if this small amount of tracer travelled directly through the reservoir or if
“recycling” through the combined injection system provided more circuitous and indirect path.
The two tracers injected into wells 77-29 and 87-29 generally behaved in an identical manner: each took
15 days to initially reach well 32-33 and 29 days to reach well 41A-33. Neither of these tracers has yet
been detected in the 84A-33 or 84B-33 wells. This indicates that injection wells 77-29 and 87-29 have
relatively slow communication with the production wells, and therefore are not the cause of the large
cooling trend observed at Soda Lake. They probably have had some impact on the modest cooling trend
observed in production well 32-33, and may be responsible for some of the cooling seen in production
well 41A-33.
Fluid Chemistry
The Soda Lake Operation has never included a program of regular, repeated fluids sampling, but some
data from initial well tests are available, two wells were sampled by the USGS in 2008 and all of the
production and injection wells were sampled in late 2009.
The reservoir water has a moderately saline sodium-chloride composition that is common in the highesttemperature geothermal fields of western Nevada. Among major species, the highest concentrations
exceed the lowest by about 20%. This range is relatively small and suggests some homogenization of the
reservoir by injection that circulates back to production.
The water has low corrosivity. It will deposit calcite scale if allowed to boil but will deposit silica scale
only if cooled to below about 90°C. Production well 32-33 is treated with a carbonate scale inhibitor to
prevent pump scaling; no other wells receive the same treatment.
Production, Injection and Power Generation
The Soda Lake Operation is comprised of two power producing facilities that generate power from hot
water using a binary technology system. Soda Lake Unit 1 and Soda Lake Unit 2 have a total installed
gross nameplate capacity of 23.1 MW. Soda Lake Unit 1 is a binary power plant and is equipped with a
water cooled condensing system. Soda Lake Unit 2 is a binary power plant and has an air cooled
condensing system.
Production/Injection History
The total production rate to the plant has declined gradually over time at the approximate rate of
1.39 litres per second. As the production wells at the Soda Lake Operation are pumped it is difficult to
determine how much of the flow rate decline is due to any overall reservoir pressure decline, localized
pressure declines near individual wells, and/or declining performance of the production well pumps. The
pump in well 84B-33 is reaching the end of its useful life in 2010 and the pump in 32-33 is near the
anticipated end of its life (but still performing well). Magma is confident the decline over the last two
years has been almost exclusively due to the failing pump in 84B-33, and that replacement of this pump
will result in an improvement of overall production by approximately 25.2 litres per second.
At present, four production wells supply the plant at an average rate of approximately 69.4 litres per
second per well. As of late March 2010, individual wells were producing at rates ranging from
approximately 31.6 litres per second to almost 126.2 litres per second per well.
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The combined produced fluid has undergone continuous temperature decline since early 1994; this overall
decline rate of up to 1.1° to 1.7°C per year is high compared to similar geothermal fields elsewhere.
Cooling rates for individual wells have been as variable as 3.3°C per year in well 41A-33 during the late
1990s to little or no recent cooling trend in the other three active production wells or even an increase in
temperature in well 84B-33 as its flow rate has declined due to an aging pump.
Power Generation History
There are annual fluctuations in both gross and net generation due to ambient temperature variations;
generation peaks in mid-winter and declines to its lowest level each year in mid-summer.
Between 1995 and 2009, the total generation at the Soda Lake Operation declined steadily at a rate of
350 kilowatts per year. This decline stopped (at least temporarily) in 2009 with the refurbishment of the
power plant.
At the Soda Lake Operation, the nominal 2.5 MW production pump load is supplied by Soda Lake Unit 2.
Accounting for this fixed pump parasitic load, an internal variable parasitic load for the Soda Lake Units
1 and 2 power plants was calculated to be 10.5% of the gross power generated. These results indicate that
the internal plant parasitic load has remained essentially constant over the past nine years.
Power Generation Efficiency
GeothermEx has assessed the power generation efficiency at the Soda Lake Operation from its power
generation history. The conversion efficiency at the Soda Lake Operation reflects the annual fluctuations
in the ambient temperatures, which is particularly typical of air-cooled plants. Soda Lake Unit 2 shows
lower conversion efficiency than Unit 1 mainly because the former supplies the parasitic power for the
plant. The conversion efficiency of both units has been declining reflecting the cooling of the produced
fluid, the rate being higher for Unit 2, which is supplied by the 41A-33 well which has the highest cooling
rate of the four production wells. In 2009, the conversion efficiency of Soda Lake Unit 1 showed a sharp
increase both due to the plant refurbishment and a trend of stabilized to increasing temperatures in wells
84A-33 and 84B-33 which supply Unit 1. Unit 1 has a conversion efficiency comparable to other
geothermal binary power plants.
Resource Model and Properties
Conceptual Model
The Soda Lake wells exploit geothermal fluids from deep, intermediate and shallow parts of the overall
reservoirs. Based on a combination of geophysical log correlation, subsurface temperature distribution
and gravity data, fluid is provided to the thermal aquifers beneath the Soda Lake Operation area via updip flow from the east within a permeable unit in the lower part of the Truckee Formation. One of the
main lines of evidence for this model is the similarity between the shape of the isotherms on the east side
of the field with the orientation of the lithologic units.
Numerical Model
Since the production and injection are essentially balanced and the temperature decline trend has been
relatively steady for many years in this field, a numerical model of the reservoir was developed based on
energy balance.
- 47 -
The numerical model can be used to forecast cooling of the produced fluid under the present
production/injection strategy.
Nature of Geothermal Resource
Geothermal energy is such that geothermal reserves and resources do not decline if managed in a
sustainable fashion. There can be a temperature decline in an area of a well site (which will eventually
reheat), but new wells can be drilled in the general area to re-establish generation levels.
After 30 years of operations, the Company will likely be required to upgrade the current plants or build a
new plant at the Soda Lake Operation, but will still have access to the geothermal resource. While a
temperature decline at the current wells at the plants is noted, future drilling of new wells would be
conducted to make up for the loss in temperature. The Company anticipates making use of improved
geothermal technology and efficiencies in the future to increase plant capacity, even at lower
temperatures in the wells. As well, with possible new reservoir management processes, the balance
between injection and production wells operation may be able to halt or even reverse the temperature
decline that has been recorded.
Abundant geothermal resources exist at the Soda Lake Operation, as calculated from the reservoir model.
These resources can be tapped into via new wells and by improved balancing between injection and
production wells to operate the plant indefinitely. As the Soda Lake Operation has approximately 100
unique well locations that penetrate the subsurface, a high degree of confidence is assigned to the
geothermal resources category (indicated resources under the Canadian Code). The well locations consist
of a variety of production and injection wells, temperature gradient holes, slim holes and observation
wells, among others.
Furthermore, as new, low temperature technology is commercialized that allows for greater resource
recovery, the plant may be able to tap into more of the geothermal resources that are currently not
recorded as a geothermal resource according to the Canadian Code.
Geothermal energy is defined as a renewable energy source by many jurisdictions including the Canadian
and U.S. governments. As such, production over an indefinite period of time is a requirement of the
“renewable” classification.
Estimated Geothermal Resource and Reserve
Data Integrity and Interpretation
Considering that resource estimation relies on estimating the heat-in-place, the most important
information for evaluating the geothermal resource is the database of downhole temperature surveys from
the many wells drilled in the field. Multiple temperature surveys have been obtained from the wells in the
field. These have been carefully reviewed by Magma. On the basis of their review of the subsurface
temperature profiles, Magma selected a temperature profile for each well that represents the static
formation (initial state) temperatures in the vicinity of the well. Magma used this subset of the subsurface
temperature database to develop a temperature model of the field.
GeothermEx was provided with the raw data files of temperature vs. depth for each well, documentation
describing how the representative static profile was determined for each well, and the temperature model
that resulted from that selection. Using this temperature model, Magma also provided maps of
temperature distribution at 152.4 metre depth intervals.
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GeothermEx evaluated: the temperature profiles; Magma’s process of selecting the representative profile
for each well; the representation of the selected profile in the temperature model; and the resulting
temperature contour maps from the model. All of these were found to be internally consistent. Further,
the methodology used to determine which profile best represents static formation temperatures was
consistent with current practice by experienced geothermal geoscientists and with GeothermEx’s
understanding of the Soda Lake Operation. Therefore, this subset of the temperature database was used to
estimate the resource at the Soda Lake Operation.
Reserve and Resource Estimate
The Canadian Code does not specify what the reference temperature should be. GeothermEx assumed a
reference temperature of 71.1°C, which is the average temperature of the injection water at Soda Lake.
GeothermEx used the three-dimensional temperature distribution in the subsurface as estimated by
Magma between depths of 305 and 1,524 metres, (the latter being the deepest level with good control on
temperature). Below 1,524 metres, GeothermEx assumed the temperature distribution at 1,524 metres
continues to a depth of 2,743.2 metres, which is slightly deeper than the deepest well drilled to date.
Based on the Canadian Code, GeothermEx believes it is justified to refer to the heat resource at
temperatures of 148.9°C or greater between 305 and 1,524 metres depth as proved reserve and that
between 1,524 and 2,743.2 metres as the indicated resource.
This results in a proved reserve of 44,433 MW thermal years, and an estimated additional indicated
resource of 89,153 MW thermal years. 2,154 MW thermal years have already been produced from this
field, which is a relatively insignificant amount (on the order of 1%) of initial thermal energy in place.
MW thermal years
MW electrical (net)1
Heat in Place
(petajoules)
Proved Reserve
44,433
14.2
1401.2
Indicated Resource
89,153
28.5
2806.5
Classification
_______________________
Note:
(1)
Assuming 12% recovery factor, 8% conversion efficiency and a 30-year project life.
For further information on the estimated geothermal resource of the Soda Lake Operation, see tables 8.1
and 8.2 of the Soda Lake Report.
Thermal Energy Recovery Factor
Based on GeothermEx’s experience, they have historically assumed a thermal energy recovery factor of
5% to 15%, and sometimes up to 20%. However, given the long operations history of the Soda Lake
field, it is possible to estimate a range of plausible values of recovery factor from the production/injection
records and the numerical model.
The cumulative thermal energy produced from the field to date is 68 petajoules.
Magma believes this is not truly a representative model since well 45A-33 will be the highest temperature
well in the field (196.1°C). Since this model does not take into account production from this well, the
model may be conservative.
Running a plant at 60% higher than the current production level reduces the production temperature to
approximately 128.3°C in 30 years (assuming that no hotter fluids are introduced). Since power
- 49 -
generation is possible from fluids even cooler than 128.3°C, it should be possible to produce at a higher
rate such that over a 30-year plant life, the produced fluid temperature reaches the lower limit of power
generation. A typical binary plant would require at least 27.8°C differential between the inlet and outlet
temperature to supply the parasitic load. Given an injection temperature in the 71.1°C range,
GeothermEx believes an absolute power generation limit would be reached when the produced fluid
temperature drops to about 98.9°C. For all practical purposes, a temperature limit of 100°C has been used
for this analysis because it is the boiling point of water at normal atmospheric pressure.
By iterative forecasting from the numerical model, GeothermEx believes that a production temperature of
100°C is reached over a 30-year plant life if the current production rate is increased by 380% (which is
not currently being proposed).
The maximum theoretically (but not necessarily practically or economically) recoverable thermal energy
from this field, under the present production/injection scenario is 258 petajoules, which includes what has
been recovered to date and what can be recovered over the next 30 years. This maximum recoverable
thermal energy from this field is the equivalent of 8,163 MW thermal per year. Given that the total
thermal energy-in-place, including both the proved reserve and indicated resource, is 133,586 MW
thermal per year, the recovery factor is 8,163/133,586, that is, 6.1%. On the one hand, it is possible that
the energy recovered under the present production/injection strategy would come only from the proved
reserve base (44,433 MW thermal years). In this case, the recovery could be as high as 8,163 MW
thermal years divided by 44,433 MW thermal years, that is, 18.4%. Therefore, the estimated range of
recovery factor for this field is 6.1% to 18.4%. It is noted that this range is close to the 5% to 15%
GeothermEx commonly use for projects without an actual operational history. For the purposes of this
assessment, GeothermEx assumed an intermediate value of 12% for the recovery factor.
Recoverable Electric Energy
The Canadian Code emphasizes that, where practical, the resource base should be reported in terms of the
equivalent electric power capacity (MW electrical) for a given project life.
A conversion efficiency on the order of 8% is the maximum possible at the Soda Lake Operation, because
future cooling of the produced fluid will reduce conversion efficiency assuming that the current
operational strategy is employed and no, new hotter wells are incorporated into the facility. Using a
recovery factor of 12% and a conversion efficiency of 8%, the equivalent power capacity for a 30-year
project life for the proved reserve is 14.2 MW electrical (net) for a 30-year plant life.
Magma has estimated that based on a forecast of the decline trend in power capacity for such a plant
(14.2 MW electrical net initially), the project would remain economic. Therefore, as per the Canadian
Code, the proved reserve at the Soda Lake Operation is 14.2 MW electrical (net). Additionally, the Soda
Lake Operation has indicated resources of 28.5 MW electrical (net).
Economic Analysis
The Soda Lake Operation was acquired by Magma for a total cost of $17,000,000 in October 2008. The
estimated capital cost of the phase 1 program is $25 million.
The proposed improvements at the Soda Lake Operation, combined with an all-in blended target PPA
price of $85 per MW hour (PPA is currently under re-negotiation) will result in favorable economics and
positive cash flow for Magma at the Soda Lake Operation. The most significant incremental benefit is
achieved by increasing access to the thermal reservoir. Additional efficiency and plant infrastructure
improvements will be implemented so as to continually increase the net energy delivered to the grid.
- 50 -
Favorable project economics are further realized from the sale of Portfolio Energy Credits (“PECs”)
respecting the parasitic consumption of the Soda Lake Operation which have been historically sold to
Nevada Energy. The Company will continue to study the growing market for PECs in order to ensure the
best available price is achieved.
In addition to the PECs, the Emergency Economic Stabilization Act of 2008 and the American Recovery
and Reinvestment Act of 2009 (“ARRA”) has created incentives in the renewable energy sector in the
form of extensions to existing production tax credits (“PTCs”), investment tax credits and a new Energy
Grant program. Magma is actively engaged in the analysis of these credits and grant programs to
determine the net benefits to the proposed Soda Lake improvements.
Conclusions and Recommendations
A thermal-to-electrical energy conversion efficiency on the order of 8% is the maximum possible at the
Soda Lake Operation, because future cooling of the produced fluid (under the present operation/injection
strategy) will reduce conversion efficiency. Using a recovery factor of 12% and a conversion efficiency
of 8%, the equivalent power capacity for a 30-year project life for the proved reserve is 14.2 MW
electrical (net) and 28.5 MW electrical (net) for the indicated resource. Magma has estimated that based
on a forecast of the decline trend in power capacity for such a plant, the project would remain economic
over a 30-year plant life.
Therefore it is concluded that the Soda Lake geothermal field is classified as containing economically
recoverable proved reserves of 14.2 MW electrical (net) and 28.5 MW electrical (net) of indicated
resources for 30 years, relative to the operational parameters of the Soda Lake Operation.
The forecast from the numerical model shows a decline in net energy production of approximately 1.4%
per year based on the present production rate and production/injection strategy.
A thorough analysis of all production histories (including pump performance), injection histories and
tracer test data is required to understand the precise reasons for cooling and what mitigating steps can be
taken. GeothermEx believes that further development at the Soda Lake Operation needs to be considered
by a detailed numerical simulation model of the field. Such a model should be developed and calibrated
against the initial (pre-exploitation) state of the field, the entire history of production and injection history
over the last 23 years, and the recent tracer testing results. This will also require a careful analysis of each
well’s production performance, taking into account the operation and characteristics of the pumps. This
calibrated model should be used to forecast future well and reservoir behavior under a number of different
plausible production/injection scenarios. Through this process, it should be possible to arrive at both a
mitigation program and a determination of the feasibility of capacity expansion.
Increasing the level of production from the Soda Lake Operation and sustaining it over the long term will
require drilling step-out wells to discover additional resource areas. As described above, the small
exploitable volume demonstrated to date must be increased to enable a higher capacity to be realized.
McCoy Property
The following is a description of the McCoy Property. Certain statements in the following summary of
the McCoy Property are based on and, in some cases, extracted directly from the McCoy Report prepared
on behalf of Magma by Dr. J. Douglas Walker (Ph.D.), who is independent from the Company. See
“Scientific and Technical Information”. Reference should be made to the full text of the McCoy Report
which is available for review on SEDAR located at www.sedar.com.
- 51 -
Property Area
The McCoy Property is located in Nevada 50 kilometres northwest of the community of Austin, Nevada,
and straddles the boundary between Churchill County on the west and Lander County on the east. It
consists of a total of 4,621 hectares (11,418 acres) covering more or less contiguous sections of land.
Nature and Extent of Title and Term of Acquisition
The McCoy Property consists of four BLM leases. The lands were acquired by the Company at a lease
auction conducted by the BLM in August 2008. The purchase price for the McCoy Property was
$7,318,005. Since acquisition, a portion of the original McCoy Property representing approximately
4000 acres has been relinquished. The primary lease term for the property is ten years with the possibility
of three additional five-year extensions. If a commercial well is drilled on the property, then the acreage
can be converted to “held-by-production” status, which continues for as long as the property produces
geothermal fluids. For a description of the terms of the BLM leases that comprise the McCoy Property,
see “United States Geothermal Leases”.
Location of Known Geothermal Resource Occurrences
There are no surface hot springs, fumaroles, or mud pots within the boundary of the McCoy Property.
However, compelling surface manifestations of earlier hydrothermal and geothermal activity have been
observed. Surface manifestations of underlying geothermal resources at the McCoy Property are limited
to hydrothermal alteration which is largely confined to the Wild Horse and McCoy mine areas. The two
mines are located within 1.5 kilometres of each other, both within the boundaries of the McCoy Property.
Environmental Issues and Permitting Requirements
The proposed exploration and development work at the McCoy Property will be subject to local, state,
and federal regulations dealing with operational standards and environmental protection measures such as
cultural resources, rare and endangered species, clean water and air, and use of hazardous materials.
Initial exploration will consist of geophysical, geological, and geochemical activities that are categorized
as “Casual Use” under BLM regulations, thus no permits or environmental clearances are required. Later
stages of exploration will include 3D reflection seismic data acquisition.
Activity on federal leases that results in disturbance of the surface (i.e., road building or drilling) will
require reclamation bonding and compliance with BLM regulations governing mineral lands and mining.
We have posted the required $50,000 bond to secure the necessary permits. Completion of the permitting
process will also require an environmental assessment, a formal consultation with Native Americans and
a review of the proposed plans by the State Historic Preservation Office on protection of cultural
resources.
The McCoy Property lies in the southwestern part of the Augusta Mountains at elevations ranging from
1,250 to 1,750 metres (approximately 4,100 to 5,750 feet) above sea level. Topography varies from
steep-sided, alluvium-filled valleys, to rolling hills, to broad, flat alluvial valleys. Streams are ephemeral
and there are no standing bodies of water within the prospect area.
- 52 -
Means of Access
From Winnemucca, Nevada, the McCoy Property is accessible by traveling south on NV294, Grass
Valley Road, south through the McCoy Ranch to Jersey Valley Road. The total distance is approximately
130 kilometres. It is also accessible from the south via U.S. Highway 50 to a secondary road at the
Overland Stage Station at New Pass in eastern Edwards Creek Valley. The property is located
22 kilometres north of that junction. There are two small landing strips in close proximity to the prospect
area: one at the Swanson Ranch ten kilometres east of the property and one at Dixie Valley 25 kilometres
to the west.
Sufficiency of Surface Rights and Infrastructure
Access is not anticipated to be an issue as all of the geothermal leases comprising the McCoy Property are
100% BLM ownership for surface and subsurface minerals. There is no power transmission
infrastructure in the immediate property area, but the site is 25 kilometres from a north-south 230 kV
transmission line in Dixie Valley that has approximately 50 MW of capacity available. There is also an
east-west 230 kV transmission line with excess capacity that runs parallel to U.S. Highway 50,
22 kilometres south of the project area. The relatively flat terrain and largely uninhabited spaces should
pose no difficulties in permitting and constructing a tie to economic transmission line installation.
History
The general region has been the locus of prospecting and mining of mostly precious metals throughout the
latter part of the 19th century, through the 20th century, and into modern times, although little scientific
work was done in the area of the McCoy Property prior to 1942. An investigation of the strategic
minerals of this area was initiated by the USGS after the establishment of the McCoy and Wild Horse
Mercury mines in 1916 and 1939, respectively.
Geological Setting
The McCoy prospect area lies within the Basin and Range geomorphic province of the western United
States. The northern portion of this province, which extends from western Utah, through northern
Nevada, and into eastern Oregon and northeastern California, is characterized by widespread (mostly)
east-west extension and crustal thinning that has been ongoing since the middle Miocene (~17 mega
annum, “Ma”). Today this province consists of a series of mountain ranges and intervening basins that
are, for the most part, oriented a few degrees east of north.
The Basin and Range, or Great Basin as it is sometimes known, was the locus of deposition of major
sedimentary units throughout the latest Precambrian, Paleozoic, and early part of the Mesozoic eras.
Volcanic rocks were erupted in the western part of Nevada mostly during the latter part of the Mesozoic
era. There were three major periods of orogenic activity that affected Nevada: the Antler Orogeny (last
Devonian early Mississippian), the Sonoma Orogeny (late Permian-early Triassic), and the Sevier
Orogeny (late Cretaceous). All of these orogenies basically consisted of east-west contraction resulting in
widespread folding and east vergent thrust faulting.
At approximately ten Ma, a broad belt of north-northwest-trending strike-slip deformation, called the
Walker Lane, was initiated along the western margin of the Basin & Range. This faulting also continues
today, defines the boundary of the Basin & Range, and greatly influences structure and tectonics within
the province.
- 53 -
The Basin and Range province is characterized by elevated levels of terrestrial heat flow resulting from
the widespread crustal extension and thinning. There is a broad region in northern Nevada, the Battle
Mountain High, where heat flow values exceed 100 milliwatts per square metre (“mW/m2”). These
values are as much as 50% higher than the rest of the province. Heat flow values of this magnitude
translate into geothermal gradients in excess of 75ºC per kilometre; local geothermal gradients within this
area have been reported to be greater than 200ºC per kilometre. This is also the locus of numerous
geothermal prospects and producing properties where production depths range from a few hundred metres
to as much as 2.5 kilometres.
Local Prospect Geology
The local geology at the McCoy Property consists of thick sequences of limestone, dolomite, shale,
conglomerate, and sandstone ranging in age from Pennsylvanian-Permian overlain by Triassic age
carbonates. The Paleozoic sequence was tightly folded and thrust over contemporaneous rocks during the
Sonoma Orogeny. Triassic rocks were mildly tilted and folded prior to late Mesozoic and Cenozoic
deformation. Middle-to-late-Oligocene and earliest Miocene silicic to intermediate tuffs and flows
overlie the Paleozoic-Mesozoic complex and account for more than 70% of the rock outcrops in the
McCoy Property. As mapped, all rocks are cut by anastomosing high-angle normal and oblique-slip
faults that trend north-south throughout the area. The fault pattern is, however, complicated by shorter,
northeast-trending faults that link the major structures. In addition, there must be important northeasterly
trending faults that transect the southern part of the area that bound the Edwards Creek Valley.
There is evidence in alluvial fans of Quaternary, and possibly Holocene, faulting in the McCoy Property.
The most recent, large-scale seismicity in the area was in nearby Dixie Valley, north-west of the
McCoy Property, where a series of magnitude six and seven events in 1954 resulted in more than four
metres of horizontal and three metres of vertical offset on the southwestern side of valley. Recent studies
of seismicity suggest that faults in the McCoy Property have a small right-lateral component in addition
to their nearly vertical, normal offset. This could be significant in terms of providing permeability and
maintaining fractures in reservoir rocks.
Hydrogeochemistry and Geothermal Resource Potential
Fluid geochemistry and temperature data from the McCoy Property area are consistent with a medium-tohigh grade geothermal resource with commercial electrical generation potential. Thermal waters in the
McCoy Property are high in sodium (200-250 parts per million, “ppm”) and potassium (greater than
15 ppm) with low chloride bicarbonate (“Cl/HCO3”) ratios. Based on geothermometer calculations using
the dilution-corrected model, the minimum equilibration temperature that can be anticipated from the
geothermal reservoir at the McCoy Property is 186oC. The thermal structure of the area supports this
contention. See “– Exploration – Discussion and Interpretation of Exploration Data: Reservoir Potential”
below.
Exploration
No exploration work has been done by, or on behalf of, the Company, but a significant effort was made
by AMAX Exploration, Inc. (“AMAX”), in the period 1979 through 1982. As part of their geothermal
evaluation of the McCoy Property, AMAX drilled 52 shallow temperature gradient holes ranging in depth
from 30 metres to 100 metres; two intermediate depth exploration wells (66-8 to 765 metres, and 14-7 to
613 metres); and three intermediate depth thermal gradient wells (25-9 to 610 metres, 38-9 to 620 metres,
and 28-18 to approximately 600 metres). Core and drill cuttings for the deeper holes and some of the
shallow ones are available for examination at the University of Utah, Energy & Geoscience Institute in
Salt Lake City. In addition, AMAX performed geophysical, geochemical, and geological surveys on the
- 54 -
McCoy Property in the late 1970’s and early 1980’s and formed a geothermal development unit
consisting of 15,135 hectares (37,417 acres). AMAX let its interest expire during the weak energy market
period in the mid-1980’s.
Geophysical Surveys
Four geophysical surveys were conducted by AMAX using gravity, aeromagnetic, MT and resistivity. In
addition, Lawrence Berkeley National Laboratory (“Lawrence Berkeley”) personnel conducted a
resistivity survey using the EM-60 frequency domain system on the McCoy Property.
In 1979 Microgeophysics Corporation and AMAX conducted a gravity survey of the area consisting of
340 stations. The resulting complete Bouguer gravity map shows 10 to 15 milligal lows associated with
alluvium-filled basins and 20 to 25 milligal highs associated with outcrops of Paleozoic and Mesozoic
basement rocks. There was no apparent attempt to jointly invert the gravity data with any of the other
geophysical data sets to constrain possible interpretations.
Aeromagnetic data were acquired over the entire prospect, although no specifications related to how the
data were acquired and processed have been found. While the residual magnetic intensity plot shows
nothing remarkable as regards the presence of a geothermal resource, it clearly mirrors the gravity data in
defining rocks of different ages and possibly different degrees of induration.
The MT and resistivity data were acquired by Terraphysics and Mining Geophysical Survey, Inc.,
respectively. Results from both confirm the existence of a relatively deep-seated resistivity low that
coincides with the locus of high temperature gradients derived from drilling and logging. Resitivities as
low as one ohm per metre were recorded for depths of five kilometres, and could reflect hot fluids in
permeable rocks, high temperature, and/or partial melt. One-dimensional models of the MT data show
that matches were achievable only by including lower resistivities moving up a sharp electrical
discontinuity presumed to be a fault. This low resistivity zone coincides with a measured temperature of
85.7°C at a depth of 755 metres in well 66-8. The electromagnetic frequency domain data acquired by
Lawrence Berkeley essentially confirms the results of the MT and resistivity surveys.
Geochemical Surveys
Mercury is commonly associated with hydrothermal systems and has been used in detecting leakage from
geothermal reservoirs in numerous systems. Mercury is highly mobile because of its volatility, thus it can
rise in gaseous form through faults and fractures, and be trapped on fine-grained sediments at shallow
depths. In 1979, the University of Utah conducted a geochemical sampling and analysis of cuttings from
varying depths in 35 drill holes at the McCoy Property for common metals associated with geothermal
systems (Hg, As, Pb, F, and Zn). The isopleth contours for mercury at the McCoy Property are elongated
in a north-south direction mimicking fault orientation in the area. There are also three loci for mercury
concentrations that correspond with the highest temperature gradients and electrical anomalies determined
from geophysical methods.
Discussion and Interpretation of Exploration Data: Reservoir Potential
Results from the survey work conducted by AMAX and others at the McCoy Property are consistent with
the presence of an active geothermal system with economically viable temperatures at depths that permit
exploitation at reasonable cost. Geophysical, geochemical, and temperature data indicate three centres for
fluid upwelling covering nearly 90% of the prospect area. The geothermal reservoir is considered to
extend over a distance of nearly 16 kilometres in a north-south direction and eight kilometres in an eastwest direction.
- 55 -
Temperature gradients were measured in 52 shallow drill holes (30 to 100 metres) located throughout the
project area. Values ranged from 28°C per kilometre to 522°C per kilometre. AMAX applied a depth
extrapolation model to the shallow temperature gradient data to project the extent of the 200°C at a depth
of two kilometres. The figure below shows the results of that extrapolation with the 200°C isotherm
covering more than 12,140 hectares (30,000 acres). For comparison, worldwide geothermal gradients
made on continental crust average 25°C per kilometre and range from 8°C per kilometre to 50°C per
kilometre. In addition, exploration and temperature gradient wells have measured temperatures of 45°C
to 102°C at a depth less than a kilometre. This attests to the presence of significant geothermal waters
under the lease area.
Heat flow measurements range from 38 to 960 mW/m2, and define three separate high heat flow zones.
The range of heat flow values for “normal” continental crust is 32 mW/m2 to 80 mW/m2 or 0.8 heat flow
unit (“HFU”) to 2.0 HFU. The worldwide average heat flow through continental crust is 50 mW/m2. The
southernmost high heat flow area is also the largest with approximately 3,500 hectares inside the
400 mW/m2 (ten HFU) contour. It is elongated in the north-south direction extending more than twothirds of the way across the prospect. The maximum heat flow of 960 mW/m2 occurs in the southern part
of the anomaly. The second highest heat flow locus located directly over the McCoy mercury mine
covers approximately 400 hectares within the 400 mW/m2 (ten HFU) contour and reaches a high of
greater than 560 mW/m2 (14 HFU). The third highest heat flow area is located in the north-west part of
the prospect centred on the hole-in-the-wall well No. 2. It covers approximately 500 hectares within the
400 mW/m2 (ten HFU) contour and reaches a high of greater than 640 mW/m2 (16 HFU).
The intense and complicated faulting in the area very likely controls permeability within the geothermal
reservoir. AMAX found that there were numerous fluid entries in the holes that they drilled, and that the
most intense fracturing was in the areas where surface fault traces were common. Based on geochemical
and drilling results, it is anticipated that reservoir temperatures should be in the range of 150°C to 200°C
at depths of 2.0 to 2.5 kilometres.
Nearby Geothermal Properties
There are no geothermal properties immediately adjacent to the McCoy Property. However, a number of
geothermal development projects and hot springs areas are in the general vicinity. Some of these are:

Dixie Valley (25 kilometres west north-west of the lease area) has a producing 60 MW dual
flash-type geothermal facility with producing temperatures in excess of 230°C. There are
numerous other hot springs (e.g., Sou Hills, Dixie Meadows, and Hyder) with temperatures
ranging from 55 to 80°C;

Jersey Valley (30 kilometres north-west of the lease area) has reported hot springs with
temperatures of 55°C. Ormat drilled two holes in Jersey Valley as part of their exploration
efforts on BLM leased lands under their control. They reported maximum downhole
temperatures in the 176°C range;

Reese River Valley (55 kilometres north north-east of the lease area) with reported hot spring
temperatures as high as 54°C. Sierra Geothermal Power Company is exploring this
BLM lease and has drilled three exploration holes to date. No results of those wells have
been published; and

Smith Creek Valley (48 kilometres south of the lease area).
- 56 -
Resource Estimate
As there has been no deep resource evaluation drilling or reservoir testing to date at the McCoy Property,
no reliable resource estimate is possible at this time. However, probable reservoir production capability
can be estimated based on the projected area of the 200°C isotherm at a depth of 2,000 metres.
An estimate of the resource potential for the McCoy Property has been prepared by GHA using the
volumetric estimation method developed by the USGS modified to account for uncertainties in some
input parameters. For a description of this methodology see “Overview of Volumetric Resource Estimate
Methodology”. This method yields estimated MW generation capacities of P90 = 80 MW for the
McCoy Property. Geothermal resources and probabilistic estimates of gross MW capacity have a great
amount of uncertainty as to their existence and as to whether they can be accessed in an economically
viable manner. It cannot be assumed that all of, or any part of, a geothermal resource will be
commercially extracted or that estimates of MW capacity will be achieved.
Recommended Exploration Program
Based on the technical data presented herein and additional backup data, it is reasonable to conclude that
there exists a substantial, but unquantified geothermal resource beneath the McCoy Property.
Temperature gradient, geochemical, and geophysical data are consistent with source fluid temperatures in
the 150°C to 200°C range at depths of 2.0 to 2.5 kilometres below the surface. Temperatures in this range
are commercially attractive for generating electricity using the single or double-flash technology.
There are no apparent environmental or administrative barriers to development of the resource. The
Nevada State Office of the BLM has an aggressive program of renewable energy development that
includes consolidated and expedited permitting mandates. Although there is an absence of productiontype data that could underpin a detailed economic analysis of the McCoy Property, a diligent exploration
program, including drilling, is warranted by the results of the technical studies to date.
We are evaluating the data described in the McCoy Report, the data found in the sources cited therein,
unpublished exploration data and databases located at the University of Nevada, Reno and the Nevada
Division of Minerals. The likely resource delineation program will include acquisition of 3D reflection
seismic data over the McCoy Property in order to define the fault and fracture system followed by in-fill
gravity, magnetics, and electrical field surveys. This data will be modeled using 3D analysis and
visualization techniques to select locations for drilling two to four intermediate depth (1,000 to
2,000 metres) slim holes from which flow tests will be conducted. Because of the large number of
shallow temperature gradient holes already available in the area, it is unlikely new shallow holes will
be drilled.
An MT survey has recently been completed at the McCoy Property and the results are currently under
review.
Further delineation of the resource requires integration of the available geologic mapping data with
subsurface information. This information is partially provided by gravity, magnetic, and MT data. In this
region the most reliable method for obtaining such information is 3D seismic reflection. This is a higher
cost exploration method that builds on the previously collected data.
The final critical data collection is the direct observation of temperature, rock, and chemical environments
in the resource. This data can only be obtained by drilling exploration holes followed by sampling and
logging. This is best accomplished through slim holes drilled based on the results of the exploration data
described above (gravity, magnetics, MT, geology). Drilling represents approximately 75% of the
- 57 -
estimated exploration budget at the McCoy Property. A determination to proceed with drilling and the
location of any proposed drill sites will be guided by the less expensive exploration activities described
above.
The process of obtaining the necessary environmental studies required to obtain the permits for drilling
has commenced in anticipation of drilling activity in 2011.
Panther Canyon Property
The following is a description of the Panther Canyon Property. Certain statements in the following
summary of the Panther Canyon Property are based on and, in some cases, extracted directly from the
Panther Canyon Report prepared on behalf of Magma by Dr. J. Douglas Walker (Ph.D.), who is
independent from the Company. See “Scientific and Technical Information”. Reference should be made
to the full text of the Panther Canyon Report which is available for review on SEDAR at www.sedar.com.
Property Area
The Panther Canyon Property is located in Nevada approximately 50 kilometres south of the community
of Winnemucca, Nevada, in the Grass Valley, Pershing County. It consists of 4,515 hectares
(11,157 acres) of federal public lands that were acquired by the Company at a BLM lease auction in
August 2008.
The Panther Canyon Property comprises three BLM leases. The purchase price for the property was
$155,540. The primary lease term is ten years with the possibility of three additional five-year
extensions. If a commercial well is drilled on the property, then the acreage can be converted to “held-byproduction” status, which continues for as long as the property produces geothermal fluids. For a
description of the terms of the BLM leases that comprise the Panther Canyon Property see “United States
Geothermal Leases”.
There are no surface manifestations of hydrothermal activity in the immediate area of the Panther Canyon
Property. There are frequent occurrences of intermediate grade argillic, hematitic, and silicic alteration,
as well as active hot springs, fumaroles, and associated sinter, chalcedony, and opaline silica in the area of
Leach Hot Springs located approximately eight kilometres north north-west of the property.
The proposed exploration and development work will be subject to local, state, and federal regulations
dealing with operational standards and environmental protection measures such as cultural resources, rare
and endangered species, clean water and air, and use of hazardous materials.
stages of exploration will include 3D reflection seismic data acquisition.
- 58 -
Activities on federal leases that results in disturbance of the surface (i.e., road building or drilling), will
process will also require an environmental assessment and a formal consultation with Native Americans
and review of plans by the State Historic Preservation Office on protection of cultural resources.
The centre of the property lies at the mouth of Panther Canyon on the west side of the Sonoma Range at
elevations ranging from 1,460 to 1,585 metres (approximately 4,800 to 5,200 feet) above sea level.
Topography is most uniformly dipping west following the surfaces of alluvial fans emanating from the
Sonoma Range. The terrain flattens with distance from the range front the closer one gets to the axis of
the alluvium-filled Grass Valley. Streams are ephemeral and there are no standing bodies of water within
the prospect area.
Means of Access
From Winnemucca, Nevada, the prospect area is accessible by traveling south on NV294, Grass Valley
Road, through the McCoy Ranch to Jersey Valley Road; the total distance is approximately 48 kilometres.
Most of the Panther Canyon lease area is under federal ownership for surface and subsurface minerals. A
portion of sections 29, 30, 31, and 32 are split estate with private surface ownership and federal
subsurface minerals. Preliminary contact has been made with the owners and there are no indications that
access will be an issue.
There is a low voltage power line that runs parallel to Grass Valley road approximately six kilometres
west of the Panther Canyon Property. The relatively flat terrain and largely uninhabited spaces should
pose no difficulties in permitting and constructing a tie to the existing transmission line although this line
may need to be upgraded to 115 kV in order to carry any substantial load from the Panther Canyon
Property. There is also a 345 kV line (originates at the Valmy power plant to the north-east) that runs east
to west just north of Leach Hot Springs.
History
There were few geologic investigations in the Grass Valley area prior to the 1970’s. The general region
of north-central Nevada has been the locus of prospecting and mining of mostly precious metals in the
latter part of the 19th century, through the 20th century, and into modern times. There are two areas in the
immediate area of the Panther Canyon Property and Leach Hot Springs that have historic mining activity,
but are currently inactive: Goldbanks mercury site on the west side of Grass Valley and the mouth of
Panther Canyon. The earliest mention in the literature of Leach Hot Springs itself was by Clarence King
in his report on the 40th parallel survey in 1878. There was, however, little reconnaissance geology
reported in the literature until the early 1970’s when scientists from the USGS and Lawrence Berkeley
conducted geological, geochemical, and geophysical surveys of the area.
Aminoil U.S.A., Inc. (“Aminoil”) and Sun Oil Company continued temperature gradient hole drilling and
also performed geophysical, geochemical, and geological surveys in the area. Aminoil established a
geothermal development unit in 1978 consisting of 12,250 hectares (30,270 acres) that they let expire
during the weak energy market period in the middle 1980’s.
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Geological Setting
The Panther Canyon Property lies within the Basin and Range geomorphic province of the western
United States. See “McCoy Property – Geological Setting” for a description of the Basin and Range
geomorphic province.
The pre-Tertiary rocks in the area have diverse rock types, are structurally complex, and are slightly to
moderately metamorphosed. The bulk of the rocks in the Sonoma Range are structurally superposed
Paleozoic eugeosynclinal and miogeosynclinal sedimentary rocks that are in varying states of alteration.
Deposition of early to middle Paleozoic marine strata and volcanic rocks was followed by thrusting and
folding during the Sonoma Orogeny. The sedimentary sequences were intruded by late Triassic granite in
the Goldbanks Hills and Cretaceous to early Tertiary granites elsewhere. There is evidence of two
periods of hydrothermal activity in the vicinity of the Panther Canyon Property: a middle-Miocene event
that is represented at Goldbanks Hills, and a modern period represented by local sinter and chalcedony at
Leach Hot Springs.
Basin boundaries are characterized by either high-angle normal faults with abrupt termination of outcrops
such as the case of the eastern side of Grass Valley, or margins with more subtle transitions to the
alleviated basins indicative of basinward progradation of alluvial fans. This is a typical structural
situation found in a half-graben setting throughout the Basin and Range geomorphic province. The basins
themselves are filled with mostly unconsolidated late Pliocene, Pleistocene, and Holocene sediments.
The structure of the Panther Canyon area consists of north north-west and northeast-striking, mostly highangle, normal and oblique slip faults that form a complex surface pattern. The fault system has been
discussed in terms of a primary north northwest-striking fault set with the northeast-striking set being
“transverse.” Where these two fault sets intersect, they predict that there is substantial permeability as is
the case at the Panther Canyon Property. In fact, Panther Canyon Property represents the topographic
break between the Tobin Range on the south and the Sonoma Range on the north. The western Sonoma
Range frontal fault in the area of Panther Canyon shows evidence of at least Quaternary, and possibly
Holocene faulting. This frontal fault is the northern extension of the structure on which the 1915 Pleasant
Valley earthquake (magnitude seven to eight) occurred, resulting in five metres of dextral oblique
displacement. The western front of the Tobin-Sonoma Ranges is offset in a sinistral sense almost
2.5 kilometres along the strike of Panther Canyon. The zones of intersection of these two structural
trends are important with regard to formation of permeability.
Resource Type
There are no chemical analyses of fluids or geothermometer data available from the Panther Canyon
Property. Geothermometer calculations based on fluid geochemistry data from the Leach Hot Springs
area show that the estimated temperature of the reservoir for those fluids is in the range of 135°C.
Exploration
We have not conducted any exploration to date in the Panther Canyon or Leach Hot Springs areas, but a
significant effort was made by the USGS, Lawrence Berkeley, Aminoil and others in the period 1979
through 1981 to define the geothermal system in the Panther Canyon, Leach Springs, and Goldbanks Hills
areas. These efforts were mostly based on temperature gradient drilling and electrical potential
field methods.
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Out of a total of more than eighty shallow and intermediate depth temperature gradient and heat flow
holes drilled in the southern Grass Valley, 58 were drilled in the vicinity of Panther Canyon. These holes
ranged in depth from 25 metres to as deep as 457 metres, and gauged bottom hole temperatures from
17.2°C to 94.1°C. Likewise, temperature gradients ranged from a low of 31.2°C per kilometre to a high
of 290°C per kilometre. The temperature gradient in the hole designated Q3 at the mouth of Panther
Canyon was 118°C per kilometre; the maximum temperature in the hole was 24°C at depth of 175 metres.
A second heat flow hole, QH13, located 1.8 kilometres north-east of Q3 had a temperature gradient of
120°C per kilometre, and a maximum measured temperature of 18.5°C at a depth of 50 metres.
Heat flow holes were drilled in the southern Grass Valley, Leach Hot Springs, and Panther Canyon
Properties by the USGS in 1975 and 1976. Heat flow values have been calculated using the temperature,
conductivity, and thermal gradient data from those holes. Results have shown heat flow in the Panther
Canyon Property as high as 4.87 HFU in well Q3 and 6.8 HFU in well QH17. These values are 2.5 to
3.0 times greater than background for the area. Using the assumption that the Panther Canyon anomalies
are conductive and linear to depth, the 200°C isotherm can be extrapolated to a depth range of 1,530 to
1,735 metres. The total area within the boundary of the four HFU contour at Panther Canyon
(approximately eight square kilometres) is about two-thirds the size of the same area at Leach Hot Springs
itself (approximately 12 square kilometres).
Geophysical Surveys
During 1975 and 1976, Lawrence Berkeley personnel conducted a wide range of geophysical surveys
throughout the southern Grass Valley area with the objective of evaluating the geothermal potential of the
area as well as evaluating the capability of various types of geophysical techniques to detect geothermal
resources. They obtained the following types of geophysical data: gravity, ground magnetics, MT,
standard resistivity, bipole-dipole, dipole-dipole resistivity, P-wave delay, microearthquake behavior,
seismic ground noise, and active seismic refraction and reflection.
The major findings of these Lawrence Berkeley surveys relevant to the Panther Canyon Property are:

there is a large low resistivity anomaly beneath the high heat flow area at the mouth of the
canyon;

the high heat flow area is co-located with a strong electrical conductivity high determined
from the dipole-dipole survey results;

a strong northeast-trending gravity lineament extending beneath the length of Panther
Canyon matches a regional north-east south-west lineament observed on satellite images and
aerial photos; and

Panther Canyon is the only location where there is microearthquake activity in southern
Grass Valley.
Geochemical Surveys
Although no geochemical data on fluids is available for the Panther Canyon Property, data from nearby
Leach Hot Springs provides some insight into possible maximum reservoir temperatures that could be
anticipated. The maximum reservoir temperature beneath Leach Hot Springs itself has been estimated to
be between 139°C and 182°C using silica and Na/K/Ca geothermometer calculations, respectively.
Aminoil determined that using mixing model equations, the subsurface temperature may exceed 200°C,
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and if one considers a 75% cold groundwater dilution factor for silica, that anticipated temperature could
reach 250°C.
Results from the survey work conducted by Lawrence Berkeley, Aminoil, the USGS and others at the
Panther Canyon Property are consistent with the presence of an active geothermal system with
economically viable temperatures at depths that permit exploitation at reasonable cost. Geophysical,
geochemical, and temperature data indicate a thermal anomaly defined by the four HFU contour that is as
large as the ore found at the Beowawe Property area in Eureka County, Nevada, and the Soda Lake
Operation in Churchill County, Nevada. If the geothermal reservoir is described by the four HFU
contour, then it would cover a distance of 3.6 kilometres in a north north-east south south-west direction
with an average width of 2.2 kilometres – an area of nearly eight square kilometres. This compares in
size with both the Soda Lake Operation and the Beowawe production facility owned by TerraGen
Power, LLC (“TerraGen”) located next to our Beowawe Property, which currently produce 8 MW and
16 MW, respectively.
The high level of earthquake activity in the Panther Canyon Property combined with the fact that it is
situated at the confluence of two nearly orthogonal fault zones indicates that this may be an area of high
permeability at depth. Without any deep slim hole or production type drilling results, it is difficult to
quantify the possible reservoir potential with any degree of certainty. However, extrapolated temperature
gradient and heat flow data indicate that a geothermal reservoir at a depth of two kilometres beneath the
area within the four HFU contour could be large enough to support a minimum of eight to ten MW and a
maximum of 20 MW to 24 MW depending on the extent of subsurface fracturing.
Leach Hot Springs is the only geothermal area in the immediate vicinity of the Panther Canyon Property,
however, a number of geothermal development projects and hot springs areas are in the general vicinity,
including the following:

Dixie Valley (40 kilometres south of the lease area) has a producing 60 MW dual flash-type
geothermal facility with producing temperatures in excess of 230°C. There are numerous
other hot springs (e.g., Sou Hills, Dixie Meadows, and Hyder) with surface hot springs
temperatures ranging from 55°C to 80°C.

Jersey Valley (35 kilometres south south-east of the lease area) have reported hot springs
with temperatures of 55°C. Ormat drilled two holes in Jersey Valley as part of their
exploration efforts on BLM leased lands under their control. They reported maximum
downhole temperatures in the 176°C range.

Pumpernickel Valley (42 kilometres north of the lease area) has been explored by Nevada
Geothermal Power Co. and has yielded downhole temperatures of 135°C. They have
reported estimated reservoir temperatures ranging from 150°C to 218°C, and they project that
the reservoir can sustain 20 to 30 MW of production.
Resource Estimate
As there has been no deep resource evaluation drilling or reservoir testing to date at the Panther Canyon
Property, no reliable resource estimate is possible at this time. However, probable reservoir production
capability can be estimated based on the projected area of the 200°C isotherm at a depth of 2,000 metres.
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An estimate of the resource potential for the Panther Canyon Property has been prepared by GHA using
the volumetric estimation method developed by the USGS modified to account for uncertainties in some
Methodology”. This method yields estimated MW generation capacities of P90 = 34 MW for the Panther
Canyon Property. Geothermal resources and probabilistic estimates of gross MW capacity have a great
Based on the technical data presented and additional backup data, it is reasonable to conclude that there
exists a substantial, but unquantified, geothermal resource beneath the Panther Canyon Property.
Temperature gradient and geophysical data are consistent with source fluid temperatures in the 150°C to
200°C range at depths of 2.0 to 2.5 kilometres below the surface. Temperatures in this range are
commercially attractive for generating electricity using single or double-flash technology. Geochemical
as well as geological and geophysical indicators from the nearby Leach Hot Springs are consistent with
this estimate. In addition, the presence of active faults indicates that there should be abundant
permeability and that open fractures should be maintained.
There are no apparent environmental or administrative barriers to the development of the resource. The
BLM, Nevada State Office, has an aggressive program of renewable energy development that includes
consolidated and expedited permitting mandates. Although there is an absence of production-type data
that could underpin a detailed economic analysis of the Panther Canyon Property resource, a diligent
exploration program, including drilling, is warranted by the results of the technical studies to date.
We are evaluating all existing data described in the Panther Canyon Report, the data found in the sources
cited therein, unpublished exploration data and databases located at the University of Nevada, Reno and
the Nevada Division of Minerals. We have completed in-fill gravity and magnetics field surveys. The
likely resource delineation program will include the acquisition of 3D reflection seismic data over the
prospect in order to define the fault and fracture system followed by in-fill electrical field surveys. This
data will be modeled using 3D analysis and visualization techniques to select locations for drilling two to
four intermediate depth (1,000 to 2,000 metre) slim holes from which flow tests will be conducted.
Because of the large number of shallow temperature gradient holes already available in the area, it is
unlikely new shallow holes will be drilled.
We have commenced permitting efforts at the Panther Canyon Property. Additional gravity, magnetic,
and resistivity data are needed to infill previous efforts and define the resource. This data will permit
further refinement of the resource based on a MT survey. This work is cost effective at a survey level.
Further delineation of the resource will require integration of geologic mapping data with subsurface
information. The geophysical data partly provide this information, but in this region the most reliable
method for obtaining such information is 3D seismic reflection. This higher cost exploration method
builds on the previously collected data. This is particularly critical for this area in that it is likely that any
resource would be structurally controlled.
in the resource. This data can only be obtained by drilling exploration wells followed by sampling and
discussed above. Drilling represents approximately 75% of the proposed exploration budget. A
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determination to proceed with drilling and the location of any proposed drill sites will be guided by the
less expensive exploration activities described above.
Desert Queen Property
The following is a description of the Desert Queen Property. Certain statements in the following
summary of the Desert Queen Property are based on and, in some cases, extracted directly from the
Desert Queen Report prepared on behalf of Magma by Dr. J. Douglas Walker (Ph.D.), who is independent
from the Company. See “Scientific and Technical Information”. Reference should be made to the full
text of the Desert Queen Report which is available for review on SEDAR located at www.sedar.com.
Property Area
The Desert Queen Property is located adjacent to the Hot Springs Mountains in west-central Churchill
County, Nevada. The site is approximately 38 kilometres north of the town of Fallon and is contiguous
with, or near to, the Desert Peak and Brady-Hazen Hot Springs geothermal facilities and our Soda Lake
Operation, three of the nine producing geothermal fields in the state of Nevada. The total land currently
under lease at the Desert Queen Property, including both the BLM and private leases, is 4,672 hectares
(11,544 acres).
The Desert Queen Property consists of five BLM lease parcels and two leases with fee owners. Two of
the BLM lease parcels were purchased at a lease auction conducted by the BLM in August 2008 for a
total purchase price of $1,570,600. The effective date of these leases is September 1, 2008 with a primary
term of ten years. The remaining BLM lease parcel consisting of 266 hectares (658 acres), was purchased
from an independent operator in October 2008 for a purchase price of $164,400. The parcel has a primary
term of ten years from its effective date of September 1, 2007. For a description of the terms of the
BLM leases that comprise the Desert Queen Property, see “United States Geothermal Leases”. The
remaining two BLM leases were purchased in May 2010 at a BLM lease auction.
The private fee land lease parcels provide for an exclusive five-year exploration period with the option to
extend for an additional five years. Annual rental fees are paid to the lessors during the exploration phase
of the leases. The fee land leases will convert to production status once a commercial well is drilled on
the property for as long as the property produces geothermal fluids. The Company is obligated to pay a
royalty to the fee landholders similar to those paid to the federal government based on a percentage of the
gross sale of electricity and the percentage contribution of geothermal fluids derived from a lessor’s
property.
The Desert Queen Property is in the Battle Mountain high heat flow area, where there are currently two
producing power plants. The property is within the second largest portion of what can be considered a
composite heat anomaly, which feeds the Desert Peak geothermal facility and Brady’s Hot Springs. The
closest surface expression of geothermal activity is at Brady’s Hot Springs, 12 kilometres west of the
current Desert Queen Property boundary. The Desert Peak geothermal facility is located nine kilometres
to the southwest of the Desert Queen Property. The Desert Peak geothermal reservoir, which was
discovered using temperature gradient data and geophysical studies in the absence of any physical surface
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expression of a geothermal system, now supports a 19.7 MW nameplate capacity power plant. Production
fluid temperatures at this facility are as high as 200°C.
The structural regime of the area has allowed hot water to circulate close to the surface, creating the heat
anomaly throughout the area that has proven capable of supporting economic geothermal development.
Inferences from geologic mapping and interpretations of geophysical data indicate that the geothermal
area is located at the intersection of two major regional fault systems – the Walker Lane belt and the
Central Nevada Seismic belt. This structural juxtaposition suggests conditions favourable for the
movement of fluids, which is an encouraging sign for continuing the exploration at the Desert
Queen Property.
stages of exploration will include 3D reflection seismic data acquisition, which is anticipated to be
completed under a categorical exclusion.
Activities on federal leases that result in disturbance of the surface (i.e., road building or drilling) will
process also requires an Environmental Assessment, a formal consultation with Native Americans, and
review of plans by the State Historic Preservation Office on protection of cultural resources. These steps
are in process.
Accessibility, Climate, Local Resources and Physiography
The Desert Queen Property lies at northern slope of the Hot Springs Mountains at elevations ranging from
1,219 to 1,402 metres above sea level. Topography is flat in the western portion of the property, sloping
up into the Hot Springs range in the southeast. Streams are ephemeral and there are no standing bodies of
water within the property area.
Means of Access
From Fernley, Nevada the Desert Queen Property is accessible by traveling east on Interstate 80, and
taking exit 65, heading west and then southeast on a public access road for approximately ten kilometres.
The Desert Queen Property is a checkerboard of BLM and private leases. There are no indications that
surface access will be an issue. The property is approximately eight kilometres from the two major
345 kV lines, located on the northwest side of Interstate 80, that originate at the Valmy power plant. The
substation at the Desert Peak geothermal facility, approximately 9.5 kilometres to the southwest of the
Desert Queen Property, connects to a 115 kV line that parallels Interstate 80 into the Reno area. The
relatively flat terrain and largely uninhabited spaces should pose no difficulties in permitting and
constructing a tie to an existing transmission line.
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History
Geologic investigation of the Desert Queen region began in the late 1800’s with the discovery of gold
mineralization in the northeastern portion of the Hot Springs Mountains. The Desert Queen Mine and the
nearby Fallon Eagle Mine were in production until 1951. Salt was produced from the flats northeast of
the Hot Springs Mountains from 1870 to 1912. Since 1940 diatomite has been mined from the northwest
side of the range. The Brady’s Hot Springs was the site of a resort and spa from the 1920’s under the
name Springer’s Hot Springs until the Brady’s bought the property in the 1940’s. Geothermal drilling
near the springs began in 1959. In 1978 a geothermal powered food processing plant opened on the
Brady’s site. Investigation of the geothermal resources of the area stretching from Brady’s to the Desert
Peak and Desert Queen properties began in the 1970’s. Phillips Petroleum Company (“Phillips”)
conducted a three-year exploration program that focused primarily on the Desert Peak area, but extended
into the Desert Queen Property. See “Exploration” below for a discussion of the exploration conducted to
date on the Desert Queen Property.
Geological Setting
The Desert Queen Property lies within the Basin and Range geomorphic province of the western
United States. See “McCoy Property – Geological Setting” for a description of the Basin and Range
geomorphic province.
The surface geology exposed in the vicinity of the Desert Queen Property consists primarily of
Quaternary alluvium and windblown sand, which hide the geology and structures within the Desert Queen
Property. Therefore much of the geologic composition and structure is inferred from the exposed geology
of the Hot Springs Mountains, drill hole data, and geophysical studies.
There are five major rock units exposed in the northern portion of the Hot Springs Mountains. There are
two younger Tertiary units of volcanic origin, which are unconformably resting on the Truckee formation,
a volcanic rich sedimentary package; the Truckee is underlain by the Desert Peak Formation consisting of
diatomite and basaltic tuff; the oldest Tertiary formation is the Chloropagus formation of mostly basalt
and andesite flows intermixed with fine-grained sediment. A very important unit is a small pluton of
hornblende-quartz diorite that crops out near the Desert Queen Mine. The intrusion is bounded on the
east by the Desert Queen normal fault, to the north by a rhyolite unit presumed to be the same age, and in
the south and west by the Chloropagus formation. This intrusive rock is inferred to be between four and
five million years old, because it has an alteration halo in similar age rocks. The presence of such a
young intrusive rock indicates potential for significant heat advection into the area. Mesozoic basement is
not exposed in the immediate vicinity, but was encountered in the deeper test holes drilled in the late
1970’s. The basement consists of metamorphosed volcanic and sedimentary rocks of varying types.
Two northeast trending fault sets are found in the Hot Springs Mountains. The dominant fault set trends
north-northeast, and is interpreted to be related to the Basin and Range deformation. In the area of
Brady’s Hot Springs, the geothermal heat is localized along a fault with this orientation. The Desert
Queen normal fault in the western part of the Desert Queen Property is part of this set of faults. The
Desert Queen fault is a relatively large structure with south-side-down offset of up to 1,000 metres.
Faulting can localize and facilitate the movement of geothermal fluids by keeping pathways open. We
are investigating this fault structure through geophysical study and geologic mapping. A second fault set
trends more easterly. This fault has been interpreted to be localized in a horst block formed by the
intersection of the north-northeast and east-northeast trending fault sets. This horst could continue
northeastward into the southern half of the Desert Queen Property, although down dropped across the
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Desert Queen fault. Some of the Tertiary rocks are folded with the fold hinges trending to the northeast.
This folding may be a result of differential block movement originating from basement faults, possibly
related to the intersecting fault sets.
Exploration
Geothermal exploration in the Brady’s Hot Springs and Desert Peak area was conducted by the USGS,
the U.S. Bureau of Reclamation, and a number of private entities over a period of more than 20 years. At
the time the area was the site of the hottest surface temperature gauged in the state of Nevada. Beginning
in 1973, Phillips conducted a three-year exploration program that focused primarily on the Desert Peak
area, but extended into the site of the Desert Queen Property. Of the 53 temperature gradient holes that
Phillips drilled, 12 were in the area of the Desert Queen Property. These holes were drilled to an average
depth of 91.4 metres (300 feet). In addition, Phillips drilled eight stratigraphic holes, one of which, ST-3,
was located in the area of the Desert Queen Property. ST-3 was drilled to a total depth of 425 metres
(1,395 feet) where a temperature of 101°C (214°F) was gauged.
In 2007, the Great Basin Center on Geothermal Energy at the University of Nevada, Reno conducted a
shallow (two metre) temperature probe survey over the area of the Desert Queen Property. Results of that
survey defined a north-northeast-trending shallow temperature anomaly approximately six kilometres
long and two kilometres in width, defined by the 25°C isotherm. The maximum temperature reached
43°C against a background temperature of 23°C.
In March 2010, we completed four temperature gradient wells at the Desert Queen Property. The
temperature logging of these wells showed good gradients and provided the impetus for a review of our
land position in the area. We acquired further acreage at a BLM auction in August 2010 and have
initiated a review of our private land holdings in the area. This review continues.
Geophysical Surveys
Phillips conducted a 32-station deep sounding MT survey around the Desert Peak area in 1976. Four of
these 32 stations are located in the Desert Queen Property. Earth resistivity maps at 610, 1,220, and
2,440 metres show resistivities below two ohm-metres at only two stations, both of which lie within one
kilometre of the six kilometre long thermal anomaly. MT mapped deep resistivities less than two ohmmetres are commonly spatially associated with rock alteration and fluid temperature and salinity
associated with geothermal fields in Nevada (e.g., Dixie Valley). The existence of very low resistivity
values adjacent to the mapped thermal anomaly suggests the latter overlies a deep anomalous geologic
feature, elsewhere seen in close genetic associations with commercial geothermal resources.
In January 2009, we completed a 375 station detailed gravity survey largely with a 400 metre by
400 metre grid station spacing covering the complete Desert Queen Property. The gravity survey showed
that the six kilometre long north-northeast thermal anomaly revealed by the University of Nevada, Reno
survey is spatially associated with a horst-like structural high gravity anomaly beneath the alluvium. This
high may be the continuation of the horst described above. Correspondence of these two large-dimension
anomalies is consistent with an integrated underlying geothermal system. This is a favourable
association, which is also seen at numerous geothermal fields including the nearby Brady’s Hot Springs
field. At the Desert Queen Property, this association strongly suggests a thermal anomaly distributed by
vertical ascent of fluids along the six kilometre length of a deep-seated north-northeast structure.
The area of the Desert Queen Property received only cursory consideration as a target area during
exploration and development of the Desert Peak field in the 1970’s. The new thermal-gravity target is
located three kilometres east of the nearest moderate depth exploration drill hole, ST3 mentioned above,
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and is covered by older lake bed sediments, alluvium and windblown sand. As is the case with the Desert
Peak field, obvious hydrothermal deposits do not occur over the thermal anomaly. This may be attributed
to a relatively deep water table (60 metres) and geologically young thermal system and is not considered a
negative indicator of the presence of a commercial field.
Geochemical Surveys
Little geochemical data is currently available from the immediate area, but samples taken from the Desert
Peak wells show high levels of total dissolved solids, chloride, and silica content, even in the lower
temperature sources. Water samples were obtained from three of the four temperature gradient wells
drilled in March 2010. The results of the initial analysis of these samples are encouraging.
Results from the survey work conducted by the USGS, the University of Nevada, Reno, the Nevada
Bureau of Mines and Geology, Phillips and others at and nearby the Desert Queen Property are consistent
with the presence of an active geothermal system with economically viable temperatures at depths that
permit exploitation at reasonable cost.
The Desert Peak and Brady’s Hot Spring geothermal facilities are in the immediate vicinity of the Desert
Queen Property. Our Soda Lake Operation is located approximately 28 kilometres to the south of the
Desert Queen Property and the Stillwater geothermal area is located approximately 38 kilometres to
the southeast.
Resource Estimate
As there has been no deep resource evaluation drilling or reservoir testing to date of the Desert Queen
Property, no reliable resource estimate is possible at this time.
An estimate of the resource potential for the Desert Queen Property has been prepared by GHA using the
volumetric estimation method developed by the USGS modified to account for uncertainties in some
Methodology”. This method yields estimated MW generation capacities of P90 = 36.4 MW for the Desert
Queen Property. Geothermal resources and probabilistic estimates of gross MW capacity have a great
Based on the technical data presented in the Desert Queen Report and additional backup data, it is
reasonable to conclude that there exists a substantial, but unquantified, geothermal resource beneath the
Desert Queen Property. Temperature gradient and geophysical data are consistent with source fluid
temperatures in the 150°C to 200°C range at depths of 2.0 to 2.5 kilometres. Temperatures in this range
are commercially attractive for generating electricity using single or double flash technology.
Geochemical as well as geological and geophysical indicators from the nearby Desert Peak property are
consistent with this estimate. Especially important is the presence of an intrusive body in the area that is
only a few million years old.
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There are no apparent environmental or administrative barriers to development of the resource. In fact,
the BLM, Nevada State Office has an aggressive program of renewable energy development that includes
consolidated and expedited permitting mandates. Although there is an absence of production-type data
that could underpin a detailed economic analysis of Desert Queen Property, a diligent exploration
program, including drilling, is warranted by the results of the technical studies to date.
We are evaluating the data described in the Desert Queen Report, the data found in the sources cited
therein, unpublished exploration data and databases located at the University of Nevada, Reno, the
Nevada Division of Minerals and from our recent temperature gradient drilling. The likely resource
delineation program will include acquisition of 3D reflection seismic data over the prospect in order to
define the fault and fracture system as well as in-fill electrical field surveys. This data will be modeled
using 3D analysis and visualization techniques to select locations for drilling two intermediate depth
(1,000 to 2,000 metre) slim holes from which flow tests will be conducted. We have commenced
permitting work at the Desert Queen Property. Additional gravity, magnetic, and resistivity data are
needed to infill previous efforts and define the resource. This data will permit further refinement of the
resource based on a MT survey. This work is cost effective at a survey level.
Further delineation of the resource will require integration of geologic mapping data with subsurface
information. The geophysical data partly provide this information, but in this region the most reliable
method for obtaining such information is 3D seismic reflection. This is a higher cost exploration method
that builds on previously collected data, and is particularly critical for the Desert Queen Property.
discussed above. Depending on the results obtained from our exploration activities we intend to drill two
intermediate depth (1,500 to 2,250 metre) slim holes from which flow tests will be conducted. Drilling
represents a significant portion of the proposed exploration budget. A determination to proceed with
drilling and the location of any proposed drill sites will be guided by the less expensive exploration
activities described above.
Thermo Hot Springs Property
The following is a description of the Thermo Hot Springs Property. Certain statements in the following
summary of the Thermo Hot Springs Property are based on and, in some cases, extracted directly from the
Thermo Hot Springs Report prepared on behalf of Magma by Dr. J. Douglas Walker (Ph.D.), who is
independent from the Company. See “Scientific and Technical Information”. Reference should be made
to the full text of the Thermo Hot Springs Report which is available for review on SEDAR located at
www.sedar.com.
Property Area
The Thermo Hot Springs Property is located in Utah approximately 50 kilometres south-southwest of the
Roosevelt Hot Springs in Beaver County, Utah. It consists of a single 713 hectare (1,761 acre) BLM
lease parcel.
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The Thermo Hot Springs Property consists of a BLM lease that was purchased from a private leaseholder
in August 2008. The purchase price for the property was $528,237. The vendor retains an overriding
royalty of 1.5% on gross proceeds derived from the sale of electricity generated from the lease. The
primary ten year lease term began on October 1, 2002 and expires on the anniversary date in 2012. For a
description of the terms of the BLM leases that comprise the Thermo Hot Springs Property, see
“United States Geothermal Leases”.
The Thermo Hot Springs Property is located within the northeast part of the Escalante Desert in southern
Beaver County. Two hot spring mounds occur in sections 21 and 28, directly adjacent to the property.
The springs occur along a north-northwest oriented lineament located in the Milford Valley of the
northern Escalante Desert. This lineament connects the property with the Roosevelt Hot Springs
geothermal facility in the northwest. Another of the three major geothermal areas in Utah, Cove Fort
Sulphurdale, is located to the northwest of the Roosevelt Hot Springs geothermal facility, crossing into
Millard County. Raser Technologies, Inc. (“RTI”) has initiated construction of a ten MW binary
geothermal facility on a property adjacent to the Thermo Hot Springs Property.
stages of exploration will include 3D reflection seismic data acquisition, which is anticipated to be
completed under a categorical exclusion.
Activities on federal leases that results in disturbance of the surface (i.e., road building or drilling) will
We will be required to post a $50,000 bond to secure the necessary permits. Completion of the permitting
process will also require an Environmental Assessment and a formal consultation with Native Americans
and review of plans by the Utah State Historic Preservation Office on protection of cultural resources.
The area is known to contain the listed species the Greater Sage Grouse and this may result in some use
stipulations on the property.
Accessibility, Climate, Local Resources and Physiography
The Thermo Hot Springs Property lies in a northeast trending alluvial valley in between the Shauntie
Hills to the northwest and the Black Mountains to the southeast in the southern part of Beaver County,
Utah. Elevations on the immediate property are relatively flat varying between 1,535 and 1,544 metres.
Peak elevations in the Shauntie Hills are between 1,672 and 1,734 metres with peaks in the Black Hills
ranging from approximately 1,704 to 1,791 metres. Generally, the climate is temperate and not subject to
either extreme heat or cold. There are four well-defined seasons. The sun shines an average of 320 days
each year. Precipitation averages 29.6 centimetres annually.
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Means of Access
From Beaver County, Utah the Thermo Hot Springs Property is accessed by heading west on road UT-21
to N300W Street, continuing west to Thermal Road and then southwest to the property. The total
distance from Beaver is approximately 55 kilometres.
Access is not anticipated to be an issue at the Thermo Hot Springs Property. The geothermal lease
comprising the Thermo Hot Springs Property is 100% BLM ownership for surface and subsurface
minerals. A portion of sections 21, 28, and 29 are held by private land owners and in State land trusts.
Preliminary contact has been made with the owners and there are no indications that access will be an
issue. An existing transmission line runs in close proximity to the southern boundary of the leasehold
position, which is currently being partially used by RTI to send power to the city of Anaheim, California.
History
Though there is abundant surface expression of geothermal systems in Utah, exploration for economic use
of the resource is a relatively new activity. In the 1970’s and 1980’s southwestern Utah was part of the
national effort to define potential sources of geothermal energy. These studies consisted of regional and
detailed geologic mapping, geochemical studies, geophysical studies, analysis of superficial hydrothermal
deposits and drilling of shallow temperature gradient holes. At this time the area of the Thermo Hot
Spring Property was classified as a “Known Geothermal Resource Area”. The Thermo Hot Springs
Property was declassified in the 1990’s due to lack of leasing interest, however, more detailed
investigation and resource exploitation has recently occurred in the region.
Geological Setting
The Thermo Hot Springs Property lies on the eastern edge of the Basin and Range geomorphic province
of the western United States. See “McCoy Property – Geological Setting” for a description of the Basin
and Range geomorphic province.
Directly within the property area the older lithology and geologic structures are obscured by recent
sedimentary deposits. The surrounding mountains are used to decipher what may be underlying the
alluvium. The Shauntie Hills, northwest of the property, and the Black Mountains to the southeast consist
of mainly Tertiary lava flows and volcaniclastic deposits that range in age from 19 to 26 million years.
Younger rhyolite has been mapped approximately three kilometres east of the property with an age of
10.3 million years. Rhyolites and other quartz-bearing volcanic rocks of Pliocene age are also mapped in
both the Shauntie Hills and the Black Mountains.
The two Thermo hot spring deposits are oriented north-northeast. Each deposit is approximately one
kilometre long, 50 to 200 metres wide and four to eight metres high. The mounds are made up of mostly
windblown sand, travertine debris and siliceous sinter. Regional gravity data suggest that a subsurface
fault with several hundred feet of displacement (down to the west) passes through the hot springs area.
Normal faults that displace the Quaternary valley fill in and around the mounds have northeast
orientation. Faults mapped within the volcanic units of the low hills southeast of the thermal area, and
within the Black Mountains, are oriented to the northwest. The orientation of these two sets of structures
and the position of the hot springs suggest that a structural intersection localizes the geothermal system.
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Republic Geothermal, Inc. (“Republic”) drilled a 2,221 metre deep exploration hole, designated
Escalante 57-29, approximately 1.6 kilometres west-southwest of the hot springs mounds. The hole
passed through 350 metres of alluvium, 610 metres of Miocene volcanic rocks, 540 metres of sedimentary
and metamorphic rocks and bottomed in granite.
Hydrogeochemistry and Geothermal Resource Potential
Four chemical analyses of water samples from the Thermo Hot Springs are publically available. The
maximum silica concentration found in these chemical analyses was 108 milligrams per litre (“mg/L”)
and the dissolved solids were about 1,500 mg/L. The dominant ions were sodium and sulfate. The
estimated reservoir temperature based on chemical analyses of water samples and geothermometer
calculations, was 140°C to 200°C. The maximum depth of circulation of water to the hydrothermal
reservoir is estimated at 3,000 and 4,000 metres based on an estimated regional conductive heat flow of
two HFU, mean thermal conductivity of the rock and alluvium of about 4.5 cal/cm/s°C, and an ambient
land surface temperature of 12°C. The calculation assumes the absence of a shallow magmatic-heat
source.
Exploration
There are records of at least 21 temperature gradient holes drilled in the immediate area of the Thermo
Hot Springs. The known thermal anomaly lies within the area of the Thermo Hot Springs Property.
Temperature gradients from wells in the immediate area range from 11°C to 178°C per kilometre with an
average temperature of 42°C per kilometre. For comparison, worldwide geothermal gradients made on
continental crust range from 8°C per kilometre to 50°C per kilometre and average 25°C per kilometre.
There have been numerous geophysical surveys done over the region with varied levels of detail.
Existing geochemical data is sparse in the direct area though there are at least two available analyses of
the spring water close to the Thermo Hot Springs Property.
Geophysical Surveys
Available geophysical data includes published gravity, ground magnetics, self-potential and electrical
resistivity data acquired primarily during the 1970’s and 1980’s. The existing electrical resistivity and
audio-magnetotelluric survey maps are of reconnaissance grade, with east-west electrical lines spaced
three kilometres apart and sounding stations scattered four six kilometres apart. New detailed, deepmapping electrical surveys are planned to identify target structures. The existing maps identify an
extreme low resistivity zone (0.9 to 2.0 ohms per metre) 1.5 kilometres wide and potentially four
kilometres in length that correspond directly with the north-northwest hot springs mounds. Data from one
Republic well, Escalante 57-29, suggests that the low resistivity values observed likely include a
contribution from argillic alteration of permeable units, as the total dissolved solids of the fluids are only
moderate at 1,300 to 3,300 ppm at measured temperatures of 174°C (160°C to 217°C) at 2,050 metres in
depth. Intense hydrothermal alteration of the rock units surrounding the throat of the hot spring is also the
most likely cause of the magnetic anomaly low associated with the conductive heat flow anomaly.
A detailed self-potential survey of the area of the Thermo Hot Springs Property, covering ten square
kilometres, with 45 kilometres of stations spaced at 30 to 60 metres, identified an unusually spatially
coherent 1.7 kilometre diameter −30 to −60 millivolt anomaly covering the southern quarter of section 27
(within the Thermo Springs Property) and the northern three-fourths of section 34 (within RTI’s
holdings). A stronger, localized negative anomaly, 180 by 400 metres in dimension, was identified near
the northwest corner of section 34, 1.5 kilometres from the hot spring mounds. The anomaly may
indicate upward-flowing geothermal fluid.
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The self-potential anomaly expression across the hot spring mound area is spatially less coherent and
weaker. This can be explained by the localized attenuation of self-potential voltage due to the factor-offour drop in resistivity around the hot spring zone when compared to resistivity values observed in the
topographically higher alluvial fan material of section 34. The larger southeaster anomaly occurs on the
up-thrown side of a northeast-oriented fault mapped in alluvium and is somewhat correlative with
the topography of the alluvial fan, suggesting some contribution of from fluids within or beneath this fan.
About 600 gravity and a similar number of magnetic stations have been published in small map figures
with large contour intervals. The detailed gravity map indicates two possible east-west trending faults
intersecting a major north-south trending fault in the immediate vicinity of the Thermo Hot Springs. The
location of the hot springs appears to be fault controlled. The residual maps outlined an elongated
north-south graben that extends through the survey area. The magnetic data are presented as total
magnetic intensity anomaly maps for both the regional and detailed surveys. The detailed magnetic map
outlines an anomalous low with nearly 100-gammas closure associated with the Thermo Hot Springs. As
previously mentioned, this magnetic low may reflect an alteration zone which is structurally controlled.
Reprocessing and additional interpretation will likely provide additional relevant information.
Geochemical Surveys
Chemical analyses from wells and springs in the area of the Thermo Hot Springs Property are sparse. We
intend to collect more geochemistry data during the exploration phase. Geochemistry is valuable for
determining the source of geothermal fluids, thermal potential and possible chemical difficulties that
would be encountered when the fluids are used in production. Results from chemical analyses of water
samples from Thermo Hot Springs are discussed above. Geothermometry estimates prepared by several
different authors suggest reservoir equilibrium temperatures between 140°C and 200°C.
Our holdings at the Thermo Hot Springs Property cover much of the apparent resistivity and heat-flow
core in the area and also extend to the northern boundary of section 31, which hosts RTI’s newly
commissioned 10 MW plant. The available shallow drill-hole (less than 150 metre) thermal gradient data
show a northwest-southeast eight by four kilometre high heat flow zone centered on the Thermo Hot
Springs mounds. This high thermal gradient area continues three kilometres to the southeast across our
holdings into section 34. The resistivity and thermal gradient mapping indicate that our holdings could
contain the high temperature, high permeability, structurally controlled centre of the Thermo Hot Springs
geothermal system.
The Thermo Hot Springs Property is adjacent to the Hatch Geothermal Power Plant, a four MW unit
operated by Intermountain Renewable Power, LLC, a subsidiary of Raser Power Systems, LLC. The
plant opened in 2009. The property lies in the same physiographic province as the Roosevelt Hot Springs
and Cove Fort-Sulphurdale geothermal facilities, the two other producing geothermal facilities in Utah.
Resource Estimate
Inasmuch as there has been no deep resource evaluation drilling or reservoir testing that has been done to
date, no reliable resource estimate is possible at this time.
An estimate of the resource potential for the Thermo Hot Springs Property has been prepared by GHA
using the volumetric estimation method developed by the USGS modified to account for uncertainties in
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some input parameters. For a description of this methodology see “Overview of Volumetric Resource
Estimate Methodology”. This method yields estimated MW generation capacities of P90 = 20.4 MW for
the Thermo Hot Springs Property. Geothermal resources and probabilistic estimates of gross MW
capacity have a great amount of uncertainty as to their existence and as to whether they can be accessed in
an economically viable manner. It cannot be assumed that all of, or any part of, a geothermal resource
will be commercially extracted or that estimates of MW capacity will be achieved. There are no
outwardly present environmental or administrative barriers to development of the resource.
Recommended Exploration
Based on the technical data presented in the Thermo Hot Springs Report and additional backup data, it is
reasonable to conclude that there exists a substantial, but unquantified, geothermal resource beneath the
Thermo Hot Springs Property lease area. Temperature gradient and geophysical data are consistent with
source fluid temperatures in the 150°C to 200°C range at depths of 2,000 to 2,500 metres. Temperatures
in this range are commercially attractive for generating electricity using single or double flash technology.
Geochemical as well as geological and geophysical indicators from the property and the nearby RTI
property are consistent with these findings. In addition, the presence of geologically active faults
indicates abundant permeability and suggests that open fractures should be maintained.
We are evaluating the data described in the Thermo Hot Springs Report, the data found in the sources
cited therein, unpublished exploration data and databases located at the Great Basin Center for
Geothermal Energy, the Utah Geological Survey, the University of Utah, Southern Methodist University,
and various private and academic sources. The likely resource delineation program will include
acquisition of 3D reflection seismic data over the property in order to define the fault and fracture system,
followed by in-fill electrical field surveys. These data will be modeled using 3D analysis and
visualization techniques. We will also select locations for drilling intermediate depth (1,000 to
2,000 metres) slim holes for the purposes of conducting flow tests. If warranted by positive results from
the proposed exploration program, future exploration programs may involve drilling one or more such
slim holes as well as shallow temperature gradient holes.
Additional gravity, magnetic, and resistivity data are required to infill previous work and further define
the resource. This data will permit further refinement of the resource based on a MT survey. This work
is cost effective at a survey level.
Further delineation of the resource requires integration of geologic mapping data with subsurface
information. This information is partially provided by geophysical data. In this region the most reliable
method for obtaining such information is 3D seismic reflection. This is a higher cost exploration method
that builds on the previously collected data. This information is critical for the area of the Thermo Hot
Springs Property given that any resource is likely to be structurally controlled.
logging. Drilling has not been included in the proposed exploration budget for the Thermo Hot Springs
Property. A determination to proceed with drilling in a future exploration program and the location of
any proposed drill sites will be guided by the less expensive exploration activities described above.
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Early-Stage Exploration Properties
Nevada
Baltazor Property
The Baltazor Hot Springs are located five miles southwest of the tiny and remote town of Denio Nevada,
close to the Oregon border. A second geothermal prospect about ten miles southwest of Baltazor is the
McGee Mountain or as it has sometimes been called in the past, the Painted Hills, geothermal prospect.
The location is very remote with no readily available services. Caldera Geothermal has been recently
active at the nearby McGee Mountain prospect. The Magma lease position at the Baltazor Property
consists of two BLM leases covering 2,688 hectares (6643.08 acres) acquired at a lease auction conducted
by the BLM in August 2009, see “United States Geothermal Leases”. The effective date of the leases is
Sept. 1, 2009. The purchase price for the property was $366,520.
This area was intensively explored by Earth Power Production Company beginning in 1977 and received
funding from the U.S. Department of Energy’s Industry Coupled Program. Therefore, all of these data
are in the public domain in a series of reports, primarily published by the Earth Science Laboratory at the
University of Utah Research Institute (now known as EGI) in the late 1970s and early 1980s. The USGS
also conducted several geophysical surveys in the area in the 1970s.
The area is located in northernmost Nevada where the classic basin and range topography merges into a
terrain that is much more of an undulating plateau. Baltazor Hot Springs is associated with the nearby
normal fault defining the steep east side of the Pueblo Mountains. Researchers suggest that there are
actually two intersecting faults controlling the location of the Hot Springs. The rocks in the area consist
of the usual stratigraphy in western Nevada. That is Quaternary alluvium overlying Tertiary basaltic and
rhyolitic volcanic rocks which overlie a wide variety of Mesozoic age rocks.
The hot water at Baltazor Hot Springs is a dilute sodium mixed anion water. Baltazor is the hottest
thermal spring in far northwest Nevada with reported temperatures ranging from 169°F to 209°F (76°C to
98°C). Baltazor is part of a regional group of thermal springs in the Black Rock/Alvord Desert area with
this chemistry. This regional group of springs extends northward from Double hot springs near Gerlack,
Nevada to Mickey hot springs near the north end of the Alvord Valley in Oregon. Several of these
thermal springs have geothermometers predicting temperatures over 300°F (150°C). Only one of these
systems, Hot Lake north of Denio in Oregon, has been drilled by Anadarko Petroleum in the 1980s or
early 1990s with temperatures over 300°F and a significant flow rate. However, past exploration and
development in this region has been inhibited by the remote location, environmental issues, and a lack of
transmission lines in the area. No deep (>4000 feet) large diameter geothermal wells have ever been
drilled in this region.
The Baltazor thermal water gives a quartz predicted temperature of 329°F (162°C) and a Na/K/Ca
predicted temperature of 306°F (152°C). The magnesium contents are very low so there is no reason to
disbelieve these cation predicted temperatures. A flowing hot well near Baltazor has similar water and
similar predicted temperatures. The presence of a few small low mounds of opaline sinter at Baltazor has
been used as an argument that relatively recently subsurface temperatures of at least 356°F (180°C) were
present in the geothermal system. At the present time Baltazor Hot Spring is not precipitating any silica
phases.
Earth Power drilled 27 shallow temperature-gradient holes to depths of more than 300 feet in 1977 both in
the vicinity of Baltazor and McGee as well a few more widely spaced holes. Earth Power produced a
temperature gradient map from these holes that shows two modestly sized and widely separated thermal
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anomalies, one centered on Baltazor Hot Springs and one on the east side of McGee Mountain. The
McGee anomaly is elongated in a north-south direction indicating that a northerly trending fault or fault
zone is the controlling structure. The Baltazor thermal anomaly is modestly elongated in an east-west
direction, which is a bit curious but could also more simply reflect the hole locations, unconstrained
contouring, or the presence of the low temperature Bog hot springs to the west of Baltazor Hot Springs.
In 1979, Earth Power drilled four holes to 1500 feet - two near the center of the Baltazor anomaly and two
in the McGee area. The two Baltazor holes had maximum temperatures of 154°F and 195°F. In 1982 and
1983, a 3703 foot deep well was drilled at Baltazor with slow penetration rates in hard volcanic rocks and
deviation problems. This well recorded a maximum temperature of 247°F (119°C) at a depth of
3640 feet. The bottomhole temperature gradient was only 1.4°F /100 feet.
We do not have any immediate plans to proceed with exploration on the property but are currently
reviewing available data and doing an assessment of the property in connection with other data available
from other operators in the area.
Beowawe Property
The Beowawe Property is located in northern Nevada astride the boundary between Lander County to the
west and Eureka County to the east. The site is approximately ten kilometres west of the town of
Beowawe and is contiguous with, or near to, the Beowawe geothermal power plant owned and operated
by TerraGen. The Beowawe Property consists of one parcel (BLM lease NVN 085728), with a total
area of 702 hectares (1,735 acres) of federal public lands that were acquired by Magma US at a lease
auction conducted by the BLM in August 2008. The effective date of the leases is September 1, 2008.
Lands included in the parcel are found in T31N, R47E, section 22, and T31N, R48E, sections 8 and 16
(Mount Diablo Meridian). The purchase price for the property was $434,000. For a description of the
terms of the BLM leases that comprise the Beowawe Property, see “United States Geothermal Leases”.
The Beowawe Property is adjacent to the production well field for the 16.6 MW dual-flash Beowawe
geothermal power plant owned and operated by TerraGen. The plant has been in operation since 1985
utilizing greater than 200°C fluids produced from depths of approximately 2,000 metres. Production is
from highly fractured and permeable zones in the Valmy Formation although the ultimate reservoir is
believed to be in Paleozoic carbonate rocks below the Valmy Formation. Production is from the Malpais
fault, a complex, north north-east to northeast-trending oblique slip structure with numerous splays.
The Beowawe Property reservoir temperature is estimated at 226°C to 238°C from the geochemical
analysis and subsequent geothermometer calculation on a fluid sample taken from a steam well drilled in
section 17. A surface hot spring temperature of 98°C in section 8 is reported; the Na/K/Ca
geothermometer run on that sample yielded a reservoir temperature of 237°C, and a quartz adiabatic
geothermometer reservoir estimate of 214°C.
We are evaluating all existing data described above in addition to data found in USGS, University of
Nevada, Reno, Southern Methodist University, and U.S. Department of Energy geothermal databases.
Our proposed resource delineation program will include acquisition of modern, closely spaced reflection
seismic data over the prospect in order to define the fault and fracture system followed by in-fill gravity,
magnetics, and electrical field surveys.
Buffalo Valley Property
The Buffalo Valley Property is located in north-central Nevada in Pershing County. The site is
approximately 27 miles southwest of the town of Battle Mountain. The prospect consists of three parcels
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(BLM lease N-86906, N-86907, and N-86908) with a total area of 5,400 hectares (13,343.88 acres) that
were acquired at a lease auction conducted by the BLM in August 2009. The effective date of the leases
is September 1, 2009. The purchase price for the property was $572,637. For a description of the terms
of the BLM leases that comprise the Buffalo Valley Property, see “United States Geothermal Leases”.
The Buffalo Valley Property is located in the western part of Buffalo Valley and east of the Tobin Range
in classical Basin and Range geology. This property has not been subject to past geothermal exploration
efforts. There are no active thermal manifestations in the western part of Buffalo Valley. The area has
recent faulting, similar to Dixie Valley, and this faulting, along with being within the regional Battle
Mountain High heat flow anomaly, forms the basis for this prospect.
Columbus Marsh Property
The Columbus Marsh Property is located in west-central Nevada in Esmeralda County. The site is
approximately 27 kilometres south of the town of Tonopah Junction (Nevada Hwy. 360 and U.S. 95).
The prospect consists of one parcel (BLM lease NVN 085713), with a total area of 1,036 hectares
(2,560 acres) of federal public lands that were acquired by Magma US at a lease auction conducted by the
BLM in August 2008. The effective date of the leases is September 1, 2008. The purchase price for the
property was $832,000. For a description of the terms of the BLM leases that comprise the Columbus
Marsh Property, see “United States Geothermal Leases”.
The Columbus Marsh Property is situated at the north-east corner of Columbus Marsh, within the
northwest-trending central Walker Lane, which represents the western margin of the Basin and Range
physiographic province. The Walker Lane is the site of an active dextral oblique-slip (transtensional)
fault system that carries approximately four to six millimetres per year of offset transferred from the
Northern Furnace Creek fault zone via the Excelsior Mountains. This transfer feature is called the Mina
deflection, and forms a structural releasing bend geometry where crustal thinning is accommodating the
dextral offset. The Columbus Marsh, Teel’s Marsh, and Rhodes Marsh represent sag areas located on the
hanging wall of a breakaway fault that exhibits top to the south-east motion. Vertical exhumation rates of
0.6 to 1.0 millimetres per year for rocks in the Walker Lane have been calculated indicating relatively
rapid exposure of hot mid-crustal rocks.
A survey of borate deposits in the area of the Columbus Marsh Property was performed and found
evidence of Quaternary borate crusts, which was interpreted as evidence of undiscovered moderate to
high temperature (greater than or equal to 150°C) geothermal resources. Geothermal fluids are known to
contain high concentrations of boron, and it is not uncommon to find elevated subsurface temperatures
associated with elevated levels of boron in surface sediments. Columbus Well CM1 drilled on the
northern boundary of the marsh yielded a maximum temperature of 21.7°C, and geothermometer
calculations on fluids from that well estimated the reservoir temperature to be 115°C. Fluids from nearby
Columbus well 2/36 yielded a Na/K/Ca geothermometer reservoir estimate of 210.5°C.
We are evaluating all existing data described above in addition to data found in USGS, University of
Nevada, Reno, Southern Methodist University, and U.S. Department of Energy geothermal databases.
Our proposed resource delineation program will include conduct of gravity, magnetics, and electrical field
surveys.
Dixie Valley (Whiterock) Property
The Whiterock Property is located in Dixie Valley in west-central Nevada in Churchill County. The site
is remote being approximately 50 miles northeast of the town of Fallon, but it takes one and a half hours
by automobile to reach the site. The prospect consists of one parcel (BLM lease N-86888) with a total
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area of 1,133 hectares (2798.94 acres) that was acquired at a lease auction conducted by the BLM in
August 2009. The effective date of the leases is September 1, 2009. The purchase price for the property
was $1,700,640. For a description of the terms of the BLM leases that comprise the Whiterock Property,
see “United States Geothermal Leases”.
The Whiterock Property is located near the western margin of Dixie Valley about 12 miles southwest of
the operating 56 MW (net) TerraGen dual flash geothermal power plant. The Property is accessible via
an all weather graded and regularly maintained gravel road that provides access to the TerraGen power
plant. The TerraGen 220 kV transmission line passes through the Whiterock Property. TerraGen has
recently announced plans to develop two additional 60 MW power plants in the western part of Dixie
Valley but has not yet commenced the exploration drilling. One of these power plants known as Coyote
Canyon is slated to be constructed about six to eight miles northeast of the Whiterock Property. The
second power plant known as Dixie Meadows will be about six miles south of the Whiterock Property.
The Whiterock Property was extensively explored by the Thermal Power Company in the late 1970s.
There are no active thermal features on or adjacent to this property but hot water was encountered in the
adjacent Dixie Combstock gold mine in the 1930s at shallow depths. The Property is located along the
same large and active normal fault as the operating power plant. This exploration culminated in the
drilling of the 8089 foot deep geothermal exploration well in 1979 immediately adjacent to the Whiterock
Property. This well encountered a five GPM flow of geothermal fluid that is still flowing today and a
bottom hole temperature of 386°F (197°C) in Triassic marine shale. Following the completion of this
well there has been no more recent geothermal exploration in this part of Dixie Valley. The chemical
geothermometers calculated from this fluid indicate a subsurface temperature close to 200°C, basically
the same as the measured temperature. A series of shallow (< 500 feet deep) temperature gradient holes
and slim holes (500 feet to 2000 feet deep) were drilled adjacent to the Whiterock Property and show that
the property is characterized by high temperature gradients.
Granite Springs Property
The Granite Springs Property is located in west-central Nevada in Pershing County. This prospect was
defined and explored by Phillips in the early 1980s under the name Adobe Valley. The prospect currently
consists of all five Federals parcels (BLM lease N-86862, N-86863, N-88400, N-86865, and N-86866)
with a total area of 9,046 hectares (22,352 acres) that were acquired at BLM auctions in August 2009 and
May 2010. The effective dates of the leases are September 1, 2009 and June 1, 2010. For a description of
the terms of the BLM leases that comprise the Granite Springs Property, see “United States Geothermal
Leases”. On September 1, 2010, 7682.44 acres of Federal leases were relinquished as they were
determined to be located north of and outside of the shallow thermal anomaly defining the prospect. The
total acquisition cost of all leases currently held and relinquished at Granite Springs is $441,670.
The Granite Springs Property is a large contiguous block of land that overlies a shallow thermal anomaly
up to eight miles long in a north-south direction and up to four miles long in an east-west direction. This
thermal anomaly was largely outlined by Phillips with approximately 30 shallow temperature-gradient
holes and lies in the central part of the broad Granite Springs Valley. Phillips drilled one strat test (slim
hole) AV-ST-1 in 1983 to a depth of 1795 feet and measured a maximum temperature of 193.5°F at the
bottom of the hole. This hole was simply sited within the heart of the shallow thermal anomaly. It was
not sited to evaluate any specific structural target. The temperature gradient at the bottom of AV-ST-1
was close to zero so there is no way to predict what temperatures are likely to be at greater depths. There
are no surficial thermal features associated with the shallow thermal anomaly but two water samples were
recovered from shallow wells within the thermal anomaly. These two waters give predicted quartz
geothermometer temperatures of 227°F and 323°F. The Na/K/Ca predicted temperatures are 255°F and
376°F. To the west of the thermal anomaly the active Shawave Fault Zone separates the Shawave
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Mountains from Granite Springs Valley and is a likely structural target. Perhaps some eastern strands of
this fault zone or hidden faults further east of the mountains transmit hot water up to shallow depths in the
western part of Granite Springs Valley. This is the largest known thermal anomaly in Northern Nevada
that has only one slim hole drilled into it. It is worthy of some additional exploration and at least one or
two additional slim holes.
Soda Lake East Property
The Soda Lake East Property is located in west-central Nevada in Churchill County. The western
boundary of this Property is located two miles east of the PA boundary for the operating Soda Lake power
plant. The eastern boundary is located six miles east of the PA boundary. The prospect consists of one
parcel (BLM lease N-86872) with a total area of 1,526 hectares (3770.72 acres) that was acquired at a
lease auction conducted by the BLM in August 2009. The effective date of the leases is September 1,
2009. The purchase price for the property was $7,542.00. For a description of the terms of the BLM
leases that comprise the Soda Lake East Property, see “United States Geothermal Leases”.
The Soda Lake East Property is a greenfields prospect located between the operating Stillwater
geothermal field and the known operating Soda Lake Property in the Carson Sink. The geothermal
industry has not performed any significant exploration in this area in the past because it has no active
thermal manifestations or young volcanic rocks. Northwesterly trending Quaternary fault scarps of the
Sagouse Fault Zone cut across the Property.
Upsal Hogback Property
The Upsal Hogback Property is located in west-central Nevada in Churchill County. The lands within
this Property essentially form a rim around the northern part of the operating Soda Lake power plant PA.
The prospect consists of two Federals parcels (BLM lease N-86869 and N-86870) with a total area of
3,554 hectares (8153.57 acres) that were acquired at a lease auction conducted by the BLM in August
2009. The effective date of the leases is September 1, 2009. The purchase price for the property was
$16,230. For a description of the terms of the BLM leases that comprise the Upsal Hogback Property, see
“United States Geothermal Leases”. One private lease covering 626.5 acres is included within the
property.
The Upsal Hogback Property lies immediately east, north, and west of the PA outlining the existing
operating Soda Lake project and so jointly overlies the distal portions of the Soda Lake thermal anomaly
with the operating project. A portion of this Property can be viewed as containing the northwest, north,
and east margins or extensions of the Soda Lake resource while the more northerly part of the Property
most likely lies beyond the resource boundary. One or two 1000 foot deep temperature-gradient holes
will be drilled in September 2010 to further evaluate this Property.
Oregon
Glass Buttes Property
The Glass Buttes Property is located in Lake County, Oregon about 16 kilometres southeast of the town
of Hampton and 80 kilometres west of the city of Burns along Highway 20. Magma US holds two federal
leases (OR-65729 and OR-65730) from the BLM, with a total area of 3,607 hectares (8,914 acres). The
two leases were acquired at a BLM geothermal lease sale in December 2008 for a total purchase price of
$77,014. The primary lease term of ten years began on February 1, 2009 with an annual lease rate of $3
an acre, or $26,745 a year. For a description of the terms of the BLM leases that comprise the Glass
Buttes Property, see “United States Geothermal Leases”.
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The federal leases can be extended for three five-year periods, if needed, with the rental fee increasing to
$5 an acre. Rental fees can be written off against royalties paid once the lease area goes into production.
The royalty arrangement on the Glass Buttes Property is 1.75% of gross proceeds for the first ten years of
production, increasing to 3.5% of gross proceeds beginning in the 11th year with a minimum payment of
$2 an acre. The lease is valid as long as production continues or BLM determines the lessee is diligently
trying to put a producible well into actual production.
Shortly after the leases were issued by the BLM, Magma became aware that the Oregon Natural Desert
Association filed an appeal and petitioned the Interior Board of Land Appeals (“IBLA”) for a stay of the
decision by the BLM to issue the leases. In April 2008, the IBLA denied the petition for a stay. On
July 9, 2009, the IBLA affirmed the BLM’s decision to issue the leases. Accordingly, we consider the
proceeding to be resolved and the lease to be in force.
The Glass Buttes Property is within the High Lava Plains physiographic province of Oregon and is cut by
a north-northwest trending fault zone which contains the high silica volcanic rocks of the region. The
appearance and manifestation of the geothermal zone is controlled by these faults. Some of the faults
show normal offset which suggests there is an open set of fractures along which geothermal fluid could
move. A set of faults to the southwest has a more oblique offset and may be a bounding structure on the
heat anomaly and fluid flow.
Hydrothermal alteration penetrates at least to 610 metres in the eastern portion of the lease area indicating
an extensive near surface hydrothermal system in the past. An electrical resistivity survey revealed
marked contrasts with a broad area of low resistivity at depth, which can be an indicator of the presence
of geothermal fluid.
Past geothermal exploration activity, which began in 1974 and continued through the early 1980’s,
includes numerous drilled temperature gradient holes, geologic mapping, an electrical resistivity survey
and a soil-mercury survey. Initial work was sponsored by the Oregon Department of Geology and
Mineral Industries and later by the geothermal lease holders Vulcan Geothermal Group and Phillips. Four
temperature gradient holes were drilled within the leased property during initial exploration work within
the leased property: GB-1 drilled to 353.6 metres had a maximum temperature of 36°C, GB-16 drilled to
609.6 metres had a maximum temperature of 58°C, GB-18 drilled to 393.2 metres with a maximum
temperature of 74.3°C and GB-31 drilled to 355 metres had a maximum temperature of 36.9°C.
We are reviewing all the existing geological, geophysical, and geochemical data acquired by the USGS,
U.S. Forest Service, University of Nevada, Reno, Oregon State University, Southern Methodist
University, and the U.S. Department of Energy. Our proposed resource delineation program will include
acquisition of geochemical and geophysical data including magnetic, gravity, resistivity, and seismic
surveys.
III.
South America
Mariposa Property
Certain statements in the following summary of the Mariposa Property are based on and, in some
cases, extracted directly from, the Mariposa Report prepared on behalf of Magma by Philip James
White of SKM who is independent from the Company. See “Scientific and Technical Information”.
Reference should be made to the full text of the Mariposa Report which is available for review on
SEDAR located at www.sedar.com.
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Concession History and Status
The Mariposa Property is comprised of the adjacent Laguna del Maule and Pellado geothermal
concessions, which are located approximately 300 kilometres south of Santiago and 120 kilometres
southeast of Talca in the Maule Region of Chile. Magma has been working on the Laguna del Maule
geothermal concession since 2008. This exploration concession was purchased from the University of
Chile, which had identified the geothermal potential of this area. The original concession covered an area
of 400 square kilometres. In July 2009, Magma applied for four square kilometres of this area to be
converted into an exploitation concession, and that was awarded by the Chilean government on May 5,
2010.
Magma applied for rights to the Pellado exploration concession to the west of Laguna del Maule in early
2009, and that was granted in January 2010. Magma owns 100% of the Laguna del Maule and Pellado
concessions through its wholly owned subsidiary Magma Energy Chile Limitada. A geothermal system
has been outlined that extends between the Laguna del Maule and Pellado concessions. This is now
known as the Mariposa geothermal system. This resource estimate applies to the whole of the Mariposa
geothermal system within both concessions.
In the first few months of 2009, Magma undertook geological mapping, chemical sampling and analysis
of fumaroles, and an MT resistivity survey over Laguna del Maule and part of the Pellado concession.
Based on the results of this work, a vertical slimhole was sited within the identified resistivity anomaly in
the Laguna del Maule concession, and this well was drilled in May-June 2009. The objective of this well
was to prove temperatures within the reservoir. Well MP-01 was completed to a depth of 659 metres in
early June, and a maximum temperature of 202°C was measured just above the bottom of the well
(651 metres) after seven days heating.
The Pellado concession was awarded on January 11, 2010, and published on January 19, 2010 and has a
two year term, which may be extended for a further two years, but must then be converted into an
exploitation concession or relinquished. The Laguna del Maule exploitation concession is for an
unlimited term provided annual fees are paid.
In March 2010, another well MP-02 was drilled. This slim hole is located on the Pellado portion of the
Mariposa Property and is currently undergoing testing and evaluation. A third well MP-03 is currently
being drilled on the Maule portion. To provide for access to these drill sites, 24 kilometres of road has
been constructed and facilities for crews necessary for drilling and winter operations have been erected at
the property.
Geophysical surveys are continuing, with gravity and magnetic surveys and additional MT stations
completed in the first half of 2010, along with further geological mapping.
The terrain is mountainous, with elevations ranging from about 700 metres above sea level in the valleys
to over 3600 metres above sea level on Volcán San Pedro. The valleys have steep sided glacial shapes,
but higher up, the slopes are generally more gentle.
Geological Setting
The Mariposa Property is located in the northern part of the southern volcanic zone of Chile, in an arc
volcanic setting. To the west of Chile, young oceanic crust of the Nazca Plate is being subducted beneath
the South American Plate at the Chile (or Atacama) Trench at the comparatively rapid rate of about
80 millimetres per year. This subduction gives rise to the volcanic activity within the Andes. Rapid
subduction, such as occurs at the Mariposa Property, favours the production of numerous potential
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magmatic heat sources for geothermal fields. Many geothermal systems have been identified in this
section of the Andes, although none have yet been developed for power production.
In addition to volcanic activity, the near-perpendicular subduction that is directed slightly north of east
produces compressive stress within Chile. The stress orientation is indicated by fault orientations, and by
the orientation of dyke intrusions. To the west of the Laguna del Maule concession, in the Pellado region,
dykes mainly trend north-south and northwest-southeast, although significant intermediate to silicic dykes
trend north 70º east. To the east, the Troncoso (La Fea) fault trends north 30-40º east. Preliminary
structural analysis (including lineaments noted on satellite imagery and compiled from literature) suggests
a strong north to northeast trend within the concession.
Surface Geology
The regional geology of this area is reasonably well understood, after geological mapping and studies by
international teams of the Cenozoic volcanism in this area. Magma’s geologists are building up a detailed
knowledge of the geology in the Laguna del Maule concession through detailed mapping in the La Plata
valley and in the vicinity of well MP-01.
Surficial glacial moraine and fluvial deposits are widely distributed, particularly within deep glaciated
valleys, and commonly tens of metres thick.
The Pellado Formation comprises unaltered Holocene to Pleistocene age andesitic to basaltic lava flows
with minor intercalated clastic overlying rhyolitic lava flows with basal obsidian layers, and pumiceous
rhyolitic pyroclastic flow deposits. This formation is in the order of 200 metres thick, and hosts cool
groundwater aquifers, especially in the upper, more permeable layers.
The Campanario Formation comprises deformed (folded and faulted) Mio-Pliocene volcaniclastic
deposits and interbedded basaltic to andesitic lava flows and pyroclastic flow deposits, including pumice
tuffs and lithic tuffs, some of which are welded. Pervasive clay alteration commonly gives these rocks a
greenish colour, although the alteration mineralogy and intensity (and hence colour) vary with location
and depth. The Pellado Formation rests unconformably on the Campanario Formation and older units,
including the Trapa-Trapa and Cura-Mallin formations.
A number of intrusive bodies have been mapped in the region, including dioritic and possibly gabbroic
bodies of Cretaceous, Miocene and Pliocene age. Some of these appear to intrude (and thus post-date) the
Campanario Formation, and some may unconformably underlie it (and are thus older). One such
intrusive was recently mapped in the La Plata valley 1.5 kilometres to the northwest of MP-01, and there
is a large granitic to tonalitic El Indio stock to the north. MT geophysical surveys suggest that these
intrusives do not occur within the conjectured reservoir area.
Within the Pellado concession area, the Late Jurassic Río Damas Formation, a continental succession of
red bed conglomerates, sandstones and subordinate siltstones, is exposed. Further north, the Río Damas
Formation overlies Jurassic Baños del Flaco Formation marine sediments. Limestone beds and lenses are
present in the Baños del Flaco and Cura-Mallin formations. Marine sediments (Nacientes del Teno
Formation) also crop out 20 kilometres south of Laguna del Maule, and similar marine successions,
including gypsum beds and limestones are exposed a few tens of kilometres to the east, in Argentina.
Consequently, there is a strong chance that marine sediments, limestones, and gypsum beds underlie the
volcanics and volcaniclastics in the Laguna del Maule and Pellado concessions.
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Subsurface Geology
The geology encountered in MP-01 was largely as expected from an assessment of the local surface
geology. The unconsolidated alluvial material was 13.5 metres thick, and overlay a sequence of relatively
fresh basalt lavas (to 177 metres), breccias (to 197 metres) and interlayered andesitic to basaltic lavas and
volcaniclastic deposits (to 542 metres). Further depths encountered mainly lithic tuffs and volcaniclastic
sediments, including sandstones, siltstones and conglomerates composed of porphyritic volcanic
fragments. No intrusive rocks were observed. The well geology from MP-02 is currently being reviewed
and integrated into the geological model of the reservoir.
Hydrothermal Alteration
In general, there is very little alteration visible at the surface, particularly within the young volcanic
sequence of the Pellado Formation. This is not thought to be because those units are young (the
geothermal system is even younger), but because they are at high elevation, above the geothermal system,
and host cold groundwater that is separated from the hot reservoir by an altered clay rich zone.
Areas of hydrothermal alteration are visible at the surface in several places within and around the
concession, including around the areas of surface thermal activity.
Within well MP-01, very little alteration was observed in the upper 200 metres. Only minor quartz,
calcite and smectite have been identified. Below 200 metres, the alteration intensity gradually increased,
and the mineralogy changed from interlayered illite-smectite, chlorite-smectite, tridymite and cristobalite
above 500 metres to illite, chlorite, quartz, calcite and adularia below 500 metres, with epidote from
540 metres and prehnite at 638 metres.
The transition from smectite to interlayered illite-smectite to illite with depth was examined during
drilling using methylene blue analysis. This technique measures the ion exchange capacity of a rock,
which in this case is due primarily to the presence of smectite. Methylene blue values were initially very
low in the unaltered lavas down to a depth of 177 metres. These rocks contain very little clay. The
highest value (41) was found at a depth of 191.5 metres, and values remained high to about 400 metres,
reflecting the depth interval where smectite and smectite-rich interlayered clays predominate. Methylene
blue values then declined to be mostly less than four below 480 metres, reflecting the transition to noninterlayered illite at that depth.
The mineralogical changes with depth in the well are consistent with increasing temperatures, from less
than 200°C at 300 metres to 240°C at 540 metres. The assemblages are indicative of fluids of nearneutral pH throughout the drilled depths. The presence of open space platy calcite crystals at 511 metres
provides evidence of boiling, and hence two-phase fluids. Prehnite at 638 metres is commonly found in
zones of low permeability, as appears to be the case here. While the trends are consistent with steadily
increasing temperatures with depth, epidote appears shallower than expected, and has a corroded
appearance indicative of retrograde alteration. This suggests that the mineralogy is not entirely indicative
of current temperatures, but reflects a slightly higher temperature profile that formed at some time in the
past.
Surface Thermal Activity
The Los Hoyos thermal area comprises several areas of diffuse steaming ground over an area of about
100 by 100 metres at an elevation of 2,190 metres above sea level in the northwest of the Laguna del
Maule concession. The steam has temperatures of up to 93°C, which is the boiling point at this elevation.
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The La Plata thermal area is located two kilometres to the west of Los Hoyos, within the Pellado
concession, on the northern side of the La Plata River at an elevation of 1950 metres above sea level. It
consists of several pockets of steaming ground and a few bubbling pools spread over an area of about 50
by 20 metres. The thermal vents appear to be aligned on an east-west structure. Temperatures reach the
local boiling point of about 93°C. There is very little sulphur.
The Pellado thermal area is about 6.6 kilometres west southwest of La Plata, at an elevation of
2,430 metres above sea level. The activity consists of steaming ground and steam vents located on a steep
hillside and spread over an area of about 50 by 20 metres. A stream runs through the thermal area,
drowning some of the steam vents or causing the water to spout vigorously. To the side of the stream is a
superheated vent with a temperature of 120°C (about 30°C above the local boiling point of 90°C). The
vent is strong and very noisy. No sulphur is deposited from the vent.
Geochemistry
Fumarole gas samples were collected by SKM and Magma in March 2009. Analysis of the steam from
these fumaroles indicates that the deep fluids are likely to have low to moderate (<1%) gas contents.
Furthermore, the gas chemistry indicates two-phase or vapour-dominated conditions, which have
probably developed above a liquid reservoir.
The occurrence of fumaroles (as opposed to diffuse, weakly steaming ground) is itself an indication of
high temperatures, since fumaroles are rarely seen in systems with temperatures under 200°C. The
application of gas geothermometry commonly gives a broad indication of temperature range and the
relative proximity of geothermal features to the centre of the resource.
The superheated condition of the Pellado fumarole and its isotopic composition suggest that the Pellado
steam more closely represents conditions at the centre of the geothermal system. The Los Hoyos and La
Plata steam has lower gas content than Pellado, which suggests the steam here has boiled off a partly
degassed deep liquid. The relatively lower carbon dioxide/sulphuric acid ratios for La Plata and Los
Hoyos are consistent with this, since sulphuric acid is more soluble than carbon dioxide and appears in
higher proportions in later-stage steam. These characteristics suggest that there is a deep liquid reservoir,
as opposed to the system being entirely vapour-dominated.
Further evidence of the deep fluid chemistry can be gained from the alteration assemblages observed in
outcrops and in drillcore. These assemblages indicate fluids of near-neutral pH. At this stage there are no
indications that there will be issues with severe scaling provided industry-standard methods are adopted,
nor with acid fluids.
The steam from the Pellado fumarole is isotopically heavier than the steam from Los Hoyos and La Plata,
and could be generated from boiling of a deep reservoir liquid close to that of local meteoric water. This
indicates that the reservoir water is recharged locally. The Los Hoyos and La Plata steam has a lighter
composition, which suggests interaction with groundwater. This would normally result in higher gas
contents as a result of steam condensation. The fact that the gas contents are lower than at Pellado
suggests the deeper steam beneath the Laguna del Maule concession has a much lower gas content.
Geophysics
Magma completed a deep-penetrating MT survey over the Laguna del Maule exploration concession and
over the wider area, including much of the Pellado concession, in April 2009. The goal of this survey was
to map the deep resistivity patterns in order to better understand the location, depth and lateral extent of
the hydrothermal system. MT survey stations were established across the area, and the data was
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processed using 3D modelling, to produce a three dimensional model of the subsurface resistivity
structure.
A low resistivity anomaly was identified extending west from just south of the Los Hoyos fumarole to
just north of the Pellado fumarole, covering a total area of about 23 square kilometres. This area of low
resistivity has a butterfly shape with two distinct lobes, one in the Laguna del Maule concession and
centred near well MP-01, and the other five kilometres to the west, in the Pellado concession.
The low resistivity layer is of the order of 200 metres thick, and is overlain by very high resistivity
material which corresponds to the unaltered Pellado Formation volcanic material at the surface. The
elevation of the base of the low resistivity layer varies between about 1,720 and 1,860 metres above sea
level, and hence between about 250 metres (near La Plata) and 1,000 metres (in the south) below the
surface. The base of the conductive layer is at a depth of about 600 metres in the vicinity of MP-01.
Accordingly, it is close to the bottom of the well and consistent with the mineralogy and temperatures
encountered.
This conductor is typical of the clay alteration cap which forms over active geothermal systems. The
shape of this feature highlights two main low resistivity centres, which are probably caused by the
presence of two principal upflow zones (which could nevertheless be hydrologically linked). The
fumaroles occur at the edges of this conductive feature, which supports the interpretation of it acting as an
impermeable cap.
The absolute resistivity values that occur within this conductive body are slightly higher than is typical
for geothermal systems. The minimum resistivities modelled in the conductive body are around four ohm
metres, which is at the high end of the normal range (typically one to four ohm metres) in such
hydrothermally-induced features in volcanic sequences. The factors affecting resistivity include porosity,
fluid salinity, matrix resistivity (affected by alteration clays), and temperature. Temperature is not usually
a very sensitive parameter, and alteration clays are present in the principal conductive zone, so the
observed resistivity values here may be due to a combination of the very high resistivity of the original
rock matrix and possibly a relatively low porosity at depth.
Porosity and Permeability
The core taken from reservoir depths in MP-01 is dominated by medium to coarse grained pyroclastic and
epiclastic deposits, including lithic tuff, sandstone and conglomerate, which should have at least moderate
porosity and permeability. However, some of the original porosity will have been reduced by the
deposition of secondary minerals, thereby reducing the permeability of these layers. There are also some
interbedded finer layers, including siltstone, which will have lower porosity and permeability. In
addition, faults were intersected at 614 and 638 metres, with that at 638 metres being described as
intensely fractured.
No significant fluid losses were encountered during drilling, although the well was not targeted to
intersect permeable faults. Past experience has shown that in most geothermal systems worldwide
permeability is focused on major fault structures, and there is no reason to believe that this geothermal
system is any different. In view of the limited exploration that has been completed to date, the lack of
evidence for high permeability is not a negative feature of this field. The presence of fumaroles, and
measured temperatures over 200°C at 650 metres indicates that there is fluid flowing within the system.
As in any geothermal system, future production wells will need to target permeable zones to be
commercially successful.
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Temperature
The existence of fumaroles at Los Hoyos, La Plata and Pellado provides good evidence that a high
temperature geothermal system exists at depth beneath this area, since fumaroles generally do not occur
over low-grade resources. Geothermometry calculations using the fumarole gas composition indicate
deep reservoir temperatures of 200°C to 250°C.
Alteration minerals seen in well MP-01, which include non-interlayered illite and epidote, indicate that
temperatures are less than 230°C down to a depth of about 500 metres, then increase to over 240°C below
540 metres. However, there are some textural indications that the mineralogy does not entirely reflect
current conditions, and is over-estimating current temperatures.
Fluid inclusion analysis did not indicate any correlation between homogenisation temperature and depth.
Three of the four samples examined contained measurable inclusions within vein quartz or calcite
crystals, and all samples contained many inclusions that were too small to measure. The highest mean
temperature (251°C) was from the shallowest sample (419.5 metres), for which five homogenisation
measurements covered a 5°C temperature range. This temperature is inconsistent with the alteration
mineralogy at that depth, which points to temperatures less than 230°C, and is also inconsistent with
boiling point for depth constraints, particularly in view of the deep water level indicated by the pressure
data. This means that at least some of the veins did not form in the currently active geothermal system,
but either formed at some time in the past when the water level was higher, or there was a more extensive
two phase upflow.
With only one or two fluid inclusion measurements from each of the other two samples, these
measurements have less significance. However, two of the three measured homogenisation temperatures
are significantly lower than would be expected for these samples on the basis of the alteration mineralogy
at these depths. Thus SKM concluded that fluid inclusion measurements in MP-01 core are of limited
help in estimating downhole temperature conditions during drilling.
The temperature and pressure profiles from the well indicate a maximum temperature of 202°C at
651 metres, after seven days heating. The pressure profile indicates that the water level is at a depth of
about 300 metres.
Project Description
Current Development Status
The initial exploration program that included the drilling of exploration well MP-01 was completed in
June 2009, and an application was submitted in July 2009 for a licence to exploit the geothermal resource,
which has now been granted. Construction of an access road from the nearby highway (Route 115) to the
area of the geothermal system has been completed, the second well (MP-02) is now being tested and a
further well MP-03 is currently being drilled.
Proposed Development
The application from Magma to the Chile Ministry of Mining for an exploitation concession was based on
plans to generate at least 50 MW of electrical power within the Laguna del Maule concession. With the
MT data indicating that the larger part of the geothermal system lies within the Pellado concession to the
west, the scale of the development may be expanded, although the technology and general process will be
similar to what was proposed in that application. The following discussion regarding the proposed
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development is based on the 50 MW development plan for the Laguna del Maule concession. The
resource estimate however is for the entire Mariposa Property.
Drilling
Completion of the slimhole well MP-01 confirmed that reservoir temperatures are above 200°C. Drilling
of additional slimholes is now under way, and drilling of standard and large diameter geothermal
production wells will follow once the necessary equipment and consumables are procured, and a drilling
contractor mobilised.
One of the largest unknown cost factors is the number of wells that will be required. At this stage,
knowledge of the subsurface permeability is limited to what was encountered in the first small diameter
exploration well, and what can be seen from the rocks that are exposed at the surface. This estimate is
based on average well productivities from similar geothermal systems elsewhere.
The success ratios and outputs of production wells are highly variable, ranging from wells that are noncommercial because they are not sufficiently hot or permeable, to the equivalent of over 40 MW electrical
from wells that encounter dry steam in highly fractured reservoirs. For Laguna del Maule, a number of
steps have been taken to increase the likelihood that the production wells will be highly productive. The
extent of the reservoir has been defined by MT geophysical surveys, wells will be drilled inside that area,
the temperature of that reservoir has been estimated from gas geothermometry and alteration mineralogy
in MP-01 to be over 230°C, and the orientation and location of permeable structures will be confirmed
prior to the commencement of production drilling through detailed surface structural mapping and deep
slimhole drilling. Production wells will be deviated rather than vertical, which will increase their chances
of intersecting sub-vertical permeable fractures, if they are oriented correctly.
Based on these factors, successful production wells are expected to have an average output of eight MW
electrical. Some wells may have a very low output, or may not discharge at all, while others will produce
more than ten MW electrical, and possibly more than 20 MW electrical. If, as it appears may be the case,
there is a dry steam zone, even higher outputs could be achieved. A 50% success rate is assumed for the
first four exploration wells, and a 70 to 80% success rate for subsequent development drilling. A
production margin for well workovers requires that 10% more steam is available at plant commissioning
than the steam required for the 50 MW electrical power plant. An additional production margin of 10%
above that for well workovers is set to allow for well decline, such that the first make-up well is not
required for several years.
Based upon the above analysis, a total of 12 production wells are required to achieve eight successful
production wells. Accordingly, four production well pads were identified in the development plan from
which the proposed production wells will be drilled.
The average injection capacity per successful well is assumed to be 300 tonnes per hour. Based on that
assumption, SKM estimated that four injection wells would be required for a 50 MW electrical power
plant.
In reality it may be possible to use some of the unsuccessful production wells as injection wells, but this
cannot be assumed, and unsuccessful production wells may not make good reinjection wells. It is also
possible that a successful but unusable exploration well may be used for reinjection, provided that it is not
too far away.
Two reinjection well pads have been identified, from which the four reinjection wells will be drilled. It is
likely that one vertical well and one deviated well will be drilled on each reinjection well pad.
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Based on the above figures, the following wells are required for the planned development:

12 production wells; and

Four injection wells.
This number of wells and their proposed locations have been used in the financial model and field layout
for costing.
Fluid Collection and Distribution System
There are no unusual aspects to the proposed surface fluid collection and distribution system. Industry
standard designs and materials will be used. As the layout has to allow for wells that have not yet been
drilled, it cannot be accurately costed as yet, but appropriate contingencies have been allowed in the
financial model and this aspect is not considered to significantly affect the project economics.
Power Plant
The development plan considered various generation options before deciding on single flash condensing
steam Rankine cycle technology, using two 25 MW electrical (net) steam turbines. Single flash steam
Rankine cycle is the most common technology used in geothermal developments, and was considered to
offer the most cost effective, technically viable option for a green fields development with the resource
characteristics identified for the Mariposa Property. However, it is possible that over time the plant
configuration may be optimised to include other technology cycles.
Grid Interconnection
With a number of hydro electric power plants in the Maule valley immediately to the north of the
Mariposa Property, as well as planned development to the southwest in the El Melado – A. Rodriguez
drainages, interconnection to the central power grid will be relatively straight forward.
Modifying Factors
This section identifies the major constraints that may limit or prevent economic development of the
geothermal system. These issues must be considered and addressed before the project can be considered
sufficiently technically robust that reserves can be declared. These include technical, environmental,
social, legal and financial issues, all of which could potentially impact on the project feasibility.
Gas Content
The reservoir gas content appears to be low (about one weight percent) compared to most other similar
geothermal reservoirs. It has not been accurately measured at this stage, and this estimate of the deep gas
content is inferred from the fumarole gas chemistry. It is possible that some parts of the reservoir will
have much higher gas contents, and it is also possible for gas contents to increase with time.
Scaling Potential
The main types of scaling that occur in geothermal wells and pipe work are normally due to the
deposition of silica, calcite, and/or anhydrite. Other less common deposits include sulphides, magnesium,
ammonium and iron carbonates.
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The silica content of geothermal fluids is typically linked to the temperature of the feed zone: higher feed
zone temperatures mean a greater likelihood of silica deposition within wells and pipelines. With no
opportunities yet to analyse the deep reservoir fluid, and the deep temperatures not being well
constrained, it is not possible to determine the potential for these fluids to present problems with silica
scaling. However, silica scaling can generally be minimised or prevented by optimising the separator
pressure once the silica content of the deep fluid has been determined, and generally after the completion
of silica polymerisation trials. Thus, silica scaling can be managed by good engineering design of the
geothermal fluid collection and disposal system. If the Mariposa geothermal system is vapour dominated
or two-phase, then the risk of silica scaling is very much reduced.
Calcite scaling is a problem in some geothermal fields, particularly where there are low temperatures and
high gas and bicarbonate contents. With preliminary evidence indicating low gas contents at Mariposa, it
does not appear that calcite scaling will be a significant issue. The potential for calcite scaling may
increase if there are bicarbonate-rich peripheral waters, which could encroach on the reservoir if pressures
were allowed to decline greatly. However, the technology exists to control calcite scaling if it does
become a problem, typically using downhole antiscalant dosing.
Although little is known about the deep reservoir chemistry, based on the conceptual model SKM
believes that the risk of anhydrite scaling occurring is low.
Corrosion
Corrosion in geothermal production facilities is generally associated with acidic conditions in the resource
or inattention to steam quality issues within the surface facilities.
From the preliminary chemistry data and alteration minerals identified to date, there is no evidence of
acidic fluids at the Mariposa Property.
Volcanic and Seismic Hazards
Most developed high temperature geothermal systems around the world are located in volcanically active
areas. The Mariposa Property area is no different. The nearest Holocene age volcano is Volcán San
Pedro, a young scoria cone just 4.5 kilometres west of the Pellado fumarole. No historical eruptions have
been reported from this volcano, which has been the source of a major debris avalanche, in addition to
lava flows. Deeply incised valleys and a narrow connecting ridge mean that any future lava flows and
debris avalanches are very unlikely to directly affect the Mariposa Property, although ash from any
pyroclastic eruptions could reach the site.
Further afield are the late Pleistocene to Holocene aged stratovolcanoes of Nevado de Longaví
(40 kilometres southwest) and Descabezado Grande (40 kilometres to the north). An eruption near
Descabezado Grande and Cerro Azul (seven kilometres to the south) in 1932 spread ash as far as Laguna
del Maule, but no historical activity has been recorded at Nevado de Longaví. With just one historical
eruption having caused ash fall on this concession (and that probably being less than a damaging amount),
the risk of a damaging eruption over the lifetime of this project is considered low. The risk is no greater
than at many geothermal developments.
Being situated above an active subduction zone, Chile is seismically active, and earthquakes are felt at
fairly regular intervals. Again, this feature is not particular to this project, but is common to most high
temperature geothermal developments worldwide. The risk is not particularly high, provided engineering
designs incorporate appropriate seismic design codes, and any active fault traces are located and avoided
when siting key facilities such as the power plant and separator station.
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Infrastructure, Geotechnical, Environmental, Land Use and Social Issues
There are no unusual geotechnical issues on the proposed site. The access road traverses some steep
slopes and crosses the La Plata valley, but the challenges are no greater than those on Route 115 to the
border. As with any geothermal development, special care will be needed around any thermal ground,
which should be avoided wherever possible. It is understood that there are adequate supplies of water for
drilling within the groundwater aquifers on site, which are replenished mainly by snowfall during winter.
The project components will have to be designed to cope with severe winter climatic conditions,
including a high avalanche risk in some locations, but similar geothermal projects have been successfully
brought into operation in similar or worse climatic zones elsewhere.
Environmental issues were addressed by Magma in its application for an exploitation concession. This
considered the potential impacts of the project on air, water, noise, fauna and flora, thermal features, and
groundwater, including the possible effects of drilling and construction activities. The environmental
issues and likely impacts at this project are no more challenging than at many other geothermal projects,
which are often located in sensitive environments.
There are no permanent residents within the concession area, which is only grazed during summer months
due to the high elevation and thick snow cover during winter. To date, relationships with landowners
have been good, with exploration activities, including drilling, proceeding without delay. It is expected
that with good management, there should be very limited adverse impact on the local communities.
Power Plant Technology
The proposed single flash condensing steam Rankine cycle generating plant is industry standard
technology that is used in geothermal developments around the world. There are a number of
manufacturers capable of supplying this type of plant, and the technology can be considered to be proven
and low-risk. Attention will have to be paid to the cooling circuit design to cope with winter conditions
but the low average ambient temperatures will be favourable for the power plant efficiency.
Transmission and Electricity Market
The transmission lines which would be required to connect the Mariposa project to the grid are
comparatively short at 15-25 kilometres. The quantity of power to be produced should be readily
accepted by the grid operator.
Security of Tenure
Chile passed a geothermal law in 2000, which provided the framework for the exploration and
development of geothermal energy in the country. Since then, a number of local and international
geothermal development companies have sought and obtained geothermal exploration and a few
exploitation concessions and undertaken project activities.
The law establishes the existence of exploration and exploitation concessions, which as of 2010 are
granted by the Ministry of Energy. Exploration concessions are valid for two years and may be extended
for further two years if sufficient funds have been spent on exploration. Exploitation concessions give the
owner exclusive rights to all geothermal fluid and power within the concession for an unlimited term.
Therefore, assuming that Magma meets the concession conditions, they will hold secure tenure over that
concession.
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Project Economics
A preliminary budget estimate was prepared as part of the development plan, based on the conceptual
field development as outlined above. A PPA has not yet been negotiated, but with Chile relying on
imports to meet some 70% of its energy needs, it should be possible for Magma to negotiate a PPA at
realistic rates that reflect the costs and risks associated with such a development, and which therefore
allow the project to proceed.
Resource Estimate
Input Parameters
The key parameters upon which the stored heat estimate are based are discussed below.
Project life
SKM assumed the project life of the Mariposa Property to be 30 years, as that is the planned project life
in the development plan submitted to the Ministry of Mining. This assumes the full recoverable energy is
extracted within 30 years. Adopting a longer project life would mean that a smaller MW electrical output
would be sustainable.
Reservoir Volume
The resource volume is defined as the volume or rock that can be reached by drilling at above the cut-off
temperature (165°C), which lies beneath the area of the resistivity anomaly as it is defined by the MT
surveys. The resource volume is calculated by multiplying the resource area by its thickness. The
resource area is taken to be 23 square kilometres, based on the extent of the MT geophysical anomaly,
which at most drilled geothermal systems corresponds closely to the extent of the system, provided there
are no areas of relict alteration. Upper and lower estimates were 20 and 26 square kilometres,
respectively. This is the total area of the Mariposa reservoir in both the Laguna del Maule and Pellado
concessions, whereas the 50 MW electrical project was proposed just for the Laguna del Maule part of the
resource.
The top of the reservoir is assumed to lie beneath the base of the conductive layer, which is at an average
elevation of about 1,800 metres above sea level, or on average about 700 metres below the surface.
Allowing for limited permeability and lower temperatures close to the conductive layer, it is estimated
that the average depth to the top of the reservoir is 800 metres, with likely upper and lower limits of 600
and 1,000 metres. The base of the reservoir is taken to be 500 metres below the depth that can be readily
accessed by drilling, or where temperatures decline below 165°C in any outflow zones. This gives a most
likely reservoir thickness of 1,500 metres, with lower and upper limits of 1,000 metres and 2,400 metres,
assuming that the base of the accessible resource is at 2,500 metres (2,000 – 3,000 metres).
Multiplying the area and thickness gives a most likely reservoir volume of 34.5 cubic kilometres, with
lower and upper values of 20.0 and 49.4 cubic kilometres. This is an inferred resource volume, meaning
that this volume of rock almost certainly contains hot fluids.
Heat Capacity, Density and Porosity
The heat capacity of the reservoir rocks is estimated by multiplying the specific heat capacity by the
specific gravity (density). The specific heat capacity was taken to be 0.9 kilojoules per kilogram per °C,
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which is considered a typical value for the sorts of reservoir lithologies encountered in the exploration
well.
The average particle density of reservoir rocks was taken to be 2,700 kilograms per cubic metre, which is
typical for the range of lithologies encountered in the well.
The average porosity was assumed to be 8%, with lower and upper values of 5% and 12%, based on a
mixture of andesitic volcanics, pyroclastics, epiclastics and possibly some intrusives at depths of 1,000 to
3,000 metres. Many geothermal fields have higher porosities than this, but that is generally where there is
abundant pumiceous material, whereas very little pumiceous material was reported from MP-01 and only
a limited amount within the older volcanics exposed on the surface.
Liquid Saturation
There is good evidence that there is a vapour dominated zone or a two-phase zone at the top of the
geothermal reservoir, based on the presence of fumaroles, the fumarole gas geochemistry and the absence
of hot springs. The absence of any hot springs, even in valleys that are incised below the elevation of the
top of the reservoir, suggests that the water level is below 1,700 metres above sea level, meaning that the
vapour dominated zone is at least 100 metres thick. Therefore the liquid saturation (by volume) could
range between about 50 and 100% in different parts of the reservoir, but the average is likely to be close
to 100%, even if there is a steam zone present at the top of the reservoir. The value used for liquid
saturation makes little difference to the stored heat assessment (dry steam rather than water means a slight
reduction in the stored heat estimate), and so a value of 100% was assumed for the Mariposa Report.
Resource Temperature
The average reservoir temperature was assumed to be 240°C (with upper and lower estimates of 230°C
and 250°C). These are estimated average temperatures for the entire reservoir volume (laterally and
vertically), based on geothermometry, alteration mineralogy, measured temperatures in the exploration
well, and including cooler marginal and upper parts of the reservoir, as well as deeper, hotter material.
There is a degree of inference in the estimation of this parameter, which is one reason why the resource is
in the inferred category rather than a higher category.
Cut-Off Temperature
The cut-off grade for the resource volume is temperature dependant. A cut-off temperature of 165°C is
proposed.
This is based on the minimum temperature at which wells will sustain a self-flowing two phase discharge
(180°C), which is also about the minimum temperature at which a dry steam resource would provide
steam at sufficient pressure to effectively operate a condensing steam turbine. It is assumed that the
separated water which is reinjected at 150°C will mine some heat in the process of returning from the
reinjection wells to the production wells, so a suitable figure for defining the lower temperature limit of
the resource is taken to be half way between those values.
The average ambient temperature at an elevation of 2,500 metres in the Mariposa Property is about 0°C.
The development plan comprises a standard condensing steam turbine with evaporative cooling towers.
With this type of plant, it is appropriate to assume a fluid rejection temperature of 40°C, which is
assumed to be the same as the reinjection temperature of condensate at the reservoir. A base temperature
of 40°C has therefore been adopted.
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Stored Heat Estimate
Using the above parameters, including upper, lower, and most likely values for each, models were run
2,000 times to obtain frequency distribution and cumulative probability distributions.
Recoverable and Converted Energy
At this stage there is no sound basis for accurately predicting the percentage of the stored energy which
may be recovered. Nor, given the fact that the inferred reservoir temperature has not been measured, is
there a good basis for determining the net conversion efficiency.
Nevertheless, it is instructive to consider what the inferred resource estimate could imply should certain
assumptions apply. The following is purely a hypothetical case, by analogy with other similar developed
geothermal resources.
Conversion Efficiency
The conversion efficiency depends on the reservoir temperature, climatic conditions (including the
ambient temperature, humidity and wind speed), and the specific design of the power plant and facilities.
The development plan has considered a condensing steam turbine, in which case the conversion
efficiency will probably lie between 10 and 12% (depending on the actual turbine inlet pressure adopted),
with a most likely value of 11%. This is net of parasitic power losses within the plant, which are likely to
be small in this case, since the planned steamfield configuration means that pumping is unlikely to be
required, with reinjection wells to be located several hundred metres lower in elevation than the power
plant and separators.
Recovery Factor
There are large uncertainties as to what recovery factor should be applied to heat in place, as this depends
on many factors, including the porosity and fracture spacing. In most cases, the recovery factor will be
less than the 25% that was commonly applied in the past to natural geothermal systems. A most likely
value of 16.5% was selected, being intermediate between the lower and upper values of 8% and 25%.
Capacity Factor
This was assigned a value of 0.9, based on a comparison with similar types of power plants operating in
similar remote locations.
Converted Energy
If the inferred resource is as stated, and the parameters set out above apply, then using a capacity factor of
0.9, the mean electrical generation capacity in this hypothetical case is 320 MW electrical for 30 years.
Limitations
A stored heat assessment is an educated estimate of the amount of accessible energy that is stored within a
geothermal system and how much electricity that could be converted into, making various assumptions.
The method has been demonstrated to have validity by applying it to developed geothermal systems with
a known production history. Some parameters have been empirically calibrated, and some account has
been taken of what is likely to be economic.
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The stored heat assessment by itself does not mean that there is a 50% probability that a 50 MW electrical
development will be economic, nor even that there is a 50% probability that sufficient fluid for a 50 MW
electrical development can be extracted for 30 years. It takes no account of the following factors which
could down-rate the available steam:

Permeability

Individual well productivities

Drilling difficulties

Chemical constraints on the geothermal fluid such as scaling or acidity

Gas content

Surface access constraints

Long term reservoir behaviour in terms of rapid reinjection returns or incursion of cool
groundwater

Environmental issues
On the other hand, it also does not allow for any hot recharge to the geothermal system. That can make a
substantial contribution to some liquid-dominated systems.
Early-Stage Exploration Properties
Argentina
Background
Argentina shares a common geologic ancestry with other Andean nations. These nations share the Andes
Mountains that form the backbone of the continent. Coincident with the mountains are numerous
volcanoes that make up the Andean magmatic arc. These volcanoes have a high potential for very high
temperature aquifers and it is within this region in northwestern Argentina that the Company has acquired
six concessions grouped into two areas – Coranzuli and Tuzgle-Tocomar. Within these regions, many
thermal springs are associated with the young volcanic features and areas of extensive alteration,
fumaroles, and hot springs (with surface temperatures reported as high as 80°C). These features attest to
the presence of geothermal systems.
In Argentina, geothermal resources are administered under the Mining Code, where they are included as
“endogenous vapours”, within the first category of metals and minerals (in general hydrothermal water
and base and precious metals). The ownership of these resources is primarily a provincial matter and the
provinces administer concession applications from the private sector. There are two types of concessions:
1.
Cateo (Exploration concessions). These have a minimum size of 500 hectares and a maximum of
10,000 hectares. The cateos are valid for the full size applied for, for a maximum period of
1,100 days (in the case of cateos of 10,000 hectares). After this time period, reductions in the
areas are required as follows: (i) after 300 days of the initial granting of the permit for the
concession, the company must release half of the area exceeding four units (2000 hectares); and
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(ii) after 700 days of the initial granting, the company must release half of the area remaining
after the first release.
2.
Mina (Exploitation concessions): Minas are created from either exploration concessions or by
direct discovery. Minas can be applied for preferentially by a cateo holder. Surface rights
covered by a mina are maintained by annual payments of AR$800 per each 100 hectare unit. To
cause a minas to become a permanent claim requires a minimum investment of 300 times the
annual fee, approximately AR$330 per hectare, over a period of five years.
Under the Mining Code, the sale of products (geothermal water) gathered from the concession is taxable.
There is a provincial royalty of one to three percent of the value of energy that may be extracted from
production drill holes. Different taxes may also be applied for production, transport and distribution at
national and provincial levels, though special tax regimes are being discussed to encourage development
of non-traditional energy sources.
In 1990, Argentina passed legislation removing the government from direct operation in the electricity
industry and introducing basic principles of competition. A legal framework was introduced two years
later under which private development and operation of power generation facilities was permitted and
transmission and distribution became regulated private monopolies. Argentina’s electricity market is
currently characterized by numerous producers in a highly competitive generation market in which
electricity supply is sourced from independent power producers, federal generators, binational utilities,
and foreign sources.
Tuzgle-Tocomar Property
The Tuzgle-Tocomar Property is made up of two cateos that are in the process of being constituted in
Salta Province, denominated Tocomar 1 & II (Salta Files 19.154 and 19.155), which are centered
40 kilometres west-northwest from San Antonio de los Cobres, the largest town in the area
(1,200 inhabitants), and 135 kilometres northwest from Salta City (300,000 inhabitants). These
concessions are 6,752 and 5,382 hectares in size respectively. Just to the east is the Concession Volcan
Tuzgle, (Jujuy File 914) within the southern boundary of Jujuy province, which is constituted as a Mina –
with several irregular tracts totalling 746 hectares. The acquisition cost was $5,600 for Tocomar I, $4,000
for Tocomar II and $2,800 for Volcan Tuzgle.
Previous preliminary regional geothermal assessments were carried out in the area of the Tuzgle-Tocomar
Property in the late 1970’s and early to middle 1980’s. Results of these assessments suggest that
northwest trending structures control hot springs in the area of the Tocomar Property and a borate rich
spring is controlled by north-south structures located east from the concessions. During the Pleistocene,
volcanic activity at the Tuzgle-Tocomar Property was structurally controlled. The first eruptions were
large volume pyroclastic flows (ignimbrites) of rhyodacite composition, which were later topped by
andesitic lava flows. Tuzgle volcano itself ranges in age from 500,000 to 100,000 years, but late stage
basaltic eruptions are dated as early Holocene. It has sulphur deposits, and two sets of hot springs to the
west and south. The Tuzgle-Tocomar Property area includes hydrothermal alteration centres associated
with Miocene dacitic lava flows.
A 500 kV line linking Argentina runs through the northern part of Tocomar I. Road access is by all
weather gravel road from San Antonio de los Cobres. Most of the access route from Salta to San Antonio
de los Cobres is paved.
The Company has no near term plans to proceed with exploration at the Tuzgle-Tocomar Property.
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Coranzuli Property
The Coranzuli Property project is made up of three adjoining cateos that are in the process of being
constituted (Files 911, 912, 913-R-2008) named Coranzuli I, II and III covering areas of 10,000, 9,053,
and 7,124 hectares respectively. Both Coranzuli I and II had an initial cost of $8,000. The cost of
Coranzuli III was $4,800. The three cateos lie 2 to 20 kilometres north of Coranzuli village
(200 inhabitants) the largest town in the area, 80 kilometres from Abra Pampa town (5,000 inhabitants)
and 170 kilometres northwest of Jujuy (150,000 inhabitants), the provincial capital city. The area is 30 to
40 kilometres south of the Pirquitas mine which is starting production in 2009.
The Coranzuli Property lies approximately 130 to 140 kilometres north of the Tuzgle-Tocomar Property.
The volcanic system at Coranzuli was the focus of a short review by Aquater S.p.A. in 1979.
Aquater S.p.A. decided to cease further studies due to both: (i) the apparent Miocene age of the volcanic
system (considered old for geothermal prospects) and (ii) the relatively low temperatures of the observed
hot springs (34°C). However, the area is considered of interest based on an attractive structural
framework (similar to the Tuzgle-Tocomar Property), one known thermal spring, sulphur dioxide (“SO2”)
vapour, and the presence of borate springs.
No transmission lines run through the property though a new gas pipeline transects it. Access to the area
is by paved and gravel road. The proximity of the new Pirquitas mine, a major energy user, may provide
development potential.
Fewer studies have been carried out in the area of the Coranzuli Property than at the Tuzgle-Tocomar
Property. This will necessitate more preliminary work than planned for the Tuzgle-Tocomar Property.
The Company has no near term plans to proceed with exploration at the Coranzuli Property.
Peru
Background
Instituto Geológico Minero Y Metalúrgico (“INGEMMET”, the geological survey of Peru), a department
of the Peruvian Ministry of Energy and Mines (“MEM”) undertook a series of studies of thermal and
mineral waters across Peru in the late 1990’s and early 2000’s. Over 500 springs have been characterized
by water chemistry, geology and the potential source of thermal waters. Some work on reservoir
temperatures has also been carried out.
There are three tectonic settings associated with thermal springs in Peru. These are deep, recent faulting
associated with uplift (and extension) of the Andes, active volcanism in the southern Andes, and basins
filled with sediments (sedimentary basins). Of these three settings, the area of active volcanism has high
potential for very high temperature geothermal resources. In this region of active volcanism in the
Southern Andes there are many springs associated with young volcanism and areas of extensive
alteration. Hotsprings with surface temperatures reported as high as 89°C are found. Our five Peruvian
concessions are located in this region.
Recent years have seen a dramatic shift in Peru’s electricity generation sector. Traditionally the country
has met the majority of its electricity needs through hydroelectric installations. By the mid-1990’s, the
country realized that natural gas was a feasible alternative to hydroelectric projects and from that time to
recent years has placed greater emphasis on the development of thermal generation facilities.
By 2006, hydroelectric production was 69% of Peru’s total electricity production and gas-fired thermal
electricity production had climbed to 31%. At the same time, there has been a push to increase the
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transmission capacity of the country and as of 2006 installed capacity for transmission lines reached 84%
of the country. The government is aggressively working on increasing its distribution capacity by
granting concessions for construction and administration of transmission lines. Recent growth in the
mining sector has helped the government with increased revenues and a stronger legal and regulatory
framework to support a large economic base for the country, where power availability is not a limiting
factor.
Peru allows for private development and operation of power generation facilities pursuant to a law
enacted in 1992. Currently, the private sector, including foreign companies, controls approximately 65%
of the generating capacity and 72% of the distribution system in Peru. The distribution system in Peru is
market-based and in 2006 the government took steps to, among other things, reduce administrative
intervention in determining prices for generation, encouraging market solutions.
Since 2006, due to increased awareness of global climate change and the impact of gas-fired thermal
electricity generation on the environment, Peru has begun to promote the generation of electricity through
other non-traditional renewable energy generation processes (wind, solar, geothermal, etc.), culminating
in the approval of Decree 1058 (June 27, 2008). This decree aims at promoting the generation of
electricity through non-traditional renewable processes by providing significant tax incentives. This new
law, along with other new legislation, provides a favourable government, legal and regulatory framework
for geothermal exploration (and ultimate power production) in Peru.
Geothermal exploration authorizations are granted for a three year term under Geothermal Resources Law
No. 26848 and Supreme Decree No. 072-2006-EM. The authorizations are extendable for an additional
two years. Fees are paid on an annual basis, based on the size of the exploration area and a fixed Unidad
Impositiva Tributaria rate. Once exploration is completed and a resource has been identified, a
concession for a fixed term of 30 years can be applied for.
We have applied for seven concessions in Peru totalling 7,900 hectares. While our geothermal lease
concession applications are being processed by MEM, our land position in these areas has been secured
through mineral claims.
Several concession areas lie within or near the Peruvian southern cordilleran volcanic zone in the
provinces of Arequipa, Moquegua and Tacna. This is a zone of Quaternary to Recent volcanoes that
form a broad belt trending parallel to the mountain trend along the western margin of the Altiplano. The
region gradually rises from coastal plains to around 1,000 metres above sea level, then rises more
precipitously to the Altiplano at an elevation of 4,200 to 4,600 metres above sea level. The volcanoes
break the western margin of the Altiplano, rising above the surrounding topography from 700 to
1,000 metres above sea level to elevations of over 5,000 metres above sea level, and in some cases to over
6,000 metres above sea level.
Jurassic sedimentary rocks and mixed sedimentary and volcanic rocks of Cretaceous age form the
basement to a thick succession of Tertiary to Recent deposits dominated by volcanic rocks that are capped
by glacial, colluvial, fluvial and lacustrine deposits. The volcanic rocks range from felsic, high silica
lavas and pyroclastics (dacites and rhyolites) to mafic, fluid lava flows of basaltic compositions. The
volcanoes themselves include long lived stratovolcanoes, domes, shield volcanoes and small cinder cones.
The concessions are all at the basic exploration stage, so our proposed exploration program on each of the
concessions will be carried out in a series of phases. Basic exploration, and water chemistry, will form
the initial exploration phase. This will include detailed geologic mapping, assessment of the spring and
stream chemistry as well as hydrology. Isotopic analysis will be carried out to determine the likely source
(magmatic and/or meteoric) of the water.
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Upon favourable results being obtained from work conducted in the initial phase, the next phase of our
proposed exploration program calls for geophysical work to define the geothermal resource through the
use of techniques such as MTs.
Casiri Property
The Casiri Property is a 900 hectare pending geothermal concession. The Casiri Property and the two
associated mineral concessions (total 1,100 hectares) are located in the Province of Tacna 90 kilometres
north-northeast of the city of Tacna, along the Rio Kalla Puma. The nearest town is Pampa Collota with
an estimated population of around 550. Agriculture is the main economic base of the area.
The Casiri Property includes 11 springs that debouch into an area known as “bofadales” or “high
elevation wetland”. The geology is mapped as glacial and the stream that drains through the concession is
controlled by marginal moraines. It drains a cirque like area that has been intruded by a post glacial lava
dome, volcán Purupurine. Two sulphur mines exist on the northwest and southeast flanks. The
15 springs known to exist in this area range in temperature from 26.9°C to 83.4°C and a siliceous sinter
cap is reported. With the exception of one low temperature spring (30.9°C with a measured pH of 6.5),
all the springs have a reported pH of 7.0. They are reported as chloride-sodic. No development of the
springs is reported.
A transmission line in the 33 kV to 50 kV class lies 18 kilometres to the south and thermal generating
plant 20 kilometres to the north. There are several roads cutting through the area, one of which goes from
Tacna, through Tarata and continues northward to connect with the paved highway to Zepita on
Lago Titicaca.
Ccollo Property
The Ccollo Property is a 600 hectare pending geothermal concession. The Ccollo Property, and its
associated 600 hectare mineral concession, is in the eastern part of Moquegua province close to the main
highway between Puno (85 kilometres to the northeast) and Moquegua (100 kilometres to the east
southeast). The closest town is Hospicio. The estimated population of the area is about 3,500.
The Ccollo Property hosts the only set of springs that lies north of the volcanic belt. It is about
40 kilometres north northeast of volcán Tiscani, where the geography is less extreme. The area is mapped
as mixed Tertiary continental and sedimentary units (Puno Group). The area of the springs is argillically
altered, silicified and has sulphur deposits. The springs range in temperature from 79°C to 81°C, pH is
6.8 and they are referred to as chloride-sulphide. There is hydrogen sulphide (“H2S”) reportedly present.
No reservoir temperatures have been calculated by INGEMMET.
The Ccollo Property is less than two kilometres from a 138 kV to 220 kV class high voltage transmission
line and the main highway between Moquegua and Puno.
Crucero Property
Crucero is a 20,000 hectare, authorization pending, geothermal exploration area. The Crucero area and its
two associated mineral concessions (1700 hectares total) is located in the jurisdiction of two provinces:
Mariscal Nieto (Department of Moquegua), and El Collao (Department of Puno), 40 kilometres west of
the town of Mazo Cruz (1600 inhabitants). Livestock and mining are the main economic bases of the
area.
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A transmission line in the 220 kV class lies 35 kilometres to the northwest. There are several roads
cutting through the area, the main one is paved and connects the towns like Moquegua and Candarave
with Desaguadero at the border with Bolivia. Much of the area consists of gentle topography upon which
access roads and geothermal facilities could easily be built.
The Crucero geothermal area was initially identified during a detailed review of Peruvian INGEMMET
geothermal bulletins. One of the objectives of the review was to identify favorable geothermal prospects
outside of well-documented young volcanic centers. The challenge involved distinguishing electricitygrade prospects from several hundred widely distributed hot spring occurrences in Peru.
Outside of known young stratovolcanoes, Crucero is the most attractive target identified during this
review. It was selected on the basis of high silica concentrations measured in surficial spring deposits, as
described in a geochemical table in INGEMMET Bulletin 24, Series D. Almost all of these spring
deposits from other localities in Peru are composed principally of calcium carbonate travertine, but the
high silica concentrations from Crucero suggested that these spring deposits were actually composed of
silica sinter.
Three field visits by Magma geologists have confirmed the presence of silica sinter terraces at four
localities at Crucero spread over a distance of nearly four kilometres. At several places, fissure-controlled
silica terraces project beneath thick marsh grasses and young alluvium. Local ranchers/herders report that
river waters draining the marshes are salty, consistent with the presence of additional concealed “hot
springs” and “sinter” terraces beneath the marshes. Hot springs at the sinter terraces have temperatures
ranging up to 66°C. It is likely that temperatures of thermal waters in the shallow subsurface are greater
than 66°C because mixing with shallow cold ground waters appears to have affected some spring waters
(as evidenced by Mg concentrations) and flow rates of some springs is low enough to permit significant
conductive cooling during the approach of thermal waters to the surface.
Analytical results from five hot spring water geochemical samples taken this summer (2010) have just
been received and are under review. In addition, the structural environment of Crucero is currently under
investigation, and a structural analysis is one of the priorities of upcoming field investigations.
Huaynaputina Property
In the Province of Moquegua, this 800 hectare pending geothermal concession (and its associated
800 hectare mineral concession) is situated almost half-way between the cities of Arequipa and
Moquegua, 60 kilometres east south-east of Arequipa. The closest town is Ulucan with an estimated
population of around 500. Agriculture is the principal economic basis of the region. The Huaynaputina
Property straddles the valley of the Rio Aguada Buena.
The Huaynaputina Property covers a series of five springs emanating from alluvially covered Yura Group
rocks. This group of rocks is Jurassic in age and contains clastic sediments. The closest volcano,
Huaynaputina (whose name means “new volcano”) is 16 kilometres to the east. Of the five springs
covered by the concession, four are over 70°C and the remaining one 55°C. The pH levels vary from 5.8
to 6.8 and they are all classified as chloride-sodic and have carbonate sinter. Reservoir temperatures were
calculated by INGEMMET at between 170°C to 180°C. The close proximity of several volcanoes makes
this a very likely target for a high temperature vapour dominated reservoir, or at the least a very high
temperature liquid one. Clastic rocks of the Yura Group are the most likely reservoir target. The strong
linears and deformation of the sedimentary rocks suggest fracture porosity and permeability.
A 138 kV to 220 kV class high voltage transmission line lies 30 kilometres to the south-east. There are
sub-stations in Omate eight kilometres to the south-east and in Puquina, 13 kilometres west associated
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with a regional line that passes through the middle of the area. Road access is to the west along the Las
Salinas River from Arequipa.
Sabancaya Property
This 900 hectare pending geothermal concession has two associated mineral concessions (total
1,600 hectares). They are located in the Province of Arequipa, 90 kilometres north of the capital of
Arequipa. There are several small towns close to the concession, the largest one is Chivay,
two kilometres from the concession. The estimated population in the vicinity is about 500 and the main
economic activity in the area is agriculture. The property is located in the broad valley of the Rio Colca.
The area of the Sabancaya Property is structurally deformed and faulted, and lies close to Sabancaya
volcano. The springs around which this concession is located consists of five springs in close proximity.
The springs issue from a sequence of tertiary volcanic rocks associated with a fault. The temperatures of
the springs range from 45°C to 80°C and are described as bicarbonate-sulfate-sodic. The pH levels range
from 6.4 to 7.4. No reservoir temperature has been calculated for the springs. The Sabancaya volcano is
a young volcanic centre (25 kilometres from the Sabancaya Property), that has erupted in historical time.
Proximity to these young volcanic centres suggests magmatic heating may be a contributing factor to the
reservoir temperature.
A major high voltage line runs 20 kilometres to the east and there is a substation just to the south of the
town of Callalli, 28 kilometres from the concession. There is also a local electrical grid that runs through
the concession. Road access appears good via the road from the coast from Camana or from the main
route heading to Lago Titicaca from Arequipa.
San Pedro Property
San Pedro is an approximately 20,000 hectare, authorization pending, geothermal exploration area. The
San Pedro area and its associated mineral concession (800 hectares) is located in the Province of
Candarave, Department of Tacna 100 kilometres north of the city of Tacna, and 15 kilometres north of the
town of Candarave (3200 inhabitants). Agriculture, livestock, and mining are the main economic bases in
the area.
The hydro electrical dam of Aricota I is located 30 kilometres south. Two lines: 33 kV to 66 kV class
and 138 kV class are derived from Aricota I. Another 220 kV class lies 50 kilometres to the northwest.
The San Pedro area covers a 16 kilometre-long north-northwest-trending structural corridor on the
northern flanks of the active volcano Cerro Yucamane. Geothermal features along this structural zone
include fumarolic deposits of native sulfur and thermal acid springs proximal to the volcano; mud pots
and steam vents on the middle slopes, and distal boiling springs with silica sinter at lower elevations.
Young fault scarps and an alignment of young volcanic summits within the structural zone suggest that
the surface thermal features lie along an interconnected zone of faults and permeable volcanic rocks at
depth with likely access to magmatic heat. Chemical analyses of the boiling springs yields
geothermometer estimates of reservoir temperatures ranging from 165°C to well over 200°C.
Satellite thermal infrared image analysis led to the initial identification of this property because the
thermal features are not currently accessible by vehicle. Much of the area, however, consists of gentle
topography upon which access roads and geothermal facilities can easily be built. An excellent graded
and well-maintained road lies six kilometres to the west, and a paved national highway lays a further 1520 kilometres to the northwest. In the opposite direction, the graded road connects to the town of
Candarave 25 kilometres to the south.
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Tiscani Property
This 1,000 hectare geothermal concession (and its two associated mineral concessions with a total of
1,500 hectares) are near the town of Putina along the river of the same name in the province of Moquegua
approximately 30 kilometres northeast of the city of the same name. The nearest town is Putina with a
population of about 500 people. Agriculture is the economic base of the area. The Tiscani Property is in
the upper parts of the Rio Corumas.
The Tiscani Property is in the Peruvian Southern Cordilleran Volcanic Zone less than ten kilometres to
the northwest of Volcán Tiscani. Volcán Huaynaputina is 20 kilometres to the northwest, putting this
group of springs in the heart of the volcanic belt. The suite of springs around which this concession is
located consists of 12 springs strung out along the Rio Corumas, a tributary of the Rio Tambo. The
springs themselves are emanating from a fault that places Tertiary against Cretaceous rocks. Springs
range in temperature from 54°C to 89°C and have an indicated reservoir temperature of 170°C to 180°C.
The pH levels range from 5.8 to 8.3 and the springs are described as chloride-sodic and have carbonate
sinter. H2S is reported from two of the springs. There is no known development of the springs.
A 138 kV to 220 kV class high voltage transmission line passes within 13 kilometres of the concession.
Road access is from the coast via Ilo through Moquegua along the paved road that goes to Puno on Lago
Titicaca. The Tiscani Property is roughly 20 kilometres (in a straight line) for this road.
DIVIDENDS
Magma has not declared or paid any dividends since incorporation. Presently, our anticipated capital
requirements are such that we intend to follow a policy of retaining earnings in order to finance further
business development. The declaration of dividends on our common shares is within the discretion of our
Board of Directors and will depend upon their assessment of our earnings, capital requirements, operating
and financial condition and other factors it considers to be appropriate. There are no restrictions on our
ability to pay dividends.
DESCRIPTION OF CAPITAL STRUCTURE
The Company is authorized to issue an unlimited number of common shares without nominal or par
value. The holders of common shares shall be entitled to receive dividends, as and when declared by the
Board of Directors out of monies properly applicable to the payment of dividends, in such amount and in
such form as the Board of Directors may from time to time determine and all dividends which the Board
of Directors may declare on the common shares shall be declared and paid in equal amounts per share on
all common shares at the time outstanding. In the event of the dissolution, liquidation or winding up of
the Company, whether voluntary or involuntary, or any other distribution of assets of the Company
among its shareholders for the purpose of winding up its affairs, the holders of the common shares shall
be entitled to receive the remaining property and assets of the Company. The holders of common shares
shall be entitled to receive notice of and attend all meetings of the shareholders of the Company and shall
have one vote for each common share held at all meetings of the shareholders of the Company.
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MARKET FOR SECURITIES
The common shares commenced trading on the TSX on July 7, 2009 under the trading symbol “MXY”.
The following table sets forth the price ranges and volume of trading of the common shares on the TSX
for each month since the Company commenced trading:
Month Ended
Volume
High
Low
Close
July, 2009
22,939,141
1.95
1.41
1.90
August, 2009
7,098,284
2.10
1.75
1.90
September, 2009
5,840,958
2.02
1.83
1.91
October, 2009
6,172,016
1.94
1.77
1.82
November, 2009
8,019,122
2.06
1.71
2.00
December, 2009
4,593,246
1.96
1.69
1.81
January, 2010
5,892,674
1.91
1.64
1.65
February, 2010
4,668,644
1.75
1.51
1.55
March, 2010
8,950,021
1.67
1.40
1.42
April, 2010
6,061,724
1.56
1.38
1.47
May, 2010
4,016,129
1.51
1.31
1.32
June, 2010
5,110,451
1.47
1.24
1.33
ESCROWED SECURITIES
The following is a summary of the common shares held, to our knowledge, in escrow or that are subject
to contractual restriction on transfer as at September 17, 2010, and the percentage of Magma’s
outstanding common shares represented by such escrowed or restricted securities. Magma is classified as
an “exempt issuer” for the purposes of National Policy 46-201 – Escrow for Initial Public Offerings.
Designation of Class
Number of common shares
held in escrow or that are
subject to contractual
restrictions on transfer
Percentage of
Outstanding
common shares
ROSS J. BEATY
Common shares
100,000,001
34.6%
OTHER INITIAL INVESTORS
Common shares
5,250,000
1.8%
OTHER RESTRICTED
SHAREHOLDERS
Common shares
6,072,967
2.1 %
Name or Category of Shareholder
Pursuant to a lock-up agreement entered into among Magma, Raymond James Ltd., Cormark Securities
Inc. and Ross J. Beaty, Mr. Beaty is prohibited from selling 100,000,001 common shares currently held
by him for a period of four years from July 7, 2009. However, Mr. Beaty may assign all or a portion of
such common shares to a non-profit foundation “The Sitka Foundation”; provided “The Sitka
Foundation” in turn agrees to be bound by such prohibition.
Pursuant to lock-up agreements entered into among Magma, Raymond James Ltd., Cormark Securities
Inc. and 15 of our initial investors (the “Other Initial Investors”) who purchased an aggregate of
10,500,000 common shares in April 2008 at a price of Cdn$0.001 per common share (the “Initially
Offered Common Shares”), which includes all of our directors and employees, with the exception of
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Mr. Beaty (as described above), who purchased Initially Offered Common Shares, such Initially Offered
Common Shares are subject to contractual restrictions on transfer. Subject to any additional statutory or
stock exchange imposed hold periods, the Other Initial Investors are prohibited from selling in excess of
one-quarter of such Initially Offered Common Shares held by them in each of the six month periods
beginning six, 12, 18 and 24 months after July 7, 2009, without the prior written consent of Raymond
James Ltd. and Cormark Securities Inc.
Pursuant to lock-up agreements entered into among Magma, Raymond James Ltd., Cormark Securities
Inc. and 110 of our shareholders (the “Other Restricted Shareholders”) who purchased common shares
in June 2008 at a price of Cdn.$0.60 per common share (the “Other Restricted Common Shares”),
subject to any additional statutory or stock exchange imposed hold periods, such Other Restricted
Shareholders are prohibited from selling in excess of 33% of such Other Restricted Common Shares held
by them in each of the six month periods beginning six, 12 and 18 months after July 7, 2009, without the
prior written consent of Raymond James Ltd. and Cormark Securities Inc.
If, after one year from July 7, 2009, the closing market price of the common shares on a stock exchange is
a price that is equal to or greater than three times Cdn.$1.50 for a period of 20 consecutive trading days,
the lock-up agreements with the Other Initial Investors and Other Restricted Shareholders will terminate.
The restrictions on the sale of common shares by Mr. Beaty, however, will not be affected.
DIRECTORS AND OFFICERS
The names and municipalities of residence of our directors and management team, the positions held by
them with us and their principal occupations for the past five years are as set forth below. The term of
office of the directors expires annually at the time of our annual general meeting. The term of office of
each officer expires at the discretion of our Board of Directors.
Name and Municipality
of Residence
Current Office
with the Company
Principal Occupation Since 2005
Directors
ROSS J. BEATY
British Columbia, Canada
Chairman and Chief Executive
Officer
(since January 22, 2008)
Chairman and Chief Executive Officer of
Magma (since January 22, 2008); Chairman
of Pan American Silver Corp. (“Pan
American”) (since 1994)
DAVID W. CORNHILL
Alberta, Canada
Director
(since December 1, 2008)
Chairman and Chief Executive Officer of
AltaGas Income Trust (since 1994)
ROBERT PIROOZ
Director
General Counsel of Pan American (since
January 2003); former Secretary of Pan
American (from January 2003 to February
2010); former Vice-President of companies
in the Lumina Copper Group (from 2003 to
2008)
DONALD SHUMKA
Director
President of Walden Management Ltd. (since
2004);
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of Residence
PAUL B. SWEENEY
Current Office
with the Company
Director
(since September 11, 2008)
Executive Officer of Plutonic Power
Corporation (“Plutonic”) (since April 2010);
former President of Plutonic (from August
2009 to April 2010); former Executive VicePresident Business Development of Plutonic
(from January 2007 to August 2009);
financial consultant (from 2005 to January
2007); former Vice-President and Chief
Financial Officer of Canico Resource Corp.
(“Canico”) (from 2002 to 2005)
ANNETTE CUSWORTH
Chief Financial Officer
Chief Financial Officer of Magma (since
June 10, 2010); former Vice-President and
Chief Accounting Officer of CHC Helicopter
Corporation (from 2008 to 2009); former
Vice-President, Financial Services of CHC
Helicopter Corporation (from 2006 to 2008);
held senior finance positions with CHC
Helicopter Corporation (from 2004 to 2006)
ANDREA M. ZARADIC
Vice-President, Operations and Vice-President, Operations and Development
Development
of Magma (since October 27, 2008); former
Senior Project Manager for Kobex
Resources Ltd. (from 2007 to 2008); former
Engineering Manager for Novagold
Resources Inc. (from 2006 to 2007); former
Engineering Infrastructure Manager for
Canico (from 2004 to 2005)
ALISON THOMPSON
Vice-President, Corporate
Relations
Vice-President, Corporate Relations of
Magma (since September 8, 2009); former
Geothermal Assessment Team Manager for
Nexen, Inc (from 2008 to 2009); former
Technology Transfer Manager for Nexen,
Inc (from 2007 to 2008); former Technology
Strategy Manager for Suncor Energy (from
2004 to 2007)
DR. CATHERINE HICKSON
Vice-President, Exploration
and Chief Geologist
Vice-President, Exploration and Chief
Geologist of Magma (since October 4,
2008); former senior Research Scientist,
Natural Resources Canada (Geological
Survey of Canada), Subdivision head (GSC
Vancouver) and Program manager
MONTE MORRISON
Nevada, U.S.A
United States Country Manager US Country Manager and Vice-President,
and Vice-President, Operations Operations of Magma (since June 2, 2010);
former Vice-President Operations (Soda
Lake) (from December 2008 to June 2010);
former Director of Operations, Renewable
Assets at Constellation Energy Corp (from
2003 to 2008)
Executive Officers
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of Residence
LYLE BRAATEN
Current Office
with the Company
Secretary and General Counsel
Secretary and General Counsel of Magma
(since June 1, 2008); former Managing
Partner of Whitelaw Twining Law
Corporation (from 2001 to 2008)
As of September 17, 2010, the directors and executive officers of the Company, as a group, beneficially
own directly or indirectly, or exercise control or direction over 125,903,542 common shares representing
approximately 43.6% of the Company’s issued and outstanding common shares.
Committees of the Board of Directors
Our Board of Directors has established three board committees: an Audit Committee, a Compensation
Committee and a Governance and Nominating Committee. The information below summarizes the
functions of each of the committees in accordance with their charters.
Audit Committee
Audit Committee Charter
Attached as Appendix “A” is the charter for the Company’s Audit Committee.
Composition of the Audit Committee
The Audit Committee is comprised of Donald Shumka (Chair), Paul B. Sweeney and Robert Pirooz, each
of whom is independent and financially literate.
Relevant Education and Experience of the Members of the Audit Committee
Donald Shumka
Mr. Shumka was born in Vernon, British Columbia, Canada in 1942, and he currently resides in
Vancouver, British Columbia, Canada. He graduated from the University of British Columbia in 1964
with a B.A. and in 1966 he graduated with an MBA from Harvard University.
From 1976 to 1979, Mr. Shumka worked in a variety of positions in the forest industry. During the
period between 1979 and 1989, Mr. Shumka was Vice-President and Chief Financial Officer of West
Fraser Timber Co. Ltd. and from 1989 to 2004 he headed the Forest Products Group for two Canadian
investment banks. Mr. Shumka was the Managing Director of Raymond James Ltd. until 2004, and he is
currently the President of Walden Management Ltd. and a director of Eldorado Gold Corporation, Paladin
Energy Ltd. and Lumina Copper Corp. Mr. Shumka is active in the not-for-profit sector and is currently
the Chair of the British Columbia Arts Council.
Paul B. Sweeney
Mr. Sweeney was born in Vancouver, British Columbia, Canada in 1949, and he currently resides in
Surrey, British Columbia, Canada. Mr. Sweeney has over 35 years experience in financial management
of mining and renewable energy companies. He is currently an Executive Officer of Plutonic, a run-ofriver hydro developer and a director of Pan American.
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Mr. Sweeney has a strong track record of success with project finance. Most recently, from 2002 to 2005
he served as Vice-President and Chief Financial Officer of Canico where he was responsible for, among
other things, arranging project financing for the Onça-Puma Nickel Project. Financing of the project was
well underway and commitments had been received when Canico was bought by way of a $940 million
takeover by Companhia Vale do Rio Doce. Prior to working at Canico, Mr. Sweeney was the VicePresident and Corporate Secretary of Manhattan Minerals Corp. from 1999 to 2002 and, from 1998 to
1999, Mr. Sweeney was the Vice-President and Chief Financial Officer for Sutton Resources Ltd. where
he had arranged the debt financing for the Bulyanhulu gold mine in Tanzania prior to the acquisition of
Sutton Resources Ltd. by Barrick Gold Corp. He is currently a director and the chairperson of the audit
committee for each of Polaris Minerals Corporation, New Gold Inc. and Pan American.
Robert Pirooz
Mr. Pirooz was born in Ahwaz, Iran in 1964. He is a Canadian citizen and currently resides in
Vancouver, British Columbia, Canada. Mr. Pirooz studied commerce at Dalhousie University and
graduated from the University of British Columbia in 1989 with a Juris Doctor. Mr. Pirooz practiced law
in Vancouver and Victoria, British Columbia from May 1990 to February 1998, primarily in the areas of
corporate, commercial and securities law. He is currently a director of Anfield Nickel Inc., Lumina
Copper Corp., Pan American and Ventana Gold Corp. Mr. Pirooz served as General Counsel, VicePresident and Secretary of Pan American from April 1998 to October 2000, as Secretary of Pan American
from January 2003 to February 2010, and as General Counsel of Pan American from January 2003 until
the present date. He was also the former Vice-President and Secretary of companies in the Lumina
Copper Group from 2003 to 2008. He has worked with Ross J. Beaty since early 1998.
Reliance on Certain Exemptions
The Company’s Audit Committee has not relied on any of the exemptions under National Instrument 52110 during the most recently completed financial year.
Audit Committee Oversight
The Board of Directors adopted all recommendations by the audit committee with respect to the
nomination and compensation of the external auditor.
Pre-Approval Policies and Procedures
The Audit Committee is responsible for overseeing the work of the external auditors and considering
whether the provision of non-audit services is consistent with the external auditor’s independence. The
Audit Committee shall approve in advance all audit and permitted non-audit services with the
independent auditors. This includes the terms of engagement and all fees payable.
External Auditor Service Fees
The aggregate fees billed by Grant Thornton LLP, the Company’s external auditors, during the fiscal year
ended June 30, 2010 for assurance and related services rendered by Grant Thornton LLP that are
reasonably related to the performance of the audit review of the Company’s financial statements for that
year were Cdn.$382,400. Assurance and related services included services rendered in connection with
the Company’s initial public offering.
The aggregate fees billed by Grant Thornton LLP during the fiscal year ended June 30, 2010 for
professional services rendered by Grant Thornton LLP for tax compliance, tax advice, tax planning and
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other services were Cdn.$104,877. Tax services provided included advice in connection with structuring
of transactions and review of tax provisions.
Fees payable by Magma for audit and other services provided by Grant Thornton LLP for the year ended
June 30, 2010 were as follows:
Year ended June 30, 2010
Year ended June 30, 2009
Audit Fees ........................................................
Cdn.$60,100
Cdn.$125,950
Audit Related Fees ...........................................
Cdn.$322,300
Cdn.$160,900
Tax-Related Fees ...........................................
Cdn.$104,877
Cdn.$58,519
Other Fees ........................................................
Nil
Total: ...............................................................
Cdn.$487,277
(1)
Nil
Cdn.$345,369
Note:
(1)
Includes fees for professional services rendered for tax compliance, tax advice, tax
planning and other related services.
Compensation Committee
Our Compensation Committee’s role is to assist the Board of Directors in fulfilling its responsibilities
relating to matters of human resources and compensation and to establish a plan of continuity and
development for senior management of Magma. Our Compensation Committee shall determine and make
recommendations with respect to all forms of compensation to be granted to our Chief Executive Officer,
and reviewing the Chief Executive Officer’s recommendations respecting compensation of our senior
executives. To fulfil the responsibilities and duties outlined in its charter, our Compensation Committee
shall review and approve corporate goals and objectives relevant to compensation, evaluate performance
of executives in light of those corporate goals and objectives and make recommendations respecting
appointment, compensation and other terms of employment. The Compensation Committee shall review
executive compensation disclosure before we publicly disclose any information regarding compensation,
and submit a report to the Board of Directors on human resources matters at least annually.
Our Compensation Committee is comprised of three independent directors. The members of the
Compensation Committee are David W. Cornhill, Robert Pirooz and Paul B. Sweeney, the latter of whom
is the chair of the Compensation Committee.
Governance and Nominating Committee
Our Governance and Nominating Committee’s charter provides that its responsibilities shall include:
(i) establishing and reviewing member characteristics and size of the Board of Directors;
(ii) recommending the remuneration of directors; (iii) monitoring conflicts of interest of both the Board of
Directors and management in accordance with our Code of Business Conduct; (iv) evaluating, identifying
and recommending nominees to the Board of Directors and to the various committees thereof;
(v) reviewing and developing corporate governance guidelines, policies and procedures for the Board of
Directors; (vi) monitoring and reviewing the education and development of members of the Board of
Directors; (vii) establishing and implementing evaluation processes for the Board of Directors, its
committees and chairs; (viii) reviewing the Board of Directors mandate and the mandates for each
committee thereof, together with a position descriptions, and ensuring that the Board of Directors and the
committees function independently of management; and (ix) receiving reports from the executive
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directors regarding breaches of the Code of Business Conduct and reporting such breaches to the Board
of Directors.
Our Governance and Nominating Committee is comprised of three independent directors. The members
of the Governance and Nominating Committee are David W. Cornhill, Donald Shumka and Robert
Pirooz, the latter of whom is the chair of the Governance and Nominating Committee.
Corporate Cease Trade Orders and Bankruptcies
Except as noted below, none of the Company’s directors or executive officers:
(a)
are, as at the date of this Annual Information Form, or have been, within ten years before
the date of this Annual Information Form, a director, chief executive officer or chief
financial officer of any company (including the Company) that,
(i)
was subject to a cease trade or similar order or an order that denied the relevant
company access to any exemption under securities legislation, for a period of
more than 30 consecutive days while such person was acting as director, chief
executive officer or chief financial officer; or
(ii)
was subject to a cease trade or similar order or an order that denied the relevant
company access to any exemption under securities legislation, for a period of
more than 30 consecutive days that was issued after the director or executive
officer ceased to be a director, chief executive officer or chief financial officer
and which resulted from an event that occurred while such person was acting in
that capacity;
(b)
are, as at the date of this Annual Information Form, or has been within ten years before
the date of this Annual Information Form, a director or executive officer of any company
(including the Company) that, while that person was acting in that capacity, or within a
year of that person ceasing to act in that capacity, became bankrupt, made a proposal
under any legislation relating to bankruptcy or insolvency or was subject to or instituted
any proceedings, arrangement or compromise with creditors or had a receiver, receiver
manager or trustee appointed to hold its assets; or
(c)
have, within the ten years before the date of this Annual Information Form, become
bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or
become subject to or instituted any proceedings, arrangement or compromise with
creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the
proposed director.
Robert Pirooz was formerly a director of Pacific Ballet British Columbia Society (the “Ballet”). On
December 23, 2008, within a year following Mr. Pirooz’s resignation from the board of directors of the
Ballet, the Ballet filed a Notice of Intention to Make a Proposal under subsection 50.4(1) of the
Bankruptcy and Insolvency Act. Subsequently, on January 9, 2009, the proposal was unanimously
accepted by the creditors of the Ballet.
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Penalties and Sanctions
To our knowledge, none of our directors or officers has:
(a)
been subject to any penalties or sanctions imposed by a court relating to Canadian
securities legislation or by a Canadian securities regulatory authority or has entered into a
settlement agreement with a Canadian securities regulatory authority; or
(b)
been subject to any other penalties or sanctions imposed by a court or regulatory body
that would likely be considered important to a reasonable investor making an investment
decision.
Conflicts of Interest
To the best of our knowledge, and other than disclosed herein, there are no known existing or potential
conflicts of interest among us and our directors, officers or other members of management as a result of
their outside business interests except that certain of our directors and officers serve as directors and
officers of other companies, and therefore it is possible that a conflict may arise between their duties to us
and their duties as a director or officer of such other companies. Conflicts of interest which arise from
time to time, if any, will be dealt with in accordance with the provisions of The Business Corporations
Act (British Columbia). In accordance with The Business Corporations Act (British Columbia), directors
who have a material interest or any person who is a party to a material control or proposed material
contract with the Company are required, subject to certain exceptions, to disclose those interests and to
generally abstain from voting on any resolution to approve the contract. In addition, the directors will be
required to act honestly and in good faith with a view to the best interests of the Company. Some of the
directors and officers of the Company have or will have either other employment or other business or
time restrictions placed on them and accordingly, these directors and officers of the Company will only be
able to devote part of their time to the affairs of the Company.
PROMOTERS
Ross J. Beaty may be considered to be, or have been within the past two years, a promoter of Magma
within the meaning of applicable securities legislation by reason of his initiative and involvement in the
formation and establishment of Magma.
As of September 17, 2010 Mr. Beaty, directly and indirectly, owns 121,579,861 common shares being
42.1% of the issued and outstanding common shares.
Other than compensation received by Mr. Beaty in his personal capacity as director, officer or employee
of Magma, the grant of incentive stock options in the ordinary course and payments made pursuant to the
terms of the 2008 Credit Agreement (defined below) and the 2010 Credit Agreement, all as disclosed
elsewhere in this Annual Information Form, nothing of value, including money, property, contracts,
options or rights of any kind will be received by the promoter directly or indirectly from the Company.
See ‘‘Interest of Management and Others in Material Transactions”.
LEGAL PROCEEDINGS
HS Orka previously entered into a conditional PPA with Nordural Helguvik sf (“Nordural”) to sell
power from HS Orka’s expansion efforts to a new aluminum smelter to be constructed and located in
Reykjanesbær. The PPA was executed on April 23, 2007 and contained a number of conditions which
were not fulfilled by the time set out in the PPA. Accordingly, HS Orka and Magma hold the view that
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the PPA has lapsed in accordance with its terms. Nordural disputes this interpretation and maintains that
the PPA is a valid agreement. The PPA provides that disputes relating to the PPA shall be resolved by
arbitration. Nordural has initiated arbitration proceedings to determine the validity of the PPA. The
arbitration proceedings were initiated on July 19, 2010 and no hearing date has been set.
While we do not view it as a legal proceeding see also the discussion respecting the appointment of a
Special Committee (as defined below) by the Icelandic government under “Risks Relating to HS Orka”
discussed below.
Except as disclosed above, we are not the subject of any material legal proceedings, nor are we or any of
our properties a party to or the subject of any such proceedings and no such proceedings are known to be
contemplated. We are involved in other routine, non-material litigation arising in the ordinary course of
our business.
RISK FACTORS
A prospective investor should carefully consider the risk factors set out below.
Risks Relating to our Business and Industry
New production wells at our Soda Lake Operation may not define sufficient additional and
commercially viable geothermal resources to support our planned expansion programs
Our expansion programs for the production of increased power from our Soda Lake Operation are not
assured of success and depend on the successful drilling and discovery of additional geothermal resources
to economically generate increased power. Substantial exploration and development work is required in
order to determine if sufficient additional economically recoverable and sustainable geothermal resources
are located on the lands and leases comprising our Soda Lake Operation to support both: our phase 1 plan
to double the existing power output from 8 to approximately 16 MW net, thus achieving the original
nameplate capacity of 23 MW; and our phase 2 plan to add additional generating and resource capacity
and increase nameplate production to realize the full potential of the Soda Lake resource. Increasing the
level of production from the Soda Lake Operation and sustaining it over the long term will require drilling
step-out wells to discover additional resource areas. The viability of the planned expansion programs at
our Soda Lake Operation will depend upon a number of factors which are beyond our control relating to
the nature of the geothermal resource defined through drilling these additional production wells, such as
heat content (the relevant composition of temperature and pressure), useful life and operational factors
relating to the extraction of fluids from the geothermal resource. If sufficient economically recoverable
and sustainable geothermal resources are not defined through drilling, our planned expansion programs at
the Soda Lake Operation may be scaled back or not proceed altogether, which would, in turn, materially
and adversely affect our business, financial condition, future results and cashflow.
Geothermal exploration and development programs are highly speculative, are characterized by
significant inherent risk and costs, and may not be successful
Our future performance depends on our ability to discover and establish economically recoverable and
sustainable geothermal resources on our properties through our exploration and development programs.
Geothermal exploration and development involves a high degree of risk and few properties that are
explored are ultimately developed into generating power plants. There is no assurance that our
exploration and development programs will be successful. Despite historical exploration work, our
properties, other than our Soda Lake Operation and the Svartsengi and Reykjanes properties owned by HS
Orka, are without a known geothermal resource. Substantial exploration and development work is
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required in order to determine if any economically recoverable and sustainable geothermal resources are
located on these exploration properties. Successfully discovering geothermal resources is dependent on a
number of factors, including the technical skill of exploration personnel involved. Even in the event
commercial quantities of geothermal resources are discovered, it may not be commercially feasible to
bring power generation facilities into a state of commercial production from such geothermal resources.
The commercial viability of a geothermal resource once discovered is dependent on a number of factors,
some of which are particular attributes of the resource, such as heat content (the relevant composition of
temperature and pressure), useful life, operational factors relating to the extraction of fluids from the
geothermal resource, proximity to infrastructure, capital costs to construct a power plant and related
infrastructure and energy prices. Many of these factors are beyond our control.
Geothermal exploration and development costs are high and are not fixed. A geothermal resource cannot
be relied upon until substantial development, including drilling, has taken place. The costs of
development drilling are subject to numerous variables such as unforeseen geologic conditions
underground that could result in substantial cost overruns. Drilling at our properties may involve
unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce
sufficient net revenues to return 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, it could materially adversely affect our business,
financial condition, future results and cashflow.
We have a limited operating history
We have a limited history of operations. We are subject to many of the risks common to start up
enterprises, including under-capitalization, cash shortages, limitations with respect to personnel, financial,
and other resources and lack of revenues. There is no assurance that we will be successful in achieving a
return on shareholders’ investment and the likelihood of success must be considered in light of our early
stage of operations.
From our inception we have incurred net losses. As a result of our planned exploration and plant
expansion projects, over the near term we do not expect that our operating revenues will be sufficient to
cover our expenses. As a result, we expect to continue to incur net losses until we are able to generate
significant revenues. Our ability to generate significant revenues and become profitable will depend on a
number of factors, including our ability to:

successfully complete our planned expansion programs to our Soda Lake Operation and HS
Orka Properties;

acquire interests in producing geothermal power companies or producing geothermal power
plants that contribute to our profitability;

acquire additional prospective exploration and development properties;

advance planned and future exploration programs on our exploration properties;

verify geothermal resources on our exploration properties that that are sufficient to generate a
favourable economic return from electricity sales;
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
acquire electrical transmission and interconnection rights for our geothermal power plant
development projects;

enter into PPA for the sale of electricity from our geothermal power plant development
projects at prices that support our operating and financing costs;

finance and complete the development and construction of geothermal power plants on
our properties;

operate producing geothermal power plants on a profitable basis;

secure adequate capital to support our expansion, exploration and development programs and
finance our acquisitions; and

attract and retain qualified personnel.
Our financial performance depends on our successful operation of geothermal power plants, which is
subject to various operational risks
Our financial performance depends on our successful operation of geothermal power plants. At present
we operate a single power plant at our Soda Lake Operation and have an interest in the Svartsengi and
Reykjanes power plants. The cost of operation and maintenance and the operating performance of a
geothermal power plant may be adversely affected by a variety of factors, including some that are
discussed elsewhere in these risk factors and the following:

regular and unexpected maintenance and replacement expenditures;

shutdowns due to the breakdown or failure of the plant’s equipment or the equipment of the
transmission serving utility;

labour disputes;

catastrophic events such as fires, explosions, earthquakes, landslides, floods, releases of
hazardous materials, severe storms or similar occurrences affecting a power plant, any of the
power purchasers from a power plant or third parties providing services to a power plant; and

the aging of power plants, which may reduce their operating performance and increase the
cost of their maintenance.
Any of these events could significantly increase the expenses incurred by a power plant or reduce the
overall generating capacity of a power plant and could significantly reduce or entirely eliminate the
revenues generated by a power plant, which in turn would reduce our net income and could materially and
adversely affect our business, financial condition, future results and cashflow.
Our geothermal resources may decline over time and may not remain adequate to support the life of
our power plants
The operation of geothermal power plants depends on the continued availability of adequate geothermal
resources. Although we believe our geothermal resources will be fully renewable if managed properly,
we cannot be certain that any geothermal resource will remain adequate for the life of a geothermal power
plant.
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Any geothermal resource may suffer an unexpected decline in capacity to generate electricity. A number
of events could cause such a decline or shorten the operational duration of a geothermal resource, which
could cause the applicable geothermal resource to become a non-renewable wasting asset. These
events include:

power generation above the amount that the applicable geothermal resource will support;

failure to recycle all of the geothermal fluids used in connection with the applicable
geothermal resource; and

failure to properly maintain the hydrological balance of the applicable geothermal resource.
If the geothermal resources available to a power plant we develop become inadequate, we may be unable
to perform under the PPA for the affected power plant, which in turn could reduce our revenues and
materially and adversely affect our business, financial condition, future results and cash flow. If we
suffer a decline in our geothermal resources, our insurance coverage may not be adequate to cover losses
sustained as a result thereof.
Uncertainty in the calculation of geothermal resources and probabilistic estimates of MW capacity
There is a degree of uncertainty attributable to the calculation of geothermal resources and probabilistic
estimates of MW capacity. Until a geothermal resource is actually accessed and tested by production
wells, the temperature and composition of underground fluids must be considered estimates only. In
addition, estimates as to the percentage of the heat that can be expected to be recovered at the surface and
the efficiency of converting that heat into electrical energy are subject to a number of assumptions
including, but not limited to, resource base temperature, areal extent of the geothermal reservoir,
thickness of the geothermal reservoir, percentage of resource recovery and the expected lifetime of the
geothermal reservoir. If any of these assumptions prove to be materially incorrect, it may affect the MW
capacity of a property.
Geological occurrences beyond our control may compromise our operations and their capacity to
generate power
In addition to the substantial risk that production wells that are 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, localized
ground subsidence, localized ground inflation, explosions, uncontrollable releases or 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.
Additionally, active geothermal areas, such as the areas in which our operations and properties are
located, are subject to frequent low-level seismic disturbances. Serious seismic disturbances are possible
and could result in damage to our projects or equipment or degrade the quality of our geothermal
resources to such an extent that we could not perform under the PPA for the affected project, which in
turn could reduce our net income and materially and adversely affect our business, financial condition,
future results and cash flow. If we suffer a serious seismic disturbance, our business interruption and
property damage insurance may not be adequate to cover all losses sustained as a result thereof. In
addition, insurance coverage may not continue to be available in the future in amounts adequate to insure
against such seismic disturbances.
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We may be unable to obtain the financing we need to pursue our growth strategy
When we identify a geothermal property that we may seek to acquire or to develop, a substantial capital
investment often will be required. Our continued access to capital, through project financing or through
credit facilities or other arrangements with acceptable terms is necessary for the success of our growth
strategy. Our attempts to secure the necessary capital may not be on favourable terms, or successful at
all. Market conditions and other factors may not permit future project and acquisition financings on terms
favourable to us. Our ability to arrange for financing on favourable terms, and the costs of such
financing, are dependent on numerous factors, including general economic and capital market conditions,
investor confidence, the continued success of current projects, the credit quality of the project being
financed, the political situation in the jurisdiction in which the project is located and the continued
existence of tax laws which are conducive to raising capital. If we are unable to secure capital through
credit facilities or other arrangements, we may have to finance our projects using equity financing which
will have a dilutive effect on our common shares. Also, in the absence of favourable financing or other
capital raising options, we may decide not to build new plants or acquire properties from third parties.
Any of these alternatives could have a material adverse effect on our growth prospects and financial
condition.
It is very costly to place geothermal resources into commercial production
Before the sale of any power can occur, it will be necessary to construct a gathering and disposal system,
a power plant, and a transmission line, and considerable administrative costs will be incurred, together
with the drilling of production and injection wells. Future development and expansion of power
production at our properties may result in significantly increased capital costs related to increased
production and injection well drilling and higher costs for labour and materials. To fund expenditures of
this magnitude, we may have to seek additional financing and sources of capital. There can be no
assurance that additional capital can be found and, if found, it may result in us having to substantially
reduce our interest in the project.
We may continue to incur negative operating cash flow for the foreseeable future
Revenues at our Soda Lake Operation are not sufficient to fund all of our anticipated expansion,
development and exploration programs and general and administrative expenses. We currently have a
negative operating cash flow and may continue to do so for the foreseeable future. Our failure to achieve
profitability and positive operating cash flows could have a material adverse effect on our financial
condition and results of operations.
Energy prices are subject to dramatic and unpredictable fluctuations
The market price of energy is volatile and cannot be controlled. If the price of electricity should drop
significantly, the economic prospects of the operations and properties that we have an interest in could be
significantly reduced or rendered uneconomic. There is no assurance that, even if commercial quantities
of geothermal resources are discovered, a profitable market may exist for the sale of geothermal energy.
Factors beyond our control may affect the marketability of any geothermal resources discovered. Prices
have fluctuated widely, particularly in recent years. The marketability of geothermal energy is also
affected by numerous other factors beyond our control, including government regulations relating to
royalties, allowable production and exporting of energy sources, the effect of which cannot be accurately
predicted.
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Industry competition may impede our ability to access suitable geothermal resources
Significant and increasing competition exists for the limited number of geothermal opportunities
available. As a result of this competition, some of which is with large established companies with
substantial capabilities and greater financial and technical resources than us, we may be unable to acquire
additional geothermal operations or properties on terms we consider acceptable. There can be no
assurance that our acquisition programs will yield new geothermal operations or properties.
We may be unable to enter into PPAs on terms favourable to us, or at all
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. The industry 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 favourable terms to us, or at all, it would negatively impact our
revenue and our decisions regarding development of additional properties.
The cancellation or expiry of government initiatives to support renewable energy generation may
adversely affect our business
Numerous government initiatives are currently in place, or have been or may be proposed, to support the
development of renewable energy generation to meet increasing electricity demand. In the United States,
current initiatives include: incentives within the United States Internal Revenue Code, such as the
investment tax credit (“ITC”) and accelerated depreciation allowances; provisions of the ARRA
extending the availability of the PTCs for geothermal projects placed in service before 2014, increasing
the ITC from 10% to 30% of eligible costs, and creating a new grant program for geothermal projects that
are placed in service in, or for which construction begins in, 2009 or 2010; and renewable portfolio
standards requirements or goals established in 33 states and the District of Columbia. The cancellation or
expiry of any one or more of these government initiatives, or the failure of federal or state governments to
adopt similar initiatives in the future, may adversely affect our business by increasing the costs for
financing or development of geothermal power plants and related transmission facilities, reducing
demand for geothermal electricity or lowering energy prices.
Environmental and other regulatory requirements may add costs and uncertainty
Our current and future operations, including exploration and development activities and electricity
generation from power plants, require licences and permits from various governmental authorities and
such operations are and will be subject to laws and regulations governing exploration and development,
geothermal resources, production, exports, taxes, labour standards, occupational health, waste disposal,
toxic substances, land use, environmental protection, project safety and other matters. Companies can
experience increased costs, and delays in production and other schedules as a result of the need to comply
with applicable laws, regulations, licences and permits. There is no assurance that all approvals or
required licences and permits will be obtained. Additional permits, licences and studies, which may
include environmental impact studies conducted before licences and permits can be obtained, may be
necessary prior to the exploration or development of properties, or the operation of power plants, in which
we have interests, and there can be no assurance that we will be able to obtain or maintain all necessary
licences or permits that may be required on terms that enable operations to be conducted at economically
justifiable costs. Failure to comply with applicable laws, regulations, licensing or permitting
requirements may result in enforcement actions thereunder, including orders issued by regulatory or
judicial authorities causing operations to cease or be curtailed, and may include corrective measures
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requiring capital expenditures, installation of additional equipment, or remedial actions. We may be
required to compensate those suffering loss or damage by reason of our activities, and may have civil or
criminal fines or penalties imposed upon us for violations of applicable laws or regulations.
In the state of Nevada, drilling for geothermal resources is governed by specific rules. In particular,
Nevada drilling operations are governed by the Division of Minerals (Nevada Administrative Code
Chapter 534A). 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.
Applicable laws and regulations, including environmental requirements and licensing and permitting
processes, may require public disclosure and consultation. It is possible that a legal protest could be
triggered through one of these requirements or processes that could delay, or require the suspension of, an
exploration or development program or the operation of a power plant and increase our costs. Because of
these requirements, we could incur liability to governments or third parties for any unlawful discharge of
pollutants into the air, soil or water, including responsibility for remediation costs. We could potentially
discharge such materials into the environment: from a well or drilling equipment at a drill site; leakage of
fluids or airborne pollutants from gathering systems, pipelines, power plants or storage tanks; damage to
geothermal wells resulting from accidents during normal operations; and blowouts, cratering
and explosions.
No assurance can be given that new laws and regulations will not be enacted or that existing laws and
regulations will not be applied in a manner that could limit or curtail our exploration and development
programs or our operation of power plants. Amendments to current laws, regulations, licences and
permits governing operations and activities of geothermal companies, or more stringent implementation
thereof, could have a material adverse impact on us and cause increases in capital expenditures or
production costs, or reduction in levels of production, or abandonment, or delays in development of
the business.
The success of our business relies on attracting and retaining key personnel
We are dependent upon the services of our senior management team. The loss of any of their services
could have a material adverse effect upon us.
Employee recruitment, retention and human error
Recruiting and retaining qualified personnel is critical to our success. We are dependent on the services
of key executives including our Chief Executive Officer and other highly skilled and experienced
executives and personnel focused on managing our interests. The number of persons skilled in
acquisition, exploration, development and operation of geothermal properties is limited and competition
for such persons is intense. As our business activities grow, we will require additional key financial,
administrative and technical personnel as well as additional operations staff. There can be no assurance
that we will be successful in attracting, training and retaining qualified personnel as competition for
persons with these skill sets increase. If we are not successful in attracting, training and retaining
qualified personnel, the efficiency of our operations could be impaired, which could have an adverse
impact on our future cash flows, earnings, results of operations and financial condition.
Despite efforts to attract and retain qualified personnel, as well as the retention of qualified consultants, to
manage our interests, even when those efforts are successful, people are fallible and human error could
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result in significant uninsured losses to us. These could include loss or forfeiture of mineral claims or
other assets for non-payment of fees or taxes, significant tax liabilities in connection with any tax
planning effort we might undertake and legal claims for errors or mistakes by our personnel.
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 we may participate, the directors may have a conflict of interest in
negotiating and concluding terms respecting the extent of such participation. From time to time several
companies may participate in the acquisition, exploration and development of natural resource properties
thereby allowing for their participation in larger programs, permitting involvement in a greater number of
programs and reducing financial exposure in respect of any one program. It may also occur that a
particular company will assign all or a portion of its interest in a particular program to another of these
companies due to the financial position of the company making the assignment.
We may face adverse claims to our title
Although we have taken reasonable precautions to ensure that legal title to our properties is properly
documented, there can be no assurance of title to any of our property interests, or that such title will
ultimately be secured. Our property interests may be subject to prior unregistered agreements or transfers
or other land claims, and title may be affected by undetected defects and adverse laws and regulations.
Pursuant to the terms of our BLM leases, 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. Additionally, certain BLM leases contain additional requirements, some of which relate to
the mitigation or avoidance of disturbance of any antiquities, cultural values or threatened or endangered
plants or animals, the payment of royalties for timber and the imposition of certain restrictions on
residential development on the leased 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 of the provisions of the Geothermal
Steam Act of 1970 or regulations issued thereunder, the BLM may, 30 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, future results and cash flow.
Developments regarding Aboriginal, First Nations and Indigenous peoples
We explore and operate in areas inhabited by aboriginal, first nations, and indigenous people. Developing
laws and movements respecting the acquisition of lands and other rights from such people and
communities may alter decades old arrangements made by prior owners of our geothermal properties or
even those made by us in more recent years. We have used commercially reasonable efforts in its dealing
with all aboriginal, first nations, and indigenous people to ensure all agreements are entered into in
accordance with the laws governing aboriginal, first nations, and indigenous peoples and their
communities but because of complex procedural and administrative requirements in some jurisdictions,
there is no guarantee that such agreements will ultimately protect our interest, nor can there be any
guarantee that future laws and actions will not have a material adverse effect on our financial position,
cash flow and results of operations.
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A significant portion of our revenue is attributed to payments made by a single power purchaser under
the Soda Lake PPAs
Electricity sales from our Soda Lake Operation are governed by the terms of two long-term PPAs with
NV Energy. Accordingly, our revenues and power generation operations are currently dependent upon a
sole customer, NV Energy. We do not make any representations as to the financial condition or
creditworthiness of NV Energy, and nothing in this Annual Information Form should be construed as
such a representation.
There is a risk that NV Energy may not fulfill its payment obligations under the Soda Lake PPAs. For
example, as a result of the energy crisis in California in the early 2000s, Southern California Edison
withheld payments it owed under various of its PPAs with a number of power generators between
November 2000 and March 2002. If NV Energy fails to meet its payment obligations under the Soda
Lake PPAs, it could materially and adversely affect our business, financial condition, future results
and cashflow.
Fluctuation in foreign currency exchange rates may affect our financial results
We maintain accounts in Canadian and U.S. dollars. Our operations in the United States and South
America make us subject to foreign currency fluctuations. Foreign currency fluctuations are material to
the extent that fluctuations between the Canadian and U.S. dollar and/or U.S. dollar balances are material.
We do not at present, nor do we plan in the future, to engage in foreign currency transactions to hedge
exchange rate risks but we do convert Canadian funds to U.S. dollars anticipating U.S. expenditures.
We may not be able to successfully integrate businesses or projects that we acquire in the future
Our business strategy is to expand in the future, including through acquisitions. Integrating acquisition
targets is often costly, and we may not be able to successfully integrate acquired companies with its
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:

the failure of the acquired companies to achieve expected results;

inability to retain key personnel of acquired companies;

risks associated with unanticipated events or liabilities; and

difficulties associated with establishing and maintaining uniform standards, controls,
procedures and policies, including accounting and other financial controls and procedures.
Our insurance policies may be insufficient to cover losses
As protection against operating hazards, we maintain insurance coverage against some, but not all,
potential losses. We do not fully insure against all risks associated with our business either because such
insurance is not available or because the cost of such coverage is considered prohibitive. The occurrence
of an event that is not covered, or not fully covered, by insurance could have a material adverse effect our
financial condition and results of operations.
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Risks Relating to HS Orka
Magma’s prior acquisitions of HS Orka may be wound-down or invalidated
Following closing of the Company’s public offering of common shares on July 27, 2010, Magma became
aware that a press conference had been arranged by the Prime Minister of Iceland to be held at 9:30 a.m.
(Pacific Standard Time) on July 27, 2010. At that press conference a “Statement of the Government
relating to Energy and Natural Resource Matters” (the “Statement”) was issued in which the government
of Iceland announced that it will appoint a special committee of independent experts (the “Special
Committee”) to investigate and review the privatization of Iceland’s energy sector in recent years. The
government of Iceland has advised that specific attention will be given to the privatization process of
Hitaveita Sudurnesja (now HS Orka) and the subsequent acquisitions by Magma Sweden of interests in
HS Orka.
Iceland’s Committee on Foreign Investment (the “Foreign Investment Committee”) has reviewed each
proposed acquisition by Magma Sweden of shares of HS Orka, including the Final Acquisition, and
provided opinions that each of these acquisitions were permitted under the provisions of Iceland’s Act on
Foreign Investment. Notwithstanding this, in an attachment to the Statement, the government of Iceland
noted that the Foreign Investment Committee had not reached a consensus in arriving at its conclusions
and the government proposed that this cast doubt on the legality of the transactions and that the
transactions should be reviewed. In particular, the government of Iceland questioned whether the
acquisitions by Magma Sweden are consistent with Icelandic law and the rules respecting the European
Economic Area Agreement.
On September 17, 2010, the Special Committee provided an initial report indicating that given the initial
decision by the Foreign Investment Committee in relation to the Company’s acquisition of its interests in
HS Orka was positive and given that the government did not take further action, it would be normal for
the government to take no further action at this time.
The Company believes that the transactions are in full compliance with Icelandic law. However, there is
the possibility that, following completion of the Special Committee’s investigation and review, the
government of Iceland may take steps to wind-down or invalidate Magma Sweden’s prior business
transactions involving shares of HS Orka. The winding-down or invalidation of Magma Sweden’s prior
business transactions involving shares of HS Orka could have a material adverse effect on Magma’s
operations and financial results.
Prior privatization of Hitaveita Sudurnesja may be wound-down or invalidated
In the Statement, the government of Iceland announced that it will appoint a Special Committee to
investigate and review the privatization of Iceland’s energy sector in recent years. In particular, the
government of Iceland advised that specific attention will be given to the privatization process of
Hitaveita Sudurnesja (now HS Orka) with a focus on: whether the original sale of Hitaveita Sudurnesja
begun in the spring of 2007 was in compliance with Icelandic law and the rules of procedure of the
Executive Committee on Privatization; the interactions between the government of Iceland at the time and
the competition authority regarding the political decision that publicly owned agencies should be barred
from bidding for shares of Hitaveita Sudurnesja; the valuation, financing and guarantee of payments for
individual privatization transactions; the relationships between participants in the privatization process;
and whether there was any assignment or plans for assignment of the rights of municipalities or the State
to energy resources which have yet to be negotiated.
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In a letter dated July 27, 2010 to HS Orka, the Ministry of Commerce of the government of Iceland
advised HS Orka of the Special Committee’s investigation and review referred to above and also advised
that a complaint has been submitted in connection with the acquisition by Magma Sweden of shares of
HS Orka to the Ombudsman of the Althing, who is appointed by the Parliament of Iceland to monitor the
administration of the state and local authorities and safeguard the rights of the citizens with regard to the
authorities. Conclusions by the Ombudsman of the Althing are not legally binding on the government of
Iceland; however, they are normally given a high degree of deference. The letter also indicated that the
government of Iceland is determined to wind-down the process of privatization in Iceland’s energy sector
and ensure, to the extent possible, that Iceland’s most important energy enterprises remain under the
control of public entities. The letter concludes by stating that the government of Iceland has not made a
final decision regarding Magma Sweden’s investment in HS Orka, but is now studying the future
operating and legal environment of enterprises in Iceland’s energy sector.
Accordingly, following completion of the Special Committee’s investigation and review, the government
of Iceland may take steps to wind-down or invalidate the prior privatization of Hitaveita Sudurnesja. As
Magma Sweden acquired its current interest in HS Orka from, and has completed the Final Acquisition
with, participants in Hitaveita Sudurnesja’s privatization, the winding-down or invalidation of the prior
privatization of Hitaveita Sudurnesja could adversely affect Magma Sweden’s interest in its shares of HS
Orka and have a material adverse effect on Magma’s operations and financial results.
Nationalization or restrictions on foreign or private ownership of Icelandic energy companies and
levies or restrictions on utilization rights
In the Statement, the government of Iceland advised that a working group will begin preparing a
legislative bill to ensure public ownership of important energy enterprises in Iceland and restriction of
private ownership. The submission of a new legislative bill in accordance with the conclusions of the
working group is scheduled before the end of October 2010 and shall occur concurrently with the
preparation of legislation regarding levies on the utilization of water and geothermal rights owned by the
state, shorter licensing periods for such utilization rights and restrictions on the assignment of utilization
rights except on a temporary basis.
Accordingly, depending on the terms of the draft legislation and subject to the government of Iceland
enacting the draft legislation, HS Orka may be nationalized by the government of Iceland, Magma’s
interest in HS Orka may be wound-down or restricted, and HS Orka may be subject to additional levies
on utilization rights for its geothermal properties, with such utilization rights potentially having shorter
terms. Any or all of these developments, if addressed by the draft legislation and enacted by the
government of Iceland, could adversely affect Magma Sweden’s interest in its shares of HS Orka and
could have a material adverse effect on Magma’s results of operations and financial results.
Lack of compensation resulting from government actions
In the event the government of Iceland takes steps to wind-down or invalidate the Final Acquisition,
nationalizes the assets of HS Orka, expropriates the assets of HS Orka or takes any other similar action
with regard to HS Orka, its assets, or Magma’s interest in HS Orka, the government of Iceland may not
pay to Magma compensation for taking such action, which could have a material adverse effect on
Magma’s results of operations and financial results.
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Potential fines or other penalties
Following completion of the Final Acquisition, the government of Iceland may take action which results
in fines or other penalties levied against Magma or HS Orka, which could have a material adverse effect
on Magma’s results of operations and financial results.
Integration of HS Orka following the completion of the Final Acquisition
There can be no assurance that the Company will be able to successfully integrate HS Orka or that it will
be able to realize expected operating and economic efficiencies from the integration of the businesses of
HS Orka and Magma. If the expected synergies do not materialize, or the Company fails to successfully
integrate the business of HS Orka in its existing operations, results of its operations could be adversely
affected.
Foreign exchange
Generally, the revenue of HS Orka is generated in ISK and in United States dollars. Fluctuations in
exchange rates between the Canadian dollar and each of the ISK and the United States dollar will
therefore give rise to foreign currency exposure which could have a material adverse effect on the
Company’s financial position.
Aluminum price risk
A large portion of the revenue of HS Orka is subject to the market price for aluminum. In addition, the
Company's debt obligations are also subject to the market price for aluminum. Accordingly, fluctuations
in the market price for aluminum could have a material adverse effect on the Company’s financial
position.
Potential undisclosed liabilities associated with the Final Acquisition
In connection with the Final Acquisition, there may be liabilities that the Company failed to discover or
was unable to quantify in its due diligence prior to the closing of the Final Acquisition and the Company
may not be fully indemnified for some or all of these liabilities. The discovery of any material liabilities
could have a material adverse affect on the Company’s business, financial condition or future prospects.
Risks Relating to the Political and Economic Climates of Countries in which we Operate
There are risks associated with inter-regional transmission grids
The electrical power generated by our operations may be used by consumers in the jurisdiction where
such operations are located or sold to other neighbouring jurisdictions through an inter-regional
transmission grid. Applicable laws, inter-regional agreements and the structure and functioning of the
power markets between a host state and its neighbouring states are all critical to the success of our
geothermal projects.
Host country economic, social and political conditions can negatively affect our operations
A number of our exploration properties are located in Iceland, Chile, Argentina and Peru. As we conduct
exploration and development operations in these foreign countries, we are exposed to a number of risks
and uncertainties, including:
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
terrorism and hostage taking;

military repression;

expropriation or nationalization without adequate compensation;

difficulties enforcing judgments obtained in Canadian or United States courts against assets
located outside of those jurisdictions;

labour unrest;

high rates of inflation;

changes to royalty and tax regimes;

extreme fluctuations in currency exchange rates;

volatile local political and economic developments;

difficulty with understanding and complying with the regulatory and legal framework
respecting the ownership and maintenance of geothermal properties and power plants; and

difficulty obtaining key equipment and components for equipment.
Host country economic, social and political uncertainty can arise as a result of lack of support for our
activities in local communities in the vicinity of our properties. Such uncertainties also arise as a result of
the relatively new and evolving promotion of private-sector power development. Though the effects of
competition will increase the likelihood of market efficiencies and benefit our properties, elimination of
energy cost subsidies may increase the inability of end-use consumers to pay for power and lead to
political opposition to privatization initiatives and have an adverse impact on our properties and
operations.
Risks Relating to the Common Shares and Trading Market
If our common share price fluctuates, investors could lose a significant part of their investment
In recent years, the stock market has experienced significant price and volume fluctuations. This
volatility has had a significant effect on the market price of securities issued by many companies for
reasons unrelated to the operating performance of these companies. The market price of our common
shares could similarly be subject to wide fluctuations in response to a number of factors, most of which
we cannot control, including:

changes in securities analysts’ recommendations and their estimates of our financial
performance;

the public’s reaction to our press releases, announcements and filings with securities
regulatory authorities and those of its competitors;

changes in market valuations of similar companies;

investor perception of our industry or prospects;
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
additions or departures of key personnel;

commencement of or involvement in litigation;

changes in environmental and other governmental regulations;

announcements by us or our competitors of strategic alliances, significant contracts, new
technologies, acquisitions, commercial relationships, joint ventures or capital commitments;

variations in our quarterly results of operations or cash flows or those of other companies;

revenues and operating results failing to meet the expectations of securities analysts or
investors in a particular quarter;

future issuances and sales of our common shares; and

changes in general conditions in the domestic and worldwide economies, financial markets or
the mining industry.
The impact of any of these risks and other factors beyond our control could cause the market price of our
common shares to decline significantly. In particular, the market price for our common shares may be
influenced by variations in electricity prices. This may cause our common share price to fluctuate with
these underlying commodity prices, which are highly volatile.
We have no dividend payment policy and do not intend to pay any cash dividends in the foreseeable
future
We have not declared or paid any dividends on our common shares and do not currently have a policy on
the payment of dividends. For the foreseeable future, we anticipate that we will retain future earnings and
other cash resources for the operation and developments of our business. The payment of any future
dividends will depend upon earnings and our financial condition, current and anticipated cash needs and
such other factors as our Board of Directors considers appropriate.
The issuance of additional equity securities may negatively impact the trading price of our common
shares
We may issue equity securities to finance our activities in the future. In addition, outstanding options or
warrants to purchase our common shares may be exercised, resulting in the issuance of additional
common shares. Our issuance of additional equity securities or a perception that such an issuance may
occur could have a negative impact on the trading price of our common shares.
Current global financial conditions have been subject to increased volatility
Current global financial conditions have been subject to increased volatility and numerous financial
institutions have either gone into bankruptcy or have had to be rescued by governmental authorities.
Access to public financing has been negatively impacted by both sub-prime mortgages and the liquidity
crisis affecting the asset-backed commercial paper market. These factors may impact our ability to obtain
equity or debt financing in the future and, if obtained, on terms favourable to us. If these increased levels
of volatility and market turmoil continue, our operations could be adversely impacted and the trading
price of our common shares could be adversely affected.
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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
Other than as disclosed below and elsewhere in this Annual Information Form, none of our directors or
senior officers or any shareholder holding, on record or beneficially, directly or indirectly, more than 10%
of the issued common shares, or any of their respective associates or affiliates, had any material interest,
directly or indirectly, in any material transaction with us within the three preceding years or in any
proposed transaction which has materially affected us or would materially affect us.
Pursuant to the terms of the credit agreement (the “2008 Credit Agreement”) dated August 25, 2008
between Magma and Kestrel Holdings Ltd. (“Kestrel”), a private company wholly-owned by our
Chairman and Chief Executive Officer, Ross J. Beaty, Kestrel has agreed to lend us an aggregate
principal amount of up to Cdn.$20,000,000 to be used by us to pay amounts coming due in connection
with the acquisition of the Soda Lake Operation, to pay our obligations respecting certain land
acquisitions, and to fund our general working capital requirements.
The principal amount of each initial advance and each subsequent advance, together with all accrued but
unpaid interest and other costs or charges payable under the 2008 Credit Agreement will be immediately
due and payable by us to Kestrel on the earlier of 12 months from the date of the initial advance under the
2008 Credit Agreement, the date of any change of control of Magma, any initial public offering of
Magma, or the occurrence of an event of default, as defined in the 2008 Credit Agreement.
We may prepay the facility in whole at any time before maturity, without notice or penalty. Interest will
accrue on the outstanding balance under the 2008 Credit Agreement as of the date of the initial advance,
at the rate of eight percent per annum. We will pay a standby fee to Kestrel in the amount of one percent
of the total facility upon the initial advance under the 2008 Credit Agreement and a non-refundable
drawdown fee to Kestrel in the amount of three percent of each advance under the 2008 Credit
Agreement. We will also pay Kestrel’s legal fees and other costs, charges and expenses of and incidental
to the preparation, execution and completion of the 2008 Credit Agreement. In the event any amount
remains outstanding under the terms of the 2008 Credit Agreement after December 31, 2009, Kestrel has
the option to convert any such amount into common shares at a rate per share equal to Cdn.$1.50 per
common share, subject to certain adjustments. In the event any amount remains outstanding under the
terms of the 2008 Credit Agreement after December 31, 2009, we shall also have the option to convert up
to 55 percent or any such lesser amount into common shares at Cdn.$1.50 per common share, subject to
certain adjustments. As of the date of this Annual Information Form all amounts advanced under the
2008 Credit Agreement have been repaid in full.
Pursuant to the terms of the 2010 Credit Agreement dated July 5, 2010, an agreement with Ross Beaty,
the Company’s Chairman and Chief Executive Officer, the Company is able to borrow up to
Cdn.$10,000,000 to pay amounts coming due by the Company to Geysir Green respecting the Final
Acquisition of shares of HS Orka, and to fund general working capital requirements. All funds advanced
under the 2010 Credit Agreement are repayable on the earlier of twelve months from the date of the initial
advance, a change of control of the Company or on a default by Magma. Interest at the rate of 8% per
annum, compounded daily, is payable monthly commencing on July 30, 2010. In addition, a standby fee
in the amount of 1% of the credit facility and a drawdown fee in the amount of 1.5% of the amount
advanced is payable in cash. As of the date of this Annual Information Form, the full principal amount of
the credit facility has been advanced to the Company to be used in connection with the Final Acquisition
of shares of HS Orka.
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TRANSFER AGENT AND REGISTRAR
The registrar and transfer agent for our common shares is Computershare Investor Services Inc. at its
principal offices in Vancouver, British Columbia.
MATERIAL CONTRACTS
Our only material contracts entered into since the beginning of the last financial year ending before the
date of this Annual Information Form, and our material contracts entered into before the beginning of the
last financial year ending before the date of this Annual Information Form that are still in effect, other
than contracts entered into in the ordinary course of business, are as follows:

the 2010 Credit Agreement;

the Long-Term Agreement for the Purchase and Sale of Electricity between Sierra Pacific
Power Company and Ormat Energy Systems and WSG dated August 10, 1987 as amended
September 27, 1990; March 7, 1991; and October 9, 1991;

the Long-Term Agreement for the Purchase and Sale of Electricity between Sierra Pacific
Power Company and Ormat Energy Systems dated March 7, 1989 as amended May 15, 1989;
September 27, 1990; March 7, 1991; and October 9, 1991; and

a share purchase agreement among the Company, Magma Energy Sweden A.B. and Geysir
Green dated May 16, 2010, relating to the Final Acquisition, the terms of which are described
in this Annual Information Form under the heading “General Developments of the Business”.
Copies of the above material contracts are available on SEDAR located at www.sedar.com.
INTEREST OF EXPERTS
No person or company whose profession or business who is named as having prepared or certified a
statement, report, valuation or opinion described or included in this Annual Information Form holds any
beneficial interest, direct or indirect, in any of our securities or property or in the securities or properties
of any of our associates, or affiliates and no such person is expected to be elected, appointed or employed
as one of our directors, officers or employees or as a director, officer or employee of any of our associates
or affiliates and no such person is one of our promoters or the promoter of one of our associates or
affiliates. In particular, Grant Thornton LLP has informed us that it is independent with respect to
Magma within the meaning of the Rules of Professional Conduct of the Institute of Chartered
Accountants of British Columbia.
KPMG hf is HS Orka’s auditor. As of the date hereof, KPMG hf and its designated professionals are
independent of, and have no interest in, the Company.
Information of an economic, scientific or technical nature regarding the geothermal resources and
properties of HS Orka included in this Annual Information Form is based upon the HS Orka Report. The
HS Orka Report was prepared by Mannvit hf. Information of an economic scientific or technical nature
regarding the geothermal resources of the Soda Lake Operation is based upon the Soda Lake Report. The
Soda Lake Report was prepared by GeothermEx. Information of a scientific or technical nature regarding
the McCoy, Panther Canyon, Thermo Hot Springs and Desert Queen Properties included in this Annual
Information Form is based upon each of the McCoy Report, Panther Canyon Report, Thermo Hot Springs
Report and Desert Queen Report, respectively. Each of the McCoy Report, Panther Canyon Report,
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Thermo Hot Springs Report and Desert Queen Report were prepared by J. Douglas Walker, Ph.D.
Information of an economic, scientific or technical nature regarding the geothermal resources of the
Mariposa Property is based upon the Mariposa Report. The Mariposa Report was prepared by Phillip
James White of SKM. See “Scientific and Technical Information”.
The authors referenced above are independent of the Company and do not have an interest in the property
of the Company.
ADDITIONAL INFORMATION
Additional information relating to the Company may be found on SEDAR at www.sedar.com. Additional
information including directors’ and officers’ remuneration and indebtedness, principal holders of the
Company’s securities and securities authorized for issuance under equity compensation plans will be
contained in the Company’s information circular to be prepared in connection with the Company’s annual
meeting of shareholders and will be available on SEDAR at www.sedar.com. Additional financial
information is provided in the Company’s financial statements and management’s discussion and analysis
for the financial year ended June 30, 2010, which are also available on SEDAR.
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GLOSSARY OF TERMS
In this Annual Information Form, the following terms shall have the meanings set forth below,
unless otherwise indicated or the context otherwise requires:
“2008 Credit Agreement” means the credit agreement dated August 25, 2008 between Magma
and Kestrel.
“2010 Credit Agreement” means the credit agreement dated July 5, 2010 between Magma and
Ross Beaty.
“AltaGas” means AltaGas Ltd.
“AMAX” means AMAX Exploration, Inc.
“Aminoil” means Aminoil U.S.A., Inc.
“Amor IX” means Amor IX, LLC.
“anion” means a negatively charged atom or group of atoms, or a radical which moves to the
positive pole (anode) during electrolysis.
“AQUA model” means the numerical model developed by Vatnaskil to simulate the water level
changes in the fields and make forecasts on future water levels, given future production scenarios.
“AR$” means Argentine Pesos.
“ARRA” means the American Recovery and Reinvestment Act of 2009.
“As” is the symbol in the periodic table for the element arsenic.
“Australian Code” means the Australian Geothermal Reporting Code.
“Ballet” means Pacific Ballet British Columbia Society.
“BLM” means U.S. Bureau of Land Management.
“°C” means degrees Celsius.
“cal/cm/s°C” means calories per centimetre per second degree Celsius – it is a measure of
conductivity and is used for heat flow calculations.
“Canadian Code” means the Canadian Geothermal Code for Public Reporting.
“Canico” means Canico Resource Corp.
“carbonate sinter” means a chemical sedimentary rock, that contains the carbonate anion,
deposited as a hard incrustation on rocks or on the ground by precipitation from hot or cold mineral
waters of springs, lakes or streams.
“cation” means a positively charged atom or group of atoms, or a radical which moves to the
negative pole (cathode) during electrolysis.
G-1
“Cdn.$ ” means Canadian dollars.
“Chevron” means Chevron Resources Company.
“chloride-sodic” refers to the most common type of geothermal water, typically near neutral in
pH, with chloride contents ranging up to a few thousand milligrams per litre and sodium being the
dominant cation.
“Cl/HCO3”means chloride bicarbonate.
“Constellation” means Constellation Energy Group, Inc.
“convective cell” means the pattern formed in a fluid when local warming causes part of the fluid
to rise, and local cooling causes it to sink again elsewhere.
“Desert Queen Report” means the Independent Technical Report Resource Evaluation of the
Desert Queen Geothermal Project, Churchill County, Nevada dated May 12, 2009 prepared by Dr. J.
Douglas Walker (Ph.D.).
“dollars” or “$” means United States dollars.
“EM-60” is the term for a high-powered, controlled source geophysical exploration tool based on
measurement of electromagnetic induction. This device was developed and used exclusively by Lawrence
Berkeley from 1977 until approximately 1989.
“F” is the symbol in the periodic table for the element fluorine.
“°F” means degrees Fahrenheit.
“Final Acquisition” has the meaning ascribed to the term under “General Development of the
Business”.
“Foreign Investment Committee” means Iceland’s Committee on Foreign Investment.
“GeothermEx” means GeothermEx Inc.
“Geysir Green” means Geysir Green Energy ehf.
“GHA” means Geo Hills Associates LLC.
“GPM” means a flow rate of gallons per minute. One GPM is equal to 0.0606 (repeating
decimal) kilograms per second.
“graben” means an elongated, downthrown block bounded by two steeply dipping normal faults,
produced in an area of crustal extension.
“H2S” is the chemical formula for hydrogen sulphide.
“Harbert” means Harbert Power Corporation.
“HFU” means heat flow unit. One heat flow unit is equal to 40 mW/m2.
G-2
“Hg” is the symbol in the periodic table for the element mercury.
“HS Orka” means HS Orka hf.
“HS Orka Report” means the Geothermal Resources and Properties of HS Orka, Reykjanes
Peninsula, Iceland: Independent Technical Report dated January 29, 2010 prepared by Mannvit hf.
“IBLA” means the Interior Board of Land Appeals.
“INGEMMET” means the Instituto Geológico Minero Y Metalúrgico.
“Initially Offered Common Shares” has the meaning ascribed to such term under “Escrowed
Securities”.
“InSAR” means Interferometric Synthetic Aperture Radar.
“ISK” means Icelandic Krona.
“ÍSOR model” means a detailed 3D numerical model developed in 2007.
“ITC” means investment tax credit.
“Kestrel” means Kestrel Holdings Ltd.
“kV” means kilovolt (1000 volts).
“Lawrence Berkeley” means the Lawrence Berkeley National Laboratory.
“Ma” means mega annum or one million years.
“Magma Sweden” means Magma Energy Sweden A.B.
“Magma US” means Magma Energy (U.S.) Corp.
“Mariposa Report” means the Mariposa Geothermal Resource, Laguna Del Maule and Pellado
Concessions, Chile dated July 19, 2010 prepared by Philip James White of Sinclair Knight Merz Limited.
“McCoy Report” means the Independent Technical Report Resource Evaluation of the McCoy
Geothermal Project, Churchill and Landers Counties, Nevada dated April 29, 2009 prepared by Dr. J.
“MEM” means the Peruvian Ministry of Energy and Mines.
“Mg” is the symbol in the periodic table for the element magnesium.
“mg/L” means milligrams per litre.
“MMS” means the U.S. Minerals Management Service.
“MT” means magnetotelluric.
G-3
“Municipal Bond” means the bond issued by Geysir Green to the Municipality of Reykjanesbær
with a face value of 6.3 billion ISK (approximately $50.5 million), which Magma is assuming as part of
the share purchase agreement entered into with Geysir Green on May 17, 2010 whereby Magma will
acquire the remainder of Geysir Green’s interest in HS Orka.
“MW” means megawatt; one million watts.
“mW/m2” means milliwatts per square metre.
“MXY” means the trading symbol of Magma on the TSX.
“Na/K/Ca” refers to a sodium-potassium-calcium geothermometer that is a geochemical
calculation used to estimate geothermal reservoir temperature from analytical results of liquid samples.
“NI 43-101” means National Instrument 43-101 – Standards of Disclosure for Mineral Projects.
“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas
Activities.
“Nordural” means Nordural Helguvik sf.
“NV Energy” means NV Energy Company.
“OEC” means Ormat Energy Converters.
“Orkustofnun” means the National Energy Authority.
“Ormat” means Ormat Nevada Inc.
“Other Initial Investors” has the meaning ascribed to the term under “Escrowed Securities”.
“Other Restricted Common Shares” has the meaning ascribed to the term under “Escrowed
Securities”.
“Other Restricted Shareholders” has the meaning ascribed to the term under “Escrowed
Securities”.
“PA” means the Participating Area, which is a portion of the SLUA that was reasonably proven
productive based on well testing performance.
“Pan American” means Pan American Silver Corp.
“Panther Canyon Report” means the Independent Technical Report Resource Evaluation of the
Panther Canyon/Leach Geothermal Project, Pershing County, Nevada dated April 29, 2009 prepared by
Dr. J. Douglas Walker (Ph.D.).
“parasitic load” refers to the amount of power used for pumps, motors and ancillary functions
related to the operation of a power plant. Gross electricity production minus parasitic load equals net
energy production.
“Pb” is the symbol in the periodic table for the element lead.
G-4
“PECs” means Portfolio Energy Credits.
“pH” stands for “potential of hydrogen”. References to pH levels in this Annual Information
Form are in respect of numbers on the pH scale, which is used to measure the acidity or basicity
(alkalinity) of a solution. This scale ranges from 0 (maximum acidity) to 14 (maximum alkalinity). The
middle of the scale, 7, represents the neutral point. Acidity increases from neutral toward 0, and alkalinity
increases from 7 toward 14. As the pH scale is logarithmic, a difference of one pH unit represents a
tenfold change. For example, the acidity of a sample with a pH of 5 is ten times greater than that of a
sample with a pH of 6. A difference of 2 units, from 6 to 4, would mean that the acidity is one hundred
times greater, and so on.
“Phillips” means Phillips Petroleum Company.
“Plutonic” means Plutonic Power Corporation.
“PPA” means power purchase agreement.
“ppm” means parts per million.
“PTC” means production tax credit.
“P50” means the median or the quantity for which there is a 50% probability that the recoverable
geothermal energy expressed in MW will equal or exceed the estimate.
“P90” means the quantity for which there is a 90% probability that the recoverable geothermal
energy expressed in MW will equal or exceed the estimate.
“Republic” means Republic Geothermal, Inc.
“RTI” means Raser Technologies, Inc.
“SEDAR” means the system for electronic document analysis and retrieval.
“self-potential” means an electrical exploration method in which one determines the spontaneous
electrical potentials (spontaneous polarization) that are caused by primary chemical, heat or fluid flow.
“SKM” means Sinclair Knight Merz Limited.
“SLLP” means Soda Lake Limited Partnership.
“SLRP” means Soda Lake Resource Partnership.
“SLUA” means the Soda Lake Unit Agreement.
“SO2” is the chemical formula for sulphur dioxide.
“Soda Lake Report” means the Independent Technical Report: Geothermal Resources and
Reserves at Soda Lake Project, Churchill County, Nevada USA dated April, 2010 prepared by
GeothermEx.
G-5
“Special Committee” means the special committee of independent experts appointed by the
government of Iceland to investigate and review the privatization of Iceland’s energy sector in recent
years.
“Special Warrants” means the 5,000,000 special warrants issued by Magma on September 29,
2008 to private investors pursuant to a brokered private placement at a price of Cdn.$2.00 per Special
Warrant, for gross proceeds of Cdn.$10,000,000.
“Statement” means the “Statement of the Government relating to Energy and Natural Resource
Matters” issued by the government of Iceland on July 27, 2010.
“TEM” means Transient Electromagnetic.
“TerraGen” means TerraGen Power, LLC.
“Thermo Hot Springs Report” means the Independent Technical Report Resource Evaluation of
the Thermo Hot Springs Geothermal Project, Beaver County, Utah dated May 15, 2009 prepared by Dr. J.
“transtension” is a structural geology term describing a particular state of stress in the crust of
the earth wherein there is a combination of translational (or shearing) and extension forces. This particular
condition is favourable to the formation of permeability in geothermal reservoir rocks.
“TSX” means the Toronto Stock Exchange.
“USGS” means the U.S. Geological Survey.
“Vatnaskil” means Vatnaskil Consulting Engineers.
“WSG” means Western States Geothermal Inc.
“Zn” is the symbol in the periodic table for the element zinc.
METRIC CONVERSION TABLE
Metric Unit
U.S. Measure
U.S. Measure
Metric Unit
1 hectare ...........................
2.471 acres
1 acre ...............................
0.4047 hectares
1 metre .............................
3.2881 feet
1 foot ...............................
0.3048 metres
1 kilometre .......................
0.621 miles
1 mile...............................
1.609 kilometres
G-6
APPENDIX “A”
AUDIT COMMITTEE CHARTER
1.
PURPOSE
The purpose of the audit committee (the “Committee”) is to assist the board of directors (the
“board”) in fulfilling its oversight responsibilities for (a) the accounting and financial reporting
processes; (b) the internal controls; (c) the external auditors, including performance,
qualifications, independence and their audit of the Company’s financial statements; and (d) the
performance of the Company’s internal audit function.
2.
3.
COMPOSITION
(a)
The Committee shall be composed of three independent directors and shall not include
any director employed by the Company.
(b)
The board shall appoint annually, from among its members, the members of the
Committee and its chair.
(c)
The members and the chair of the Committee shall serve one-year terms and are
permitted to serve an unlimited number of consecutive terms.
(d)
Each member of the Committee shall be financially literate, meaning that each member
must have the ability to read and understand a set of financial statements that present a
breadth and level of complexity of accounting issues that are reasonably comparable to
the breadth and complexity of the issues that can reasonably be expected to be raised by
the Company’s financial statements.
MEETING
(a)
The Committee shall meet at least four times per year and any member may call special
meetings as required.
(b)
A quorum at meetings of the Committee shall be two members. No business may be
transacted by the Committee except at a meeting of its members at which a quorum of the
Committee is present.
(c)
The chair of the Committee shall, in consultation with management and the auditors,
establish the agenda for the meetings and ensure that properly prepared agenda materials
are circulated to the members with sufficient time for study prior to the meeting.
(d)
The minutes of the Committee meetings shall accurately record the decisions reached and
shall be distributed to all directors with copies to the chief financial officer and the
external auditors.
4.
DUTIES AND RESPONSIBILITIES
(a)
Financial Information
The Committee shall review:
A-1
(b)
(i)
the annual financial statements and recommend their approval to the board, after
discussing matters such as the selection of accounting policies, major accounting
judgements, accruals and estimates with management;
(ii)
other financial information included in the annual report and any other reports to
shareholders and others;
(iii)
financial information in any annual information form, management proxy circular,
prospectus or other offering document, material change report or business acquisition
report;
(iv)
management’s discussions and analysis contained in the annual report and quarterly
statements, if any;
(v)
earnings press releases and any news release regarding financial results or containing
earnings guidance before being released to the public;
(vi)
fillings to the securities regulators containing financial information; and
(vii)
audits and reviews of financial statements of the Company and its subsidiaries.
External Audit
The Committee shall:
(i)
recommend to the board the external auditors to be nominated for the purpose of
preparing or issuing an auditor’s report or performing other audit, review or attest
services for the Company and the compensation of the external auditors;
(ii)
review and approve the Company’s hiring policies regarding partners, employees and
former partners or employees of the present or former external auditors of the Company;
(iii)
at least annually, review the qualifications and performance of the lead partners of the
external auditors and determine whether it is appropriate to adopt or continue a policy of
rotating the lead partner of the external auditors;
(iv)
review and pre-approve all audit and non-audit service engagement fees and terms in
accordance with applicable law, including those provided to the subsidiaries of the
Company by the external auditors or any other person in its capacity as external auditors
of such subsidiary;
(v)
review the planning and results of the external audit, including:
A.
the auditor’s engagement letter;
B.
the reasonableness of the estimated audit fees;
C.
the scope of the audit, including materiality, locations to be visited, audit reports
required, areas of audit risk, timetable, deadlines and coordination with internal
audit;
D.
the post-audit management letter together with management’s response;
A-2
(c)
E.
the form of the audit report;
F.
any other related audit engagements (e.g. audit of the company pension plan);
G.
non-audit services performed by the auditor;
H.
assessing the auditor’s performance; and
I.
meeting privately with the auditors to discuss pertinent matters, including the
quality of accounting personnel;
(vi)
discuss with management and the external auditors any significant financial reporting
issues considered during the fiscal period and the method of resolution and resolve
disagreements between management and the external auditors regarding financial
reporting; and
(vii)
review with management and the external auditors any items of concern, any proposed
changes in the selection or application of major accounting policies and the reasons for
the change, any identified risks and uncertainties, and any issues requiring management
judgment, to the extent that the foregoing may be material to financial reporting.
Interim Financial Statements
(d)
(i)
obtain reasonable assurance on the process for preparing reliable quarterly interim
financial statements from discussions with management and, where appropriate, reports
from the external and internal auditors;
(ii)
review and discuss with management and the external auditors all interim unaudited
financial statements and quarterly reports and related interim management discussion and
analysis and make recommendations to the board with respect to the approval thereof,
before being released to the public; and
(iii)
obtain reasonable assurance from management about the process for ensuring the
reliability of other public disclosure documents that contain audited and unaudited
interim financial information.
Accounting System and Internal Controls
(i)
obtain reasonable assurance from discussions with and/or reports from management and
reports from external and internal auditors that the Company’s accounting systems are
reliable and that the prescribed internal controls are operating effectively;
(ii)
direct the auditors’ examinations to particular areas;
(iii)
request the auditors to undertake special examinations (e.g., review compliance with
conflict of interest policies);
A-3
(e)
(iv)
review control weaknesses identified by the external and internal auditors, together with
management’s response;
(v)
review the appointments of the chief financial officer and key financial executives; and
(vi)
review accounting and financial human resources and succession planning within the
Company.
Internal Audit
(f)
(i)
review the terms of reference of the internal audit function and the appointment or
removal of the director of the internal audit;
(ii)
review the resources, budget, reporting relationships and planned activities of the internal
audit function; and
(iii)
review internal audit findings and determine that they are being properly followed-up.
Compliance
(g)
(i)
monitor compliance by the Company of the governing laws and any regulatory
requirements, including all payments and remittances required to be made in accordance
with applicable law;
(ii)
monitor compliance by the Company of the terms of the International Business Conduct
Policy and report periodically to the board thereon; and
(iii)
establish and oversee the procedures in the Code of Business Conduct and the
Company’s Whistleblower Policy to address:
A.
the receipt, retention and treatment of complaints received by the Company
regarding accounting, internal accounting controls or auditing matters; and
B.
confidential, anonymous submissions by employees of concerns regarding
questionable accounting and auditing matters.
Other Responsibilities
The Committee’s additional responsibilities to be defined as required, but may include:
(i)
monitoring compliance with the corporate code of conduct;
(ii)
investigating fraud, illegal acts or conflicts of interest;
(iii)
discussing selected issues with corporate counsel; and
(iv)
reviewing compliance with environmental codes of conduct and legislation.
A-4
(h)
Liaison with Other Financial Officer/Audit Committees of Subsidiary Companies
(i)
(i)
review the mandate and terms of reference of a subsidiary’s audit committee;
(ii)
review the financial report(s) of the subsidiary’s audit committee to its board of directors;
and
(iii)
follow-up, as appropriate, with management, the chairperson of the audit committee or
the audit partner of the subsidiary on any matters of concern.
Reporting
5.
(i)
report, through the chairperson, to the board following each meeting on the major
discussions and decisions made by the Committee;
(ii)
report annually, through the board, to the shareholders on the Committee’s
responsibilities and how it has discharged them; and
(iii)
review the Committee’s terms of reference annually and propose recommended changes
to the board.
REGULATIONS
(a)
The Committee shall have the power, authority and discretion delegated to it by the board
which shall not include the power to change the membership of or fill vacancies in the
Committee.
(b)
The Committee shall conform to the regulations which may from time to time be imposed
upon it by the board.
(c)
A resolution approved in writing by the members of the Committee shall be valid and
effective as if it had been passed at a duly called meeting. Such resolution shall be filed
with the minutes of the proceedings of the Committee and shall be effective on the date
stated thereon or on the latest date stated in any counterpart.
(d)
The board shall have the power at any time to revoke or override the authority given to or
acts done by the Committee except as to acts done before such revocation or act of
overriding and to terminate the appointment or change the membership of the Committee
or fill vacancies in it as it shall see fit.
(e)
The Committee shall have unrestricted and unfettered access to all Company personnel
and documents and shall be provided with the resources necessary to carry out its
responsibilities.
(f)
The Committee shall have the resources and authority appropriate to discharge its duties
and responsibilities, including the authority to:
A-5
(g)
(i)
engage independent counsel, or other advisors, as it determines necessary to
carry out its duties;
(ii)
to select and direct the payment of the compensation for any independent counsel
or other advisor engaged by the Committee; and
(iii)
to communicate directly with the internal and external auditors.
The Committee shall participate in an annual performance evaluation by the governance
and nominating committee, the results of which will be reviewed by the board.
A-6

annual information form

Transcription

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