AIF - Sprott Resource Corp.

SPROTT RESOURCE CORP.
Annual Information Form
March 29, 2012

TABLE OF CONTENTS
ABBREVIATIONS ........................................................................................................................................................ 1
CONVERSIONS ........................................................................................................................................................... 1
GENERAL INFORMATION .......................................................................................................................................... 2
SCIENTIFIC AND TECHNICAL INFORMATION ......................................................................................................... 2
FORWARD-LOOKING STATEMENTS ........................................................................................................................ 2
COMPANY OVERVIEW ............................................................................................................................................... 4
CORPORATE STRUCTURE ....................................................................................................................................... 5
Name, Address and Incorporation ................................................................................................................. 5
Intercorporate Relationships .......................................................................................................................... 6
CAPITAL STRUCTURE ............................................................................................................................................... 6
Common Shares ............................................................................................................................................ 7
Capital Structure of Subsidiaries .................................................................................................................... 7
GENERAL DEVELOPMENT OF THE BUSINESS ....................................................................................................... 8
Three-Year History ........................................................................................................................................ 8
ENERGY SEGMENT – WASECA AND OEOG.......................................................................................................... 12
Overview ...................................................................................................................................................... 12
Waseca ...................................................................................................................................................... 12
OEOG ...................................................................................................................................................... 12
Oil and Gas Industry Overview .................................................................................................................... 13
2012 Outlook ............................................................................................................................................... 17
AGRICULTURE SEGMENT - ONE EARTH FARMS ................................................................................................. 18
Overview of One Earth Farms ..................................................................................................................... 18
Farming Industry Overview .......................................................................................................................... 19
2012 Outlook ............................................................................................................................................... 22
CORPORATE SEGMENT .......................................................................................................................................... 23
Overview ...................................................................................................................................................... 23
Stonegate Agricom ...................................................................................................................................... 24
2012 Outlook ............................................................................................................................................... 24
RISK FACTORS ......................................................................................................................................................... 24
EMPLOYEES ............................................................................................................................................................. 43
ENVIRONMENTAL POLICY ...................................................................................................................................... 44
DIVIDENDS................................................................................................................................................................ 44
MARKET FOR SECURITIES ..................................................................................................................................... 44
DIRECTORS AND OFFICERS .................................................................................................................................. 45
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TABLE OF CONTENTS
(continued)
Page
Name, Occupation and Security Holdings ................................................................................................... 45
Cease Trade Orders, Bankruptcies, Penalties or Sanctions ........................................................................ 46
Conflicts of Interest ...................................................................................................................................... 48
AUDIT COMMITTEE INFORMATION ........................................................................................................................ 48
The Audit Committee’s Charter .................................................................................................................... 48
Composition of the Audit Committee............................................................................................................ 48
Relevant Education and Experience ............................................................................................................ 48
Pre-Approval Policies and Procedures ........................................................................................................ 49
External Auditor Service Fees (By Category) .............................................................................................. 49
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS .................................................... 50
TRANSFER AGENT AND REGISTRAR .................................................................................................................... 50
MATERIAL CONTRACTS .......................................................................................................................................... 50
Material Contracts Entered into During 2011 ............................................................................................... 50
INTERESTS OF EXPERTS ....................................................................................................................................... 52
Names and Interests of Experts ................................................................................................................... 52
ADDITIONAL INFORMATION.................................................................................................................................... 53
APPENDIX “A”
Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1)
APPENDIX “B”
APPENDIX “C”
Report on Reserves by McDaniel & Associates Consultants Ltd. – Waseca
(Form 51-101F2)
Report on Reserves by McDaniel & Associates Consultants Ltd. – OEOG
(Form 51-101F2)
APPENDIX “D” Report of Management and Directors on Oil and Gas Disclosure (Form 51-
101F3)
APPENDIX “E”
APPENDIX “F”
APPENDIX “G”
Mantaro Technical Report Summary
Paris Hills Technical Report Summary
Audit Committee Charter
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ABBREVIATIONS
Oil and Natural Gas Liquids
Natural Gas
bbl barrel Mcf thousand cubic feet
bbls barrels MMcf million cubic feet
Mbbls thousand barrels Mcf/d thousand cubic feet per day
bbls/d barrels per day MMcf/d million cubic feet per day
NGL natural gas liquids MMbtu millions of British thermal units
Other
AECO
API
°API
Boe
Boe/d
LT
MBoe
MM$
MMboe
SAGD
WTI
the natural gas storage facility located at Suffield, Alberta
American Petroleum Institute
an indication of the specific gravity of crude oil measured on the API gravity scale
barrels of oil equivalent of natural gas and crude oil on the basis of 1 Boe for 6 Mcf of
natural gas
barrel of oil equivalent per day
long ton
thousand barrels of oil equivalent
millions of dollars
million barrels of oil equivalent
Steam-Assisted Gravity Drainage
West Texas Intermediate, the reference price paid in United States dollars at Cushing,
Oklahoma for crude oil of standard grade
$ Canadian dollars
$000s thousands of Canadian dollars
Disclosure provided herein in respect of boe may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
CONVERSIONS
To Convert From To Multiply By
Mcf Cubic metres 28.174
Cubic metres Cubic feet 35.494
Bbls Cubic metres 0.159
Cubic metres Bbls oil 6.290
Feet Metres 0.305
Metres Feet 3.281
Miles Kilometres 1.609
Kilometres Miles 0.621
Acres Hectares 0.405
Hectares Acres 2.471
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GENERAL INFORMATION
This is the annual information form (“AIF”) for Sprott Resource Corp. (referred to in this AIF as the “Company” or “SRC”).
All amounts that are presented in this AIF are in Canadian dollars unless noted otherwise. The information in this AIF is
presented as at December 31, 2011 unless otherwise indicated.
SCIENTIFIC AND TECHNICAL INFORMATION
Technical information in this AIF relating to the Mantaro phosphate project (the “Mantaro Project”) is based on
information prepared by Donald H. Hains, P. Geo and Michelle Stone, P.Geo, Ph.d, each a “Qualified Person” as such
term is defined in National Instrument 43-101 – Standards of Disclosure for Mineral Projects (“NI 43-101”), and included in
the technical report filed in respect of the Mantaro Project on March 11, 2010 (the “Mantaro Technical Report”).
Technical information in this AIF relating to the Paris Hills phosphate project (the “Paris Hills Project”) is based on
information prepared by Leo J. Gilbride, P.E., Vanessa Santos, P.G., and Gary L. Skaggs, P.E., P.Eng, each an
independent consultant and “Qualified Person” as such term is defined in NI 43-101, and included in the technical report
filed in respect of the Paris Hills Project on March 29, 2012 (the “Paris Hills Technical Report”).
A “Qualified Person” means an individual who is an engineer or geoscientist with a university degree, or equivalent
accreditation, in an area of geosciences or engineering, relative to mineral exploration or mining, with at least five years of
experience in mineral exploration, mine development or operation or mineral project assessment, or any combination of
these, has experience relevant to the subject matter of the mineral project and the technical report, and is in good
standing of a professional association that is relevant to his or her professional degree or area of practice.
The Mantaro Technical Report and the Paris Hills Technical Report have been filed on SEDAR and can be found at
www.SEDAR.com. Readers are encouraged to read each report in its entirety.
FORWARD-LOOKING STATEMENTS
This AIF contains certain forward-looking statements and forward-looking information which are based upon the current
internal expectations, estimates, projections, assumptions and beliefs of the Company as of the date of such statements
or information, including, among other things, assumptions with respect to production, future capital expenditures, and
cash flows. The reader is cautioned that the assumptions used in the preparation of such information may be incorrect. In
some cases, words such as “plan”, “expect”, “project”, “intend”, “believe”, “anticipate”, “estimate”, “may”, “will”, “potential”,
“proposed” and other similar words, or statements that certain events or conditions “may” or “will” occur, are intended to
identify forward-looking statements and forward-looking information. These statements are not guarantees of future
performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or
events to differ materially from those anticipated in the forward-looking statements or forward-looking information. In
addition, this AIF may contain forward-looking statements and forward-looking information attributed to third-party industry
sources. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and
uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and
other forward-looking statements will not occur. Such forward-looking statements and forward-looking information in this
AIF speak only as of the date of this AIF unless an alternative date is otherwise expressly identified herein.
The forward-looking statements and the forward-looking information contained in this AIF are expressly qualified by the
cautionary statements provided for herein. The Company is not under any duty to update any of the forward-looking
statements or forward-looking information after the date of this AIF to conform such statements or information to actual
results or to changes in the expectations of the Company except as otherwise required by applicable securities laws.
Forward-looking statements and forward-looking information contained in this AIF include, but are not limited to,
statements with respect to:
• the use of funds available to the Company;
• drilling inventory, drilling plans and timing of drilling;
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• plans for facilities construction and completion or the timing and method of funding thereof;
• productive capacity of wells, anticipated or expected production rates and anticipated dates of
commencement of production;
• drilling, completion and facilities costs;
• results of various projects;
• cost structure of certain projects;
• growth expectations;
• timing of development of undeveloped oil and gas reserves;
• the tax horizon of the Company and its subsidiaries;
• the performance and characteristics of oil and natural gas properties;
• oil and natural gas production levels;
• the quantity of oil and natural gas reserves;
• capital expenditure programs and the timing and funding thereof;
• supply and demand for commodities and commodity prices;
• expected levels of royalty rates, operating costs, general and administrative costs, costs of services and
other costs and expenses;
• expectations relating to the ability to continually add, as applicable, to oil and gas reserves through
acquisitions, exploration and development;
• the quantity of mineral resources;
• expectations regarding the development of mineral resources;
• expectations regarding the growth in farmed acreage;
• expectations regarding improvements in crop farming and cattle program operating efficiencies;
• expectations regarding the development and growth of the cattle program;
• expectations regarding enhanced operational decisions and product traceability supported by the GIS
project;
• strategies regarding marketing and branding;
• treatment under governmental regulatory regimes and tax laws;
• the payment of dividends;
• conflicts of interest; and
• realization of the anticipated benefits of acquisitions and dispositions.
Although the Company believes that the expectations reflected in the forward-looking statements and forward-looking
information are reasonable, there can be no assurance that such expectations will prove to be correct. The Company
cannot guarantee future results, levels of activity, performance or achievements. Consequently, there is no representation
by the Company that actual results achieved will be the same in whole or in part as those set out in the forward-looking
statements and forward-looking information. Some of the risks and other factors, some of which are beyond the control of
the Company, that could cause results to differ materially from those expressed in the forward-looking statements and
forward-looking information contained in this AIF, include, but are not limited to:
• general economic conditions in Canada, the United States, Peru and globally;
• industry conditions, including fluctuations in the price of oil, natural gas and uranium, the price of
phosphate and the price of grains and cattle;
• liabilities inherent in oil and natural gas operations, mineral exploration and development, and farming
operations;
• governmental regulation of the oil and gas industry, the mining industry and the farming industry,
including environmental regulation and applicable tax and royalty regimes;
• geological, technical, drilling and processing problems and other difficulties in producing oil and gas
reserves;
• geological, technical, drilling and processing problems and other difficulties relating to the exploration and
development of phosphate rock;
• fluctuations in weather conditions or climate change;
• livestock disease or a decline in livestock fertility rates;
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• fluctuations in foreign exchange or interest rates;
• failure to realize anticipated benefits of acquisitions;
• unanticipated operating events which can reduce oil and gas production or cause production to be shut-in
or delayed;
• failure to obtain industry partner and other third-party consents and approvals, when required;
• stock market volatility and market valuations;
• competition for, among other things, capital, acquisitions of oil and gas reserves, undeveloped land and
skilled personnel;
• competition for and/or inability to retain drilling rigs and other services;
• the availability of capital on acceptable terms;
• the need to obtain required approvals from regulatory authorities; and
• the other “risk factors” disclosed in this AIF.
The foregoing list of factors should not be considered exhaustive. See also “Risk Factors” in this AIF. Statements relating
to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based
on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future.
With respect to forward-looking statements and forward-looking information contained in this AIF, the Company has made
assumptions regarding: future exchange rates; the price of gold bullion; energy markets and the price of oil, natural gas
liquids, natural gas and uranium; the grain market and the price of grains; the cattle market and the price of beef; the
phosphate market and the price of phosphate rock; the potash market and the price of potash; the market and services
rates for land-based contract drilling services; the impact of increasing competition in each business in which the
Company’s subsidiaries operate; conditions in general economic and financial markets; the availability of quality
management; availability of drilling and related equipment; availability of skilled labour; availability of qualified farming
personnel; the effects of regulation and tax laws of governmental agencies; future operating costs; and the ability to obtain
financing on acceptable terms.
The above summary of assumptions and risks related to forward-looking statements and forward-looking information has
been provided in this AIF in order to provide readers with a more complete perspective on the future operations of the
Company and its subsidiaries. Readers are cautioned that this information may not be appropriate for other purposes.
COMPANY OVERVIEW
The Company invests and operates, through its subsidiaries, in the natural resource sector. As at December 31, 2011,
the Company had three reportable segments: (i) the energy segment (the “Energy Segment”); (ii) the agriculture segment
(the “Agriculture Segment”); and (iii) the corporate and other segment (the “Corporate Segment”).
The Energy Segment includes the results and operations of Waseca Energy Inc. (“Waseca”) and One Earth Oil & Gas
Inc. (“OEOG” or “One Earth Oil & Gas”), in which the Company holds a 81.1% and 91.1% interest respectively. Waseca
and OEOG are referred to collectively in this AIF as the “Energy Subsidiaries” and each as an “Energy Subsidiary”.
Through the Energy Subsidiaries, the Company is involved in the exploration and production of oil and gas in Alberta,
Saskatchewan and Montana.
The Agriculture Segment includes the results and operations of One Earth Farms Corp. and its subsidiaries (“One Earth
Farms”), in which the Company holds a 58.1% interest. Through One Earth Farms, the Company farms on First Nations’
and privately leased farmland in the Canadian Prairie Provinces.
Each of Waseca, OEOG, and One Earth Farms is referred to in this AIF as a “Subsidiary” and collectively as the
“Subsidiaries”.
The Corporate Segment includes the Company’s ownership of gold bullion (73,971 ounces as at December 31, 2011),
cash and other short-term investments and securities of companies in the natural resource sector in respect of which the
Company’s interest is less than 50% (the “Minority Investments”). The Minority Investments held by the Company as at
December 31, 2011 include investments in WestFire Energy Ltd. (“WestFire”), Stonegate Agricom Ltd. (“Stonegate
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Agricom”), Guide Exploration Ltd. (“Guide”) (formerly Galleon Energy Inc.), Virginia Energy Resources, Union Agriculture
Group, Potash Ridge Corporation (“Potash Ridge”) and VA Uranium Holdings Inc. (“VAUH”) and, subsequent to
December 31, 2011, Independence Contract Drilling, Inc. (“ICD”). In respect of each of these Minority Investments, the
Company holds less than 20% of the voting shares outstanding, with the exception of Stonegate Agricom (32.5%) and
ICD (31.6%).
Name, Address and Incorporation
CORPORATE STRUCTURE
The Company was incorporated under the Canada Business Corporations Act as 3061213 Canada Inc. by articles of
incorporation dated August 19, 1994. By articles of amendment dated September 29, 1994, the Company changed its
name to General Minerals Corporation. By articles of amendment dated October 31, 1994, the Company amended its
authorized capital to create special shares as a new class of shares. By articles of amendment dated June 17, 2003, the
Company consolidated its issued and authorized common shares on a one-for-ten basis. By articles of amendment dated
August 31, 2007, the Company changed its name to Sprott Resource Corp. By articles of amendment dated June 3,
2008, the special class of shares created on October 31, 1994 was eliminated.
The Company’s registered office is 700-2nd Street S.W., Suite 1400, Calgary, Alberta, T2P 4V5. The head office is
located at Royal Bank Plaza, South Tower, 200 Bay Street, Suite 2750, Toronto, Ontario, M5J 2J2.
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Intercorporate Relationships
Included below is a diagram of the intercorporate relationships among the Company and its Subsidiaries as at December
31, 2011, indicating the percentage of votes attaching to all voting securities of the Subsidiary beneficially owned,
controlled or directed by the Company and where the Subsidiary was incorporated or continued.
CAPITAL STRUCTURE
The authorized capital of the Company consists of an unlimited number of common shares. The material provisions of the
common shares are summarized below.
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Common Shares
As at December 31, 2011, the Company had 112,636,810 issued and outstanding common shares. The holders of the
common shares are entitled to one vote per share at all meetings of shareholders of the Company. Each common share
entitles the holder thereof to receive any dividends, when and if declared by the directors of the Company, and to the
distribution of the residual assets of the Company in the event of the liquidation, dissolution or winding-up of the
Company.
Capital Structure of Subsidiaries
The capital structure for each Subsidiary as at December 31, 2011 is outlined in the following table:
Common Shares
Outstanding
Common Shares
Owned by SRC
Percentage
Ownership (undiluted)
of Votes attached to
all Securities of the
Subsidiary Owned or
over which Control or
Direction is Exercised
by the Company
OEOG Waseca
One Earth
Farms
18,994,000 90,806,181 103,186,778
17,300,000 73,632,240 60,000,000
91.1% 81.1% 58.1%
Equity Contributed by $17.3 million $44.2 million $57.5 million
SRC
Warrants Outstanding 873,110 10,935,420 Nil.
Warrants Owned by
Nil. 400,458 Nil.
SRC
Warrant Terms See Note 1 See Note 2 N/A
Stock Options
Outstanding
Stock Options Owned
by SRC
Stock Option Terms See Note 3
below
below
below
873,110 8,456,739 7,243,660
Nil. 600,000 250,000
See Note 4
below
See Note 5
below
(1) The warrants have a term of five years. They are convertible to common shares at $1.00 per warrant. In order to be convertible, there must
be (i) a liquidity event or public transaction in respect of OEOG and (ii) the transaction value of the common shares on the liquidity event or public
transaction must meet or exceed a set price. One-quarter vest at a transaction value per common share of at least $1.15. An additional one-quarter
vest at a transaction value per common share of at least $1.50. An additional one-quarter vest at a transaction value per common share of at least
$2.00. A final one-quarter vest at a transaction value per common share of at least $2.50.
(2) The warrants have a term of five years. They are convertible to common shares at $0.60 per warrant. In order to be convertible, there must
be (i) a liquidity event or public transaction in respect of Waseca and (ii) the transaction value of the common shares on the liquidity event or public
transaction must meet or exceed a set price. One-quarter vest at a transaction value per common share of at least $0.69. An additional one-quarter
vest at a transaction value per common share of at least $0.90. An additional one-quarter vest at a transaction value per common share of at least
$1.20. A final one-quarter vest at a transaction value per common share of at least $1.50.
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(3) The term, vesting period and exercise price of the options are determined at the discretion of One Earth Oil and Gas’ Board of Directors.
However, the maximum option term shall not exceed five years. As at December 31, 2011, 288,126 stock options were exercisable at $1.00 per
common share.
(4) Subject to any employment contracts, each outstanding option grant is exercisable as to 33 1/3% on a cumulative basis, at the end of each of
the first, second and third years following the date of grant. The maximum option term cannot exceed five years. As at December 31, 2011, 3,536,665
stock options were exercisable at $0.60 per common share and no stock options were exercisable at $0.75 per common share.
(5) Subject to any employment contracts, 33 1/3% of each option grant vests on a cumulative basis on the anniversary of the first, second and
third years following the date of grant and is exercisable upon a “liquidity event”. The maximum option term shall not exceed seven years, subject to
extension in the event that the expiry date falls within a “blackout” period. As at December 31, 2011, 1,704,373 options were vested but none of the
options were exercisable as there has not been a “liquidity event”.
GENERAL DEVELOPMENT OF THE BUSINESS
Up to September 5, 2007, the Company was an international mineral exploration company that acquired, explored and
developed mineral properties, primarily copper, gold and silver, in the United States and Mexico. The Company’s
strategic plan was to carry out in-house exploration with a focus on exploration for the discovery of copper, gold and silver
prospects. The Company’s strategy was to acquire such prospects and complete early stage exploration, following which
joint venture partners would be sought. In addition, the Company acquired majority interests in private companies run by
groups of entrepreneurial geologists in diverse geographic areas, such as Mongolia and Afghanistan.
On September 5, 2007, following a review of strategic alternatives by the Company to enhance shareholder value, and
after obtaining shareholder approval at a special meeting of shareholders, the Company entered into a management
services agreement (the “MSA”) with Sprott Consulting Ltd. (“SCL”), a then wholly-owned subsidiary of Sprott Asset
Management Inc. (“SAM”). SCL subsequently assigned the MSA to Sprott Consulting Limited Partnership (“SCLP”), the
successor to SCL, as part of an internal reorganization involving SAM and its subsidiaries.
As a result of the adoption of the MSA and a consequential change in the Company’s management, the Company’s
business changed. The Company now invests, and operates through its Subsidiaries, more broadly in the natural
resource sector.
On October 3, 2011, the Company completed a corporate reorganization to enable the Company to pursue its business
goals in a more efficient and effective manner (the “Reorganization”). As a result of the Reorganization, the Company
now invests and operates in the natural resource sector through Sprott Resource Partnership (the "Partnership"), a
partnership formed pursuant to an Amended and Restated Partnership Agreement between Sprott Resource Consulting
Limited Partnership ("SRCLP") and the Company (the “Partnership Agreement”). Substantially all of the holdings of the
Company were transferred to the Partnership in 2011.
In connection with the Reorganization, the Company’s Board of Directors and the general partner of SCLP approved
changes to the MSA and an amended and restated management services agreement between the Company and SCLP
(the “Amended and Restated MSA”) was entered into. The Reorganization did not alter the overall entitlement of SCLP
or its affiliates when compared to the prior MSA. Copies of the Amended and Restated MSA and Partnership Agreement
have been filed on SEDAR and can be found at www.SEDAR.com.
Three-Year History
The following is a summary of key events that have influenced the development of the Company over the last three
completed fiscal years:
2009
• On March 4, 2009, the Company announced that it had launched One Earth Farms. The Company invested
$27.5 million for 30 million units of One Earth Farms, with each unit entitling the Company to one common share
and one common share purchase warrant exercisable for $1 for a period of five years from the date of issuance.
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• On September 25, 2009, the Company entered into an agreement (the “Auriga Acquisition Agreement”) to
purchase, through a newly formed subsidiary later renamed Orion Oil and Gas Ltd. (“Orion Ltd.”), all of the
issued and outstanding shares of Auriga Energy Inc. (“Auriga”), a private oil and gas company operating in
Alberta (the “Auriga Acquisition”), by way of an exempt take-over bid. In conjunction with entering into the
Auriga Acquisition Agreement, the Company subscribed for 7,954,545 common shares of Orion Ltd. at $0.44 per
common share for $3.5 million and Orion Ltd. in turn subscribed for 7,954,545 common shares of Auriga at $0.44
per common share for $3.5 million.
The Auriga Acquisition closed on October 20, 2009. Under the terms of the Auriga Acquisition Agreement, each
shareholder of Auriga received 0.3 of an Orion Ltd. common share and 0.0979 of an SRC common share for each
Auriga common share held. A total of 13,853,097 SRC common shares and 42,449,848 Orion Ltd. common
shares were issued to Auriga shareholders. Concurrently with the closing of the Auriga Acquisition, the Company
subscribed for 122,330,162 common shares of Orion Ltd. as part of a $61.5 million private placement completed
by Orion Ltd. (the “Auriga Private Placement”). Immediately following the completion of the Auriga Acquisition
and the Auriga Private Placement, the Company owned 229,334,350 Orion Ltd. common shares out of a total of
289,226,766, being approximately 79% of the outstanding common shares on an undiluted basis.
In connection with the closing of the Auriga Acquisition, a total of 20,245,873 share purchase incentive warrants,
each exercisable for one Orion Ltd. common share at a price of $0.50 per share, were issued to new
management of Orion Ltd. (“Orion Ltd. Warrants”).
On December 23, 2009, the Company filed a Business Acquisition Report on SEDAR (www.SEDAR.com) in
respect of the Auriga Acquisition (Form 51-102F4).
• On November 26, 2009, Orion Ltd. signed an amalgamation agreement (the “Wintraysan Amalgamation
Agreement”) with Wintraysan Capital Corp. (“Wintraysan”) and a wholly-owned subsidiary of Wintraysan
(“Wintraysan SubCo”) pursuant to which Orion Ltd. agreed to amalgamate with Wintraysan Subco (the
“Wintraysan Amalgamation”). Orion Ltd. became a wholly-owned subsidiary of Wintraysan and was
subsequently amalgamated with Wintraysan. Wintraysan was renamed “Orion Oil & Gas Corporation” (“Orion”)
and began trading on the Toronto Stock Exchange (“TSX”). Orion Ltd. Warrants were converted into Orion
common share purchase warrants on a one for one basis.
• On December 22, 2009, One Earth Farms completed a $15 million financing pursuant to which it issued 15 million
common shares for $1 per common share. As the Company did not participate in this financing, the Company’s
ownership interest in One Earth Farms was diluted to 66.67% (undiluted).
• In 2009, the Company sold 1,783,013 ounces of silver bullion for $32.9 million (or $18.44 per ounce) and
purchased 33,496 additional ounces of gold bullion for a cost of $36.2 million (or $1,080 per ounce).
• During 2009, the Company repurchased and cancelled 2.9 million common shares under a normal course issuer
bid at an average cost of $3.86 per common share for a total cost of $11.2 million.
2010
• On January 11, 2010, Waseca completed an equity financing to existing shareholders. As part of the financing,
the Company purchased 28.34 million Waseca common shares at $0.60 per common share for a total cost of $17
million. As a result of the financing, the Company’s ownership interest in Waseca increased from 79.1% to 81.3%
on an undiluted basis.
• On April 28, 2010, Stonegate Agricom closed its initial public offering of 45 million units of Stonegate Agricom
(“Stonegate Units”) at a price of $1.00 per Stonegate Unit for gross proceeds of $45 million. Each Stonegate
Unit consisted of one common share and one-half common share purchase warrant. Each warrant entitles the
9

holder to acquire one Stonegate Agricom common share at an exercise price of $1.50 until April 28, 2013. The
Company purchased 12 million Stonegate Units on the initial public offering.
Stonegate Agricom granted the underwriters to the initial public offering an over-allotment option for 6.75 million
Stonegate Units, which was exercised in full and resulted in additional gross proceeds to Stonegate Agricom of
$6.75 million.
As a result of the completion of the Stonegate initial public offer and the exercise of the over-allotment option by
the underwriters, the Company’s ownership interest in Stonegate Agricom was reduced to 54% on an undiluted
basis.
• On December 21, 2010, the Company purchased 16.8 million common shares from the treasury of VAUH, a
private company in the United States with leasehold interests covering a uranium deposit. The VAUH shares
were purchased for $6 million total consideration. On December 21, 2010, the Company completed the purchase
of an additional 16.2 million common shares of VAUH from VAUH shareholders in exchange for 1.3 million
common shares of the Company. Upon completion of these purchases, the Company owned approximately 19%
of the outstanding common shares of VAUH.
• During 2010, 15.9 million warrants exercisable at $4.25, which were issued by the Company on July 7, 2008 as
part of a warrant incentive program, were exercised and 0.737 million warrants expired on December 31, 2010
unexercised.
• During 2010, the Company repurchased and cancelled 70 thousand common shares under a normal course
issuer bid at an average cost of $4.49 per common share for a total cost of approximately $0.3 million.
2011
• On February 4, 2011, the Company exercised its remaining 20 million One Earth Farms common share purchase
warrants, which increased its ownership in One Earth Farms to 80% and the invested capital to $57.5 million.
• On March 9, 2011, Stonegate Agricom closed its secondary offering of 25 million common shares of Stonegate
Agricom (“Stonegate Shares”) by the Company at a price of $1.75 per common share for aggregate gross
proceeds of $43,750,000 (the “Secondary Offering”). The Secondary Offering was completed by a syndicate of
underwriters.
As part of the Secondary Offering, the Company granted the underwriters an over-allotment option to purchase up
to an additional 3,750,000 Stonegate Shares from the Company at a price of $1.75 per Stonegate Share. On
April 6, 2011, the underwriters exercised the over-allotment option in full, resulting in gross proceeds to the
Company of $6,562,500.
After giving effect to the Secondary Offering and the exercise of the over-allotment option, the Company’s
ownership interest in Stonegate Agricom was reduced to approximately 33% on an undiluted basis.
• On March 17, 2011, One Earth Farms completed the first tranche of a $35 million private placement (the “One
Earth Private Placement”). The first tranche consisted of the issue and sale of 22,193,921 common shares at
$1.40 per share for aggregate gross proceeds of approximately $31.1 million. On May 2, 2011, One Earth Farms
completed the second tranche of the One Earth Private Placement, which consisted of the issuance and sale of
2,806,079 common shares, resulting in gross proceeds of approximately $3.9 million. In addition, the agent of the
One Earth Private Placement exercised its over-allotment option, resulting in the sale by One Earth Farms of a
further 3,186,778 common shares at a price of $1.40 per share for additional aggregate gross proceeds to One
Earth Farms of approximately $4.5 million. As a result of these transactions, the Company’s interest in One
Earth Farms was decreased to approximately 58.1% on an undiluted basis.
10

• On June 1, 2011, One Earth Farms completed its acquisition of a turn-key farming operation in central Alberta,
thereby acquiring approximately 29,500 acres of leased farmland with a weighted average lease duration of 2.5
years, along with $10.2 million of selected farm equipment, a building machine shop and two grain storage
elevators with a total capacity of 400,000 bushels.
• On June 30, 2011, Orion completed a strategic merger with WestFire pursuant to a plan of arrangement (the
“Arrangement”). Immediately upon completion of the Arrangement, Orion and WestFire amalgamated under the
Business Corporations Act (Alberta), continuing as “WestFire Energy Ltd.”. Pursuant to the Arrangement, for each
common share of Orion (an "Orion Share") held, Orion shareholders received at their election, either 0.125 of a
WestFire common share (a "WestFire Share") or 0.125 of a non-listed, non-voting convertible share (a "WestFire Non-
Voting Share"), which may be converted into a WestFire Share on a one for one basis in certain circumstances. The
0.125 exchange ratio reflects a deemed price of $8.00 per WestFire Share and $1.00 per Orion Share.
Prior to the completion of the Arrangement, the Company held 229,334,351 Orion Shares. In exchange for its
Orion Shares, the Company agreed to elect to receive 13,153,936 WestFire Shares, representing an ownership
interest of approximately 19.5%, and an aggregate of 15,512,858 WestFire Non-Voting Shares, representing
almost all of such shares. The Company recorded a pre-tax gain of $88.4 million as a result of the Arrangement.
The Company acquired the WestFire Shares and WestFire Non-Voting Shares for investment purposes. Subject
to the restrictions set forth in the Investor Agreement dated May 11, 2011 between WestFire and the Company, a
copy of which is available on SEDAR at www.SEDAR.com, the Company may purchase or sell securities of
WestFire in the future on the open market or in private transactions, depending on market conditions and other
factors material to the investment decisions of the Company.
• On October 1, 2011, the Company completed the Reorganization, as described above.
• On October 18, 2011, the Board of Directors of Waseca (the “Waseca Board”) initiated a process to identify,
examine and consider a range of strategic alternatives available to Waseca, with a view to maximizing
shareholder value. Over the course of the following two months, the Waseca Board considered corporate sale
proposals, proposals for a material portion of Waseca's assets and a corporate reorganization among other
alternatives. After careful analysis, consideration and advice from its financial advisor, the Waseca Board
concluded on December 19, 2011, that the most beneficial outcome for all shareholders is for Waseca to continue
to operate independently and pursue its existing business plan which has achieved significant organic production
growth.
• On December 19, 2011, the Board of Directors of WestFire decided to initiate a process to identify, examine and
consider a range of strategic alternatives available to WestFire with a view to enhancing shareholder value.
WestFire announced that these strategic alternatives may include, but are not limited to, a sale of all or a material
portion of the assets of WestFire, either in one transaction or in a series of transactions, the outright sale of
WestFire, or merger or other transaction involving WestFire and a third party.
• In the fourth quarter of 2011, and as announced on January 4, 2012, the Company invested $6.9 million in Potash
Ridge in a series of non-brokered private placements completed by Potash Ridge. As a result of its investment,
the Company owns approximately 19.9% of Potash Ridge. Potash Ridge is a private mineral resource company
focused on its two 100% owned alunite deposits in Utah named Blawn Mountain and Pine Valley. Alunite is a
mineral from which sulphate-of-potash (a high-grade potash), alumina and sulphuric acid can be extracted.
Potash Ridge is currently undertaking an extensive drilling program with funds raised from already completed
financings.
• During 2011, the Company purchased 15,519,477 common shares of Guide (the “Guide Shares”), which, based
on information contained in documents publically filed by Guide, represents approximately 16.8% of the total
issued and outstanding Guide Shares. The Guide Shares were acquired through the facilities of the TSX for an
average purchase price of $2.95 per Guide Share. The Company has acquired the common shares of Guide for
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investment purposes. The Company may purchase or sell securities of Guide in the future on the open market, in
private transactions or otherwise, depending on market conditions and other factors material to the investment
decisions of the Company.
• During 2011, the Company repurchased and cancelled 769,833 common shares under a normal course issuer bid
at an average cost of $4.16 per common share for a total cost of approximately $3.2 million.
2012
• On March 2, 2012, the Company completed an equity investment in ICD through a private placement in the
amount of US$50 million ($49.4 million). As at the date of the private placement, the Company's basic and diluted
ownership were 31.6% and 25.3%, respectively. ICD is a land drilling services provider and rig manufacturer
based in Houston, Texas, USA. Through its own fully staffed and integrated manufacturing facility located in
Houston, ICD will manufacture and contract for service programmable alternating current ("AC") rigs designed to
target longer-reach horizontal wells that are technically demanding and are more efficiently drilled by highspecification,
programmable AC rigs that precisely control and monitor the drilling operation and wellbore
geometry. These AC rigs have "walking" capability to allow the rig to be quickly moved to a new drilling location
on the pad without disassembling and reassembling the rig. Currently, approximately 20% of the U.S. rig fleet
features the programmable AC technology desired for unconventional drilling. The greater efficiency of
programmable AC rigs versus mechanical rigs and silicon controlled rectification rigs typically results in higher day
rates and operating margins for programmable AC rigs.
Overview
ENERGY SEGMENT – WASECA AND OEOG
The Energy Segment is comprised of the results and operations of Waseca and OEOG. A description of each Energy
Subsidiary is included below.
Revenue for the Energy Segment for 2011 (net of royalties) was $61.3 million, as compared to $77.2 million for 2010. In
addition, $42.6 million was recorded as discontinued operations for the three and six months ended June 30, 2011 and
$67.8 million was recorded as discontinued operations for the twelve months ended December 31, 2010, with respect to
the Orion Arrangement.
The Energy Segment had 37 employees. A breakdown of employees by Energy Subsidiary is included below.
OEOG, which is undertaking exploration activities in Montana, is the only Energy Subsidiary with operations outside of
Canada.
Waseca
Waseca is a private corporation engaged in the exploration and production of oil and gas in the Lloydminster area on the
border of Saskatchewan and Alberta. Waseca focuses its exploration and production on heavy oil. Waseca completed a
75 well (72.9 net) drilling program in 2011, which led to significantly increased production. Waseca's average production
increased 562 boe/day in 2010 to 2,214 boe/day in 2011. Waseca's exit volumes as at December 31, 2011 were
estimated to be 3,746 boe/day, up 258% from the December 31, 2010 exit rate of 1,046 boe/day.
OEOG
OEOG is a private corporation engaged in the exploration for oil and gas in Alberta and Montana, on and off First Nations’
land. OEOG commenced production operations in April 2011 and, as of December 31, 2011, OEOG’s average
production and exit volumes were approximately 255 boe/d and 366 boe/d respectively. As at December 31, 2011,
OEOG had 10 employees.
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Statement of Reserves Data and Other Oil and Gas Information
Attached as Appendices A to D are the following items:
APPENDIX “A”
Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1)
APPENDIX “B”
APPENDIX “C”
Report on Reserves by McDaniel & Associates Consultants Ltd. – Waseca
(Form 51-101F2)
Report on Reserves by McDaniel & Associates Consultants Ltd. – OEOG
(Form 51-101F2)
APPENDIX “D” Report of Management and Directors on Oil and Gas Disclosure (Form 51-
101F3)
Oil and Gas Industry Overview
The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land
tenure, exploration, development, production, refining, transportation, marketing, remediation, abandonment and
reclamation) imposed by legislation enacted by various levels of government, and with respect to pricing and taxation of
oil and natural gas, by agreements among the applicable federal, provincial, state or local governments, all of which
should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or
regulations will affect the Energy Subsidiaries’ operations in a manner materially different than they would affect other oil
and gas companies of similar size. All current legislation is a matter of public record and the Company is unable to predict
what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of
legislation, regulations and agreements governing the oil and gas industry in Canada.
Pricing and Marketing - Natural Gas
In Canada, natural gas is sold throughout the country at various market hubs that are connected to several pipelines
within Canada and the United States. The transaction price is determined by negotiation between buyers and sellers and
includes the utilization of electronic trading platforms and various publications and reference indexes. Prices depend on
many variables including but not limited to supply and demand fundamentals, the price of NYMEX natural gas contracts,
distance to alternative markets, pipeline costs, natural gas storage, competing fuels, contract terms, weather conditions
and foreign exchange rates. Natural gas exported from Canada is subject to regulation by the National Energy Board of
Canada (the “NEB”) and the Government of Canada. The price received for natural gas that is exported depends largely
on the same variables noted above including the market hub prices at the delivery end of the export pipelines. Exporters
are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet
certain other criteria prescribed by the NEB and the Government of Canada. As in the case with oil, natural gas exports
for a term of less than two years or for a term of 2 to 20 years (in quantities of not more than 30,000 cubic metres per
day), must be made pursuant to a NEB order. Any natural gas export to be made pursuant to a contract of longer duration
(to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the
issuance of such license requires the approval of the Governor in Council.
The governments in the Canadian provinces where the Energy Subsidiaries operate also regulate the removal of natural
gas from those provinces for consumption elsewhere based on such factors as reserve availability, transportation
arrangements and market considerations.
Pricing and Marketing - Oil
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market
determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in
part on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand
balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not
exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order
approving such export has been obtained from the NEB. Any oil export to be made pursuant to a contract of longer
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duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of
such licence requires a public hearing and the approval of the Governor in Council.
Pipeline Capacity
As a result of recent pipeline additions and expansions, an excess of natural gas pipeline capacity exists in western
Canada, which provides for the ability to deliver all current production to natural gas sales markets.
Currently, there are some concerns with respect to whether the oil pipeline capacity on the inter-provincial pipeline
systems is sufficient. There exists the possibility of apportioning pipeline space amongst shippers and this may affect the
ability to market oil production.
The North American Free Trade Agreement
The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States of America,
and Mexico became effective on January 1, 1994. In the context of energy resources, Canada continues to remain free to
determine whether exports of energy resources to the United States of America or Mexico will be allowed, provided that
any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon
the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price
subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii)
disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import
price requirements, provided, in the case of export price requirements, any prohibition in any circumstances in which any
other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not
apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory
border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair
implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue
interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.
Provincial Royalties and Incentives
In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties,
production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability
of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other
than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from
such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation
and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally
depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of
recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from
time to time, carved out of the working interest owner’s interest through non-public transactions. These are often referred
to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.
Occasionally the governments of the western Canadian provinces create incentive programs for exploration and
development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally
introduced when commodity prices are low. The programs are designed to encourage exploration and development
activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount
of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and
funds from operations of such producers.
Land Tenure
Crude oil and natural gas located in the western Canadian provinces is owned predominantly by the respective provincial
governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases,
14

licences, and permits for varying periods, and on conditions set forth in provincial legislation including requirements to
perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and
rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be
negotiated.
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation pursuant to a variety of provincial and federal
legislation. Such legislation provides for environmental protection and applies restrictions and prohibitions regarding
disturbances and releases or emissions of various substances produced or utilized in association with certain oil and gas
industry operations. In addition, such legislation requires that well, pipeline and facility sites be abandoned and reclaimed
to the satisfaction of provincial authorities. Environmental laws may impose remediation obligations with respect to a
property designated as a contaminated site upon certain responsible persons, which include persons responsible for the
substance causing the contamination, persons who caused release of the substance and any past or present owner,
tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures
and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil
liability for pollution damage, the issuance of clean-up orders and the imposition of material fines and penalties.
Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and
Enhancement Act (Alberta) (the “EPEA”), which came into force on September 1, 1993, and the Oil and Gas
Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose certain environmental standards, reporting and
monitoring obligations, responsibilities and penalties which may be significant for violations. In 2006, the Alberta
Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions
from industrial operations including the oil and gas industry. In addition, the reduction emission guidelines outlined in the
Climate Change and Emissions Management Amendment Act came into effect on July 1, 2007 (“CCEMAA”). Under this
legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions
intensity by 12 percent. Industries have three options to choose from in order to meet the reduction requirements outlined
in this legislation: (i) make improvements to operations that result in reductions; (ii) purchase emission credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions; or
(iii) contribute to the Climate Change and Emissions Management Fund (the “Fund”). Industries can either choose one of
these options or a combination thereof. Pursuant to CCEMAA and the Specified Gas Emitters Regulation, companies
were obliged to reduce their emission intensity by 12 percent by March 31, 2008. It is reasonably likely that the trend
towards stricter standards in environmental legislation and regulation will continue.
On January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta’s
projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and
storage, which will be mandatory for in situ oil sand facilities that use heavy fuels for steam generation; (ii) energy
conservation and efficiency; and (iii) greening production through increased investment in clean energy technology,
including supporting research on new oil sands extraction processes, as well as the funding of projects that reduce the
cost of separating CO 2 from other emissions. In addition to this action plan, the Provincial Energy Strategy unveiled on
December 11, 2008 is expected to, among other things, support the upgrading, refining and petrochemical clusters
existing in the Province, market Alberta's energy internationally, review the emission targets and carbon charges applied
to large facilities, and promote the innovation of energy technology by encouraging investment in research and
development.
In December 2002, the Government of Canada ratified the Kyoto Protocol (“Protocol”). The Protocol called for Canada to
reduce its greenhouse gas emissions to 6 percent below 1990 “business-as-usual” levels between 2008 and 2012. Bill C-
288, which was intended to ensure that Canada meets its global climate change obligations under the Protocol, was
passed by the House of Commons on February 14, 2007. On December 12, 2011, Canada formally withdrew from the
Protocol opting to keep in line with U.S. action in pursuing a regulatory approach that would impose sector by sector rules.
On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the
“Action Plan”) also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan
covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a
number of energy using products.
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The Government of Canada and the Province of Alberta released the final report of the Canada-Alberta ecoENERGY
Carbon Capture and Storage Task Force on January 31, 2008, which recommends among others: (i) incorporating carbon
capture and storage into Canada’s clean air regulations; (ii) allocating new funding into projects through competitive
process; and (iii) targeting research to lower the cost of technology.
In order to strengthen the Action Plan, on March 10, 2008, the Government of Canada released “Turning the Corner –
Taking Action to Fight Climate Change” (the “Updated Action Plan”) which provides some additional guidance with
respect to the Government’s plan to reduce greenhouse gas emissions by 20 percent by 2020 and by 60 to 70 percent by
2050.
The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the
oil sands, oil and gas and refining industries. The Updated Action Plan is intended to create a carbon emissions trading
market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a market price
for carbon. There are mandatory reductions of 18 percent from the 2006 baseline starting in 2010 and an additional 2
percent in subsequent years for existing facilities. This target will be applied to regulated sectors on a facility-specific,
sector-wide or corporate basis; in the case of oils sands production, petroleum refining, natural gas pipelines and
upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex and diverse,
or where emissions are affected by factors beyond the control of the facility operator). Emissions from new facilities, which
are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage continuous emissions
intensity reductions over time, and will be granted a three year grace period during which no emissions intensity targets
will apply. Targets will begin to apply on the fourth year of commercial operation and the baseline will be the third year's
emissions intensity, with a two percent continuous annual emission intensity improvement required. The definition of new
facility also includes greenfield facilities, major expansions constituting more than a 25 percent increase in a facility’s
physical capacity, as well as transformations to a facility that involve significant changes to its processes. For upstream oil
and gas and natural gas pipelines, it will be applied using a sector-specific approach. For the oil sands, its application will
be process-specific; oil sands plants built in 2012 and later and those which use heavier hydrocarbons, up-graders and insitu
production will have mandatory standards in 2018 that will be based on carbon capture and storage.
In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum annual
emissions threshold: (i) 50,000 tonnes of carbon dioxide equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of
CO 2 equivalent per upstream oil and gas facilities; and (iii) 10,000 boe/d/company. These proposed thresholds are
significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO 2 equivalent per year per facility.
Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions,
offset credits, clean development credits and credits for early action. The most significant of these compliance
mechanisms, at least initially, will be the Technology Fund, in which regulated entities will be able to contribute in order to
comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 per tonne for
the 2010-12 period, rising to $20 per tonne in 2013, and thereafter increasing at the nominal rate of GDP growth.
Contribution limits will correspondingly decline from 70 percent in 2010 to zero percent in 2018. Monies raised through
contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions.
Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at
the same contribution rate and under similar requirements as mentioned above.
The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing
non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits,
project proponents must propose and receive approval for emissions reduction activities that will be verified before offset
credits will be issued to the project proponent. Such credits can then be sold to regulated entities for use in compliance or
non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale.
Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean
Development Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits will be restricted to
10 percent of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink
projects will not be available for use in complying with the Canadian regulations.
16

Finally, a one-time credit of up to 15 metric tonnes worth of emissions credits will be awarded to regulated entities for
emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.
Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting
requirements, it is not currently possible to predict.
Subsequent to the International Climate Change meeting in Copenhagen in December 2009 the governments of the
United States and Canada committed to a 17% reduction in greenhouse gas emissions by 2020 relative to a 2005
baseline. The Government of Canada is working towards this target on a sector by sector basis but has yet to finalize
regulations pertaining to the oil and gas sector. A recent report from the National Roundtable on the Environment and
Economy (2011) has recommended short-term actions for Canada to develop a national cap and trade program and to
eventually link with a North American cap and trade system if the U.S. eventually develops and implements its own cap
and trade system. However, as the Canadian federal government continues to seek to align its greenhouse gas
regulations with those of the United States, it is unclear whether the Canadian federal government will pursue any shortterm
actions and therefore its regulations remain pending.
The Company believes that the Energy Subsidiaries are, and expects that the Energy Subsidiaries will continue to be, in
material compliance with applicable environmental laws and regulations and is committed to the Energy Subsidiaries
meeting their responsibilities to protect the environment wherever the Energy Subsidiaries operate or hold working
interests. The Company anticipates that this compliance may result in increased expenditures of both a capital and
expense nature as a result of increasingly stringent laws relating to the protection of the environment. The Company
believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter
standards.
Trends
An important trend that appears to be shaping the near future of the oil and gas industry is the volatility of commodity
prices. Natural gas is a commodity influenced by factors within North America and liquefied natural gas imports. A tight
supply/demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels
tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all
factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility. Crude oil is
influenced by, among other things, the world economy, Organization of the Petroleum Exporting Countries’ (“OPEC”)
ability to adjust supply to world demand, political circumstances and weather. Crude oil prices have been kept high by
political events causing disruptions in the supply of oil and concern over potential supply disruptions triggered by unrest in
the Middle East. Political events trigger large fluctuations in price levels in crude oil.
The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices,
producers generate sufficient cash flows to conduct active exploration programs without the need for external capital.
Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for
their services. The cost of purchasing land and properties similarly increases in price during these periods. During low
commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and
development activities. With decreased demand, the prices charged by the various service suppliers also decline.
2012 Outlook
Waseca
For 2012, Waseca has a sixty well drilling program planned and will continue to evaluate upcoming crown land sales and
potential production acquisition opportunities. Waseca management estimates that the 2012 drilling program should result
in a December 31, 2012 exit rate of production between 4,600 boe/day and 5,000 boe/day. Actual results are dependent
on a variety of factors including: number of wells drilled in 2012; timing of drilling; weather; success rates; and production
rates on future and existing wells.
17

One Earth Oil and Gas
OEOG will focus on developing liquids rich gas and oil prospects in 2012. The company will utilize the three townships of
3D seismic data that cover its existing land holdings to add to the drilling inventory, currently at 18 locations. The oil and
liquids rich gas locations have been prioritized for drilling in 2012. Subject to surface access and regulatory approvals,
OEOG expects to drill up to four wells in the first half of 2012. The four locations have been identified as having the
highest probability of encountering oil in the drilling inventory. OEOG will delay drilling dry gas targets until suitable prices
are obtainable in the market-place.
One Earth Oil and Gas continues to look for new oil and gas opportunities in Western Canada and the United States,
including advancing land development negotiations with First Nations and other aboriginal groups.
Except as required under contractual agreements, exploration drilling in northern Montana will be deferred as OEOG
determines the most economic approach in the region.
Overview of One Earth Farms
AGRICULTURE SEGMENT - ONE EARTH FARMS
One Earth Farms is a large grain and cattle farming business operating in the Prairie Provinces. Its first year of
operations was 2009. As at December 31, 2011, One Earth Farms had 71 full and part time employees and 60 seasonal
employees still on payroll to perform necessary year end farm operations. It had revenues of $18.5 million in 2011, as
compared to $7.9 million in 2010.
One Earth Farms became the largest farm in Canada in 2011, growing its total crop and pasture acres under
management to 103 thousand acres (of which 91 thousand acres were planted) and 68 thousand acres (excluding custom
grazing arrangements) (of which 35 thousand acres were planted) respectively. In addition, total livestock was increased
to 13,703 from 3,620 as at December 31, 2010.
In 2011, One Earth Farms farmed approximately 91 thousand acres of cultivated land under lease and custom farmed an
additional 10 thousand acres. Custom farmed acres are acres that One Earth Farms manages for a fee, which may or
may not include a profit share in the products grown. The other land farmed in 2011 consisted of First Nations reserve
land, which One Earth Farms leased from eleven First Nations, and private land. The crops produced in 2011, as a
percentage of acres planted, were canola (41%), wheat (35%), malt and feed barely (18%), flax seed (5%) and other
crops (1%). In total, One Earth Farms produced 87,720 gross tonnes (85,288 net tonnes) of grain product during 2011.
As discussed below (see “Agriculture Segment: One Earth Farms - Farming Industry Overview – Farmland
Ownership/Leasing Restrictions”), there are provincial legislative restrictions in each of Alberta, Saskatchewan and
Manitoba, which, to varying degrees, restrict One Earth Farms from owning or leasing non-First Nations farmland. Due to
these legislative restrictions, One Earth Farms’ operations are principally on First Nations’ farmland. First Nations
farmland is federally regulated and therefore not subject to these provincial legislative restrictions.
All of the farmland leased by One Earth Farms was farmland that was already being farmed by other parties. The First
Nations with which One Earth Farms has entered leases are electing to lease the farmland to One Earth Farms for job
participation, market rate leases, possible equity ownership and the opportunity to partner with One Earth Farms on
ancillary business opportunities relating to primary agriculture, such as storage and trucking.
The Company believes that One Earth Farms represents an opportunity to change primary farming in Canada.
Management believes that once sufficient scale is realized, One Earth Farms will be able to achieve improved equipment
utilization, input purchasing power and improved pricing for final products, which management expects will generate
greater operating margins and more profitability than the average farm in the Canadian Prairie Provinces.
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Farming Industry Overview
The Crop Farming Process
Crop farming in Canada has historically been a cyclical industry, subject to profit volatility due to weather, varying crop
yields, pricing volatility and other sources of uncertainty. Other challenges include high financing costs, family related
issues, equipment utilization, management capabilities and a high level of investment in working capital. More recently,
however, government programs and crop insurance have materially reduced downside potential.
Crops grown by One Earth Farms fall into three main categories: grains, oilseeds and specialty crops.
Grains: Grains include wheat, corn, barley, oats and rye and are used primarily for human consumption and livestock
feed. Other uses include ethanol, biodiesel, biodegradable plastics, cosmetics, hand cleaners, soap, dog and cat
products, shampoo and a variety of pharmaceutical products.
Oilseeds: Oilseeds consist of canola, soybean, flax seed, safflower and sunflower seeds and are used in the production
of cooking oils, margarine and livestock feed. Other uses include paint, plastics and fuel.
Specialty Crops: Specialty crops include pulse crops such as chickpeas, dry beans, dry peas and lentils, as well as
canary seed, mustard seed, buckwheat, and forages.
While each type of crop has its own unique growing requirements, the primary production cycle on the Prairies typically
spans from early spring to late fall. Storage, marketing and planning activities occur all year round but represent the
primary activities during the winter months. The whole cycle for each crop can generally be represented by the following
five stages: (i) planting (Apr-May); (ii) growth (May-Sept); (iii) harvest (Aug-Oct); (iv) storage (Aug-July); and (v) marketing
(year-round).
Planting
The planting phase includes land preparation and seeding. Adopting a low-till or no–till strategy is the environmentally
and economically preferred approach, reducing carbon emissions, soil erosion, diesel fuel use and operating costs.
Growth
The growth phase includes fertilization, watering and crop protection. Fertilization is key for achieving a high yield and
growing a high quality crop. Fertilization may be achieved using organic fertilizer, inorganic fertilizer or some combination
of both depending on the crop. Organic fertilizer generally refers to naturally occurring compounds (plant or animal
matter) and may include animal manure, peat or naturally occurring mineral deposits. Inorganic fertilizers are generally
those fertilizers manufactured through a variety of chemical processes or from naturally occurring deposits that have been
chemically altered. The use of fertilizer can improve the health of plants and the productivity of soil by providing essential
nutrients.
A key component of yield maximization is controlling weeds which utilize resources that would otherwise be available for
crops. Different crops and weed varieties may require tailored herbicide solutions while timing and method of herbicide
application will be dependent on the specific product being used. Generally, herbicides are applied repeatedly and
accompanied with water.
One Earth Farms’ lands under management in 2011 included crops produced with the support of irrigation. Irrigation is an
artificial application of water to the soil which assists in the growing of crops. In crop production it is mainly used in dry
areas and in periods of rainfall shortfalls. When economically feasible, irrigation brings stability to agricultural production
and increases land productivity, although the cost of leasing irrigated land is substantially higher than dry land.
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Harvest
Harvest times vary depending upon the crop variety, degree of crop maturity and the risk of potential weather
complications. Frost can result in significant harm to a crop as ice forms and causes molecular damage. Frost damaged
crops will show signs of injury including discoloration, darkening, water soaked appearance, etc.
Harvesting techniques will vary depending upon the crop being grown. In many instances, specialized equipment such as
combines are used to harvest large acreages of crops, including wheat, oats, rye, barley, corn, soybeans and flax.
Storage
Grain is typically stored in rigid containers, silos or grain elevators for up to 12 months. Storing grain allows the producer
to realize greater selling prices by delaying the time of sale until market prices are attractive, rather than selling directly off
the field.
Marketing
Based in Winnipeg, Manitoba, the Canadian Wheat Board (“CWB”) is a farmer-controlled organization that had a
monopoly on all sales of western Canadian wheat, durum and barley for human consumption (“Board Grains”).
The CWB controlled the pricing as well as the flow and timing of wheat and barley deliveries into the elevator system by
issuing contract calls to the producers. The flow of shipments to port terminals was also determined by the CWB through
its management of rail logistics.
On December 15, 2011, royal assent was given to Bill C-18, which established the Marketing Freedom for Grain Farmers
Act (the “Grain Marketing Act”). The Grain Marketing Act ended the CWB’s monopoly on all sales of Board Grains,
allowing farmers to market their crops independently or through the CWB. An application for an injunction to suspend the
Grain Marketing Act brought by eight former CWB directors before the Manitoba Court of Queen’s Bench was dismissed
on February 24, 2012.
Canadian farmers sell their non-board grains and oilseeds directly to grain handling companies and processors (e.g., nonmilling
varieties of wheat, feed barley, canola, oats, flax, peas) in the open market. The dollar value of non-board grains
and oilseeds marketed in Canada account for more than half of all sales.
Supply Chain Dynamics
The Canadian supply chain for grain is dominated by large multinational players who, unlike primary producers, have
undergone a period of significant consolidation and international expansion. As a result, large scale input providers, grain
handlers and processors exhibit considerable pricing power within the domestic supply chain and internationally.
Comparatively small primary producers are unable to buy or sell in sufficient quantities to increase their negotiating power
and are therefore predominantly price-takers. While the CWB offers some of the benefits of scale in the sale of Board
Grains, primary producers selling non-board grains have little negotiating leverage. Whether selling board or non-board
grains, primary producers of grain without significant scale have a limited ability to reduce costs through negotiation with
much larger input providers.
The Cattle Program
Similar to crop farming, cattle ranching in Canada has historically been a cyclical industry, subject to profit volatility
primarily due to pricing volatility and other sources of uncertainty. Other challenges include high financing costs, family
related issues, management capabilities, animal health management and a high level of investment in working capital.
More recently, however, government programs have materially reduced downside potential.
The term ‘cattle’ broadly refers to cows (mature females who have given birth to one calf), mature bulls (greater than one
year of age), yearling bulls (one year of age), replacement heifers (one to two year old females being bred to give birth to
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a calf), heifer calves (less than one year old) and steer calves (castrated male calves less than one year old). There are
many different breeds of cattle with the most common being: black Angus, red Angus, Hereford, Simmental, Charolais,
Shorthorn and Limousin.
The following chronological listing of events in the cattle cycle portrays the process from genetic selection through to beef
processing. Below are the associated critical events for each phase, several of which overlap.
Seedstock Genetic Selection
The seedstock selection phase occurs from six months to one year prior to the breeding phase. The critical events are
bull and heifer calf retention decisions. At this stage, the calves are immature and not capable of breeding, requiring one
year of additional development to transform into a productive asset. As an alternative to selecting breeding stock from
within the cattle herd, breeding stock can be acquired at any age from other cattle ranches. The key selection criteria
typically are animals with a low birth weight, high rate of gain after birth and good feed efficiency.
Breeding Phase
Typically in early to mid-summer, one year old heifers and the mature cows will be bred naturally or through artificial
insemination. This phase typically lasts for 45 to 60 days, during which the females are comingled with the bulls.
Throughout this phase, the cows and bulls are located on grass in large, open fields which minimizes the incidence of
sickness and provides the appropriate nutrition. The cattle are checked on a regular basis to ensure the bulls remain in
productive health. This management practice reduces the risk of the cows not becoming pregnant.
Gestation
The gestation phase of the cow following breeding lasts for approximately 283 days until the calf is born. During this time
period the cow’s nutrition requirements change as the unborn calf grows. During this phase the cows continue to remain
on open fields of grass until the snow covers the ground. At that point in time, the cows are then fed other sources of feed
such as hay, yet remain out in the large fields where there is adequate shelter for the winter.
Calving
The calving phase for One Earth Farms starts in April with the majority of the calves born by the end of May. During this
phase, the cows are predominantly calving on the open grass fields which provides a low stress environment. The open
fields also help aid in reducing the incidence of sickness in the newborn calves as they are not forced into close contact
with the other cattle. Key factors to reduce the death loss during this phase are maintaining the cows in a strong, healthy
condition through exercise by walking to water and proper nutrition, periodic checking of the cows to aid them as
necessary while giving birth, and providing large fields to reduce the incidence of sickness.
Cow/Calf Pairs
During this phase, the cow and calf remain together on grass for approximately 210 to 240 days from the time the calf is
born. As the calf grows it starts to balance its diet between the cow’s milk and grass.
Key management factors to minimize the risk of death loss and poor animal condition are ensuring adequate grass,
quality water, and early detection of sickness followed with an appropriate treatment. One Earth Farms follows a hormone
and antibiotic-free protocol, typically referred to as a natural beef protocol, for its cattle. Through genetic selection, low
stress cattle handling systems, proactive management of herd health protocols and a predominantly forage (e.g.
grass/hay) feed ration, this management system is providing the ability to operate under the natural protocols which
results in price premiums for One Earth Farms’ animals and beef.
This phase also overlaps with the seedstock selection, breeding and gestation phases.
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Weaning
The weaning phase occurs in the late fall to early winter time period. This is the time when the calf is weaned from the
cow. At this point in time the calf no longer relies on the cow’s milk for its nutrition.
At this time, the calf can be retained or sold to third parties for feeding for beef production or as genetic seedstock. If the
calves are sold, they can be marketed into the cash market or sold through forward sales contracts for delivery at a later
date. Cattle price insurance programs are available to mitigate price risk during this phase.
Key management factors required to minimize the risk of death loss during the weaning phase are ensuring a low stress
environment, large open fields to minimize incidence of sickness, adequate nutrition and access to good quality water.
Feeder Cattle On-Feed
The feeder cattle on-feed phase refers to the time period during which calves are fed to the weight required to be
processed into beef for consumers. During this phase, calves can enter different feeding programs depending upon the
consumer-end market desired. Examples of this are a predominantly forage ration for the grass-fed beef market or a
feedlot ration predominantly comprised of grain for the typical commercial market. Depending upon the requirements of
the retailer, feeder cattle under natural protocols can go through either of the programs noted above.
Feeder cattle are sold through either spot cash sales or forward contracts for future delivery.
Farmland Ownership/Leasing Restrictions
In Manitoba, the ownership and leasing of farmland is regulated by The Farm Lands Ownership Act. In Saskatchewan,
the regulating legislation is the Saskatchewan Farm Security Act. In Alberta, the regulating legislation is the Agricultural
and Recreational Land Ownership Act. In general, the legislation in Manitoba and Saskatchewan restricts entities with
non-resident shareholders, or entities that are themselves publicly traded or have shareholders that are publicly traded,
from owning or leasing more than a de minimis amount of farmland in the applicable province. In Alberta, the legislation is
less strict. Leasing by non-residents, or entities with non-resident ownership, is permitted for a period of up to 20 years.
In general, ownership of farmland is permitted provided the entity is not owned by a majority of non-residents, as
determined under the legislation.
First Nations Land Leasing Process
Under the Indian Act (Canada) (the “Indian Act”), there are two mechanisms by which One Earth Farms, or any other
private farmer, may obtain an interest in reserve land: (i) a permit issued under the Indian Act (an “INAC Permit”) by the
Minister of Indian and Northern Affairs (the “Minister”); or (ii) a lease granted by the Minister. Private lease agreements
between an individual or corporation and a band are not enforceable, although they are common.
Seasonality
Revenues for One Earth Farms are predominantly earned in the third and fourth quarters of the Company’s fiscal year
and correspond to the harvesting of crops in the Prairie Provinces.
2012 Outlook
For 2012, One Earth Farms anticipates planting approximately 100,000 acres on leased land in Alberta and
Saskatchewan. The planned crops are canola, wheat, malt barley, feed barley, field peas, oats and flax seed. Corn is
expected to be planted in two regions to determine the economics and synergies with the cattle operation.
To continue One Earth Farms’ positive progress in 2012, One Earth Farms needs to ensure the retention of the
appropriate number of fully trained seasonal crews, maintain the appropriate level and structure of management, continue
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to acquire leases on productive land and successfully implement the standard operating procedures. Farming will always
have a component of uncontrollable influences, most of which are related to weather.
One Earth Farms currently has cattle being finished for market under two existing natural and one organic beef brands.
The information obtained through these marketing initiatives will enable One Earth Farms to further develop its marketing
strategy in 2012. Future success of the cattle operations will depend on One Earth Farms' ability to grow the size of its
high quality genetic herd, continue to develop its grass fed, natural protocols, and generate premium revenue.
A GIS project was initiated to provide high resolution satellite imagery on all leased lands. This information will provide
greater accuracy on acres farmed and will form a platform to support enhanced operational decisions and product
traceability. When combined with One Earth Farms' proprietary operations data tracking technology, the completed
system will provide for real-time traceability of all production inputs and crop and livestock grown on the farm.
Overview
CORPORATE SEGMENT
The Corporate Segment includes the Company’s ownership of gold bullion, cash and other short-term investments and
securities of companies in the natural resource sector in respect of which the Company owns less than 50%.
The following is a summary of the principal assets that comprise the Corporate Segment and their values as set out in the
Company’s audited financial statements as at December 31, 2011:
($ in
Asset
thousands)
Cash and Cash Equivalents 15,336
Gold Bullion 117,582
Investment in Stonegate Agricom 17,273
Public Securities 214,903
Investment in WestFire 162,541
Investment in Guide 48,731
Other 3,631
Private Securities 63,886
The Company’s gold bullion is held in the vaults of a Canadian chartered bank in Toronto.
Private and public securities are securities of companies of which the Company owns less than 20% of the outstanding
voting shares. The private securities include the Company’s ownership interest in VAUH, a private company in the United
States with leasehold interests covering a uranium deposit; and Union Agriculture Group (“UAG”), which is focused on
acquiring and farming farmland in Uruguay. The Company has invested $28.7 million in UAG and, according to
information filed by UAG, holds approximately 8.7% of the issued and outstanding shares. The public securities include
the Company’s ownership interest in WestFire, which is engaged in the acquisition, development and production of crude
oil and natural gas in Western Canada; and Guide, an intermediate oil and natural gas company in Western Canada. The
Company has invested $105.9 million and $45.7 million in WestFire and Guide, respectively. According to publically filed
documents, the Company holds approximately 34.5% of the issued and outstanding shares of WestFire (voting and nonvoting)
and 16.8% of the issued and outstanding shares of Guide. The Company’s interest in private and public securities
are accounted for as available for sale and, other than Stonegate Agricom which is accounted for using the equity
method, are marked to market at each balance sheet date.
The Company’s Corporate Segment had no revenues during the past two years. It had 41 employees (including
employees of Stonegate Agricom) as at December 31, 2011.
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Stonegate Agricom
Stonegate Agricom is engaged in the business of acquiring, exploring and developing agricultural nutrient projects and is
currently focused on the exploration and development of the Mantaro Project and the Paris Hills Project. As at December
31, 2011, Stonegate Agricom had 31 employees.
Technical Summary of the Mantaro Project and the Paris Hills Project
Mantaro Project
Attached as Appendix “E” is the summary from the Mantaro Technical Report, which report is incorporated into this AIF by
reference. The Mantaro Technical Report is available on SEDAR under the Company’s profile at www.SEDAR.com.
Readers are encouraged to read the Mantaro Technical Report in its entirety.
Paris Hills Project
Attached as Appendix “F” is the summary from the Paris Hills Technical Report, which report is incorporated into this AIF
by reference. The Paris Hills Technical Report is available on SEDAR under the Company’s profile at www.SEDAR.com.
Readers are encouraged to read the Paris Hills Technical Report in its entirety.
2012 Outlook
Corporate Segment
The Company continues to look for assets and/or companies at attractive valuations that, over the long term, will prove to
be profitable to the Company.
Stonegate Agricom
Stonegate Agricom is continuing to work on developing the Mantaro Project and the Paris Hills Project. A pre-feasibility
study was completed in March 2012 in respect of the Paris Hills Project, the results of which are contained in the Paris
Hills Technical Report. It is expected that a bankable feasibility study of the Paris Hills Project will be completed by the
end of 2012. With respect to the Mantaro Project, work will continue on securing the permits and community approvals
required to conduct a broad exploration program.
RISK FACTORS
There are risks associated with owning common shares of the Company that holders should carefully consider.
The risks and uncertainties below are not the only risks and uncertainties facing the Company, its Subsidiaries or Minority
Investments. Additional risks and uncertainties not presently known to the Company or that the Company currently
considers immaterial may also impair the business, operations and future prospects of the Company, its Subsidiaries or
Minority Investments and cause the price of the Company’s common shares to decline. If any of the following risks
actually occur, the business of the Company, its Subsidiaries or Minority Investments, as applicable, may be harmed and
its financial condition and results of operations may suffer significantly. In that event, the trading price of the Company’s
common shares could decline, and holders of the Company’s common shares may lose all or part of their investment. In
addition to the risks described elsewhere and the other information contained in this AIF, holders of common shares of the
Company should carefully consider each of, and the cumulative effect of all of, the following risk factors.
Risks Relating to the Energy Segment
Volatility in Oil and Natural Gas Prices
The Energy Subsidiaries’ results of operations and financial condition are dependent on the prices the Energy
Subsidiaries receive for the oil and natural gas (and related products) they produce and sell. Oil and natural gas prices
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have fluctuated widely during recent years and may continue to be volatile in the future. Oil and natural gas prices may
fluctuate in response to a variety of factors beyond the Energy Subsidiaries’ control, including:
• global energy supply, production and policy, including the ability of OPEC to set and maintain production
levels in order to seek to influence prices for oil;
• political conditions, including the risk of hostilities in the Middle East and global terrorism;
• global and domestic economic conditions;
• the level of consumer demand;
• the supply and price of imported oil and liquefied natural gas;
• the production and storage levels of North American natural gas and the supply and price of imported and
liquefied natural gas;
• currency fluctuations;
• weather conditions;
• the price and availability of alternative fuels;
• the proximity of reserves and resources to, and capacity of, transportation facilities;
• the availability of refining capacity;
• the effect of world-wide energy conservation measures and greenhouse gas reduction measures; and
• government regulations.
Any decline in crude oil or natural gas prices may have a material adverse effect on the Energy Subsidiaries’ operations,
financial condition, borrowing ability, levels of reserves and the level of expenditures for the development of the Energy
Subsidiaries’ oil and natural gas reserves. Certain oil or natural gas wells may become uneconomic to produce if market
conditions deteriorate, thereby impacting the Energy Subsidiaries’ production volumes.
The Company or its Energy Subsidiaries may use financial derivative instruments and other hedging mechanisms to try to
limit a portion of the adverse effects resulting from volatility in natural gas and oil commodity prices. To the extent the
Company or its Energy Subsidiaries hedge their commodity price exposure, they may forego the benefits they would
otherwise experience if commodity prices were to increase. In addition, these commodity price hedging activities could
expose the Company or its Energy Subsidiaries to losses which could occur in various circumstances, including if the
counterparty to a hedging agreement does not perform its obligations. See “Risk Factors - Risks Relating to the Energy
Segment - Counterparty Risk” below.
Fluctuations in Foreign Currency Exchange Rates
The price that the Energy Subsidiaries receive for a majority of their oil and natural gas is based on United States dollar
denominated benchmarks, and therefore the price that the Energy Subsidiaries receive in Canadian dollars is affected by
the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the
United States dollar will negatively impact the Energy Subsidiaries’ net production revenue by decreasing the Canadian
dollars the Energy Subsidiaries receive for a given sale in United States dollars while offering limited relief to the Energy
Subsidiaries’ cost structures, as a majority of their costs are incurred in Canadian dollars.
Inability to Add or Develop Additional Reserves
The Energy Subsidiaries add to their oil and natural gas reserves primarily through acquisitions and ongoing development
of reserves, together with certain exploration activities. As a result, the level of the Energy Subsidiaries’ future oil and
natural gas reserves are highly dependent on their success in developing and exploiting their reserve and resource bases
and acquiring additional reserves through purchases or exploration. Exploration and development risks arise for the
Energy Subsidiaries and may affect the value of the Company’s common shares, due to the uncertain results of searching
for and producing oil and natural gas using imperfect scientific methods. Additionally, if capital from external sources is not
available or is not available on commercially advantageous terms, the Energy Subsidiaries’ ability to make the necessary
capital investments to maintain, develop or expand their oil and natural gas reserves will be impaired. Even if the
necessary capital is available, the Energy Subsidiaries cannot assure that they will be successful in acquiring additional
reserves on terms that meet their investment objectives. Without these additions, the Energy Subsidiaries’ reserves will
25

deplete and, as a consequence, either their production or the average life of its reserves will decline. Either decline may
result in a reduction in the value of the Company’s common shares.
Actual Reserves will Vary from Reserve Estimates
The value of the Company’s common shares depends upon, among other things, the reserves attributable to the Energy
Subsidiaries’ properties. The actual reserves contained in the Energy Subsidiaries’ properties will vary from the estimates
summarized in this AIF and those variations could be material. Estimates of reserves are by necessity projections, and
thus are inherently uncertain. The process of estimating reserves requires interpretations and judgements on the part of
petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different
engineers may make different estimates of reserve or resource quantities and revenues attributable thereto based on the
same data. Ultimately, actual reserves attributable to the Energy Subsidiaries’ properties will vary and be revised from
current estimates, and those variations and revisions may be material. The reserve information contained in this AIF is
only an estimate. A number of factors are considered and a number of assumptions are made when estimating reserves.
These factors and assumptions include, among others:
• historical production in the area compared with production rates from similar producing areas;
• future commodity prices, production and development costs, royalties and capital expenditures;
• initial production rates;
• production decline rates;
• ultimate recovery of reserves;
• success of future exploitation activities;
• marketability of production; and
• the effects of government regulation and other government levies that may be imposed over the
producing life of reserves.
Reserve estimates are based on the relevant factors, assumptions and prices on the date the evaluations were prepared.
Many of these factors are subject to change and are beyond the Energy Subsidiaries’ control. If these factors,
assumptions and prices prove to be inaccurate, the Energy Subsidiaries’ actual reserves could vary materially from their
estimates. Additionally, all such estimates are, to some degree, uncertain, and classifications of reserves are only
attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas, the classification of such reserves based on risk of recovery and associated
contingencies, and the estimates of future net revenues expected therefrom, prepared by different engineers or by the
same engineers at different times, may vary substantially.
Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric or
probabilistic calculations and upon analogy to similar types of reserves, rather than upon actual production history.
Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent
evaluation of the same reserves based upon production history may result in variations or revisions in the estimated
reserves, and any such variations or revisions could be material. Reserve estimates may require revision based on actual
production experience. Such figures have been determined based upon assumed oil, natural gas and natural gas liquid
prices and operating costs. Market price fluctuations of commodity prices may render uneconomic the recovery of certain
categories of oil or natural gas. Moreover, short term factors may impair the economic viability of certain reserves in any
particular period.
An Increase in Operating Costs or a Decline in Production Level
Higher operating costs for the Energy Subsidiaries’ properties will directly decrease the amount of cash flow received by
the Energy Subsidiaries and, therefore, may reduce the value of the Company’s common shares. Electricity, chemicals,
supplies, energy services and labour costs are a few of the Energy Subsidiaries’ operating costs that are susceptible to
material fluctuation. The level of production from the Energy Subsidiaries’ existing properties may decline at rates greater
than anticipated due to unforeseen circumstances, many of which are beyond the Company’s and Energy Subsidiaries’
control. Higher operating costs or a significant decline in production could result in materially lower revenues and cash
flow and, therefore, could reduce the value of the Company’s common shares.
26

Counterparty Risk
The Energy Subsidiaries are subject to the risk that the counterparties to their risk management contracts, marketing
arrangements and operating agreements and other suppliers of products and services may default on their obligations
under such agreements or arrangements, including as a result of liquidity requirements or insolvency. A failure by such
counterparties to make payments or perform their operational or other obligations to the Energy Subsidiaries may
adversely affect their results of operations, cash flows and financial position and therefore may reduce the value of the
Company’s common shares.
General Energy Segment Risk
The business and operations of the Energy Subsidiaries, including the drilling of oil and natural gas wells and the
production and transportation of oil and natural gas, are subject to certain risks inherent in the oil and natural gas
business. These risks and hazards include encountering unexpected formations or pressures, blow-outs, craterings and
fires. The Energy Subsidiaries’ operations may also subject them to the risk of vandalism or terrorist threats including ecoterrorism.
The foregoing hazards could result in personal injury, loss of life, reduced production volumes or environmental
and other damage to the Energy Subsidiaries’ property and the property of others. The Energy Subsidiaries cannot fully
protect against all of these risks, nor are all of these risks insurable. Although the Energy Subsidiaries carry liability,
business interruption and property insurance in respect of such matters, there can be no assurance that insurance will be
adequate to cover all losses resulting from such events or that the lost production will be restored in a timely manner. The
Energy Subsidiaries may become liable for damages arising from these events against which they cannot insure or
against which they may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair
damages or pay liabilities would reduce the value of the Company’s common shares.
The Properties and Assets acquired in the Future will be Subject to Operational Risks
The risk factors set forth in this AIF relating to the Energy Subsidiaries, their operations and reserves apply equally in
respect of any future properties or assets that the Company, the Energy Subsidiaries or any future subsidiary of the
Company may acquire. The Company and Energy Subsidiaries generally conduct certain due diligence in connection with
acquisitions, but there can be no assurance that the Company or Energy Subsidiaries, as applicable, will identify all of the
potential risks and liabilities related to the subject properties.
Inability to Compete Successfully with other Organizations in the Oil and Natural Gas Industry
The oil and natural gas industry is highly competitive. The Energy Subsidiaries compete for capital, acquisitions of
reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to
processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other
organizations, many of which may have greater technical and financial resources than the Energy Subsidiaries. Some of
these organizations not only explore for, develop and produce oil and natural gas but also conduct refining operations and
market oil and other products on a world-wide basis. As a result of these complementary activities, some competitors may
have greater and more diverse competitive resources to draw upon.
Environmental Claims and Liability
The oil and natural gas industry is subject to extensive environmental regulation pursuant to local, provincial and federal
legislation in Canada. A breach of that legislation may result in the imposition of fines or the issuance of ‘‘clean up’’
orders. Legislation regulating the Energy Subsidiaries’ industry may be changed to impose higher standards and
potentially more costly obligations, such as legislation that would require significant reductions in greenhouse gas
emissions. See ‘‘Energy Segment: Waseca and OEOG – Oil and Gas Industry Overview – Environmental Regulation’’ for
a summary of certain proposals. Although the actual form such legislation or regulation may take is largely unknown at
this time, the implementation of more stringent environmental legislation or regulatory requirements may result in
additional costs for oil and natural gas producers such as the Energy Subsidiaries, and such costs may be significant,
which may negatively impact the trading price or value of the Company’s common shares.
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The Energy Subsidiaries are not fully insured against certain environmental risks, either because such insurance is not
available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring
over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.
Accordingly, the Energy Subsidiaries’ properties may be subject to liability due to hazards that cannot be insured against,
or that have not been insured against due to prohibitive premium costs or for other reasons.
The Energy Subsidiaries do not establish a separate reclamation fund for the purpose of funding their estimated future
environmental and reclamation obligations. The Company cannot assure investors that the Energy Subsidiaries will be
able to satisfy their future environmental and reclamation obligations. Any site reclamation or abandonment costs incurred
in the ordinary course, in a specific period, will be funded out of cash flows. Should an Energy Subsidiary be unable to
fully fund the cost of remedying an environmental claim, such Energy Subsidiary might be required to suspend operations
or enter into interim compliance measures pending completion of the required remedy.
Government Regulations and Required Regulatory Approvals
The oil and gas industry operates under federal, provincial and municipal legislation and regulation governing such
matters as land tenure; prices; royalties; production rates; environmental protection controls; well and facility design and
operation; income; exportation of crude oil, natural gas and other products; and other matters. The industry is also subject
to regulation by governments in such matters as the awarding or acquisition of exploration and production rights; the
imposition of specific drilling obligations; environmental protection controls; control over the development and
abandonment of fields and mine sites (including restrictions on production); and possibly expropriation or cancellation of
contract rights. See ‘‘Energy Segment: Waseca and OEOG - Oil and Gas Industry Overview’’.
To the extent that the Energy Subsidiaries fail to comply with applicable government regulations or regulatory approvals,
they may be subject to fines, enforcement proceedings (including ‘‘enforcement ladders’’ with varying penalties) and the
restriction or complete revocation of rights to conduct their business, or to apply for regulatory approvals necessary to
conduct their business, in the ordinary course. Government regulations may be changed from time to time in response to
economic or political conditions. Additionally, the adoption of new technology by the Energy Subsidiaries may attract
additional regulatory oversight which could result in higher costs or require changes to proposed operations. For example,
Canadian regulatory bodies have enhanced their oversight of and reporting obligations associated with fracturing
procedures. The exercise of discretion by governmental authorities under existing regulations, the implementation of new
regulations or the modification of existing regulations affecting the crude oil and natural gas industry could negatively
impact the development of oil and gas properties and assets, reduce demand for crude oil and natural gas, increase the
Energy Subsidiaries’ costs, any of which have a material adverse impact on the Energy Subsidiaries and therefore the
value of the Company’s common shares. Additionally, various levels of Canadian and United States governments have
implemented, or are considering, legislation to reduce emissions of greenhouse gases. See ‘‘Energy Segment: Waseca
and OEOG – Oil and Gas Industry Overview – Environmental Regulation’’ for a description of these initiatives. Because
the Energy Subsidiaries’ operations emit various types of greenhouse gases, such new legislation or regulation could
increase the costs related to operating and maintaining the Energy Subsidiaries’ facilities and could require one or more
them to install new emission controls on their facilities, acquire allowances for their greenhouse gas emissions, pay taxes
related to their greenhouse gas emissions and administer and manage a greenhouse gas emissions program. The
Company is not able at this time to estimate such increased costs; however, they could be significant. Any of the
foregoing could have adverse effects on the Energy Subsidiaries’ business, financial position, results of operations and
prospects and as a result adversely affect the Company's common shares.
Decline in Ability to Market Oil and Natural Gas Production
The Energy Subsidiaries’ business depends in part upon the availability, proximity and capacity of oil and natural gas
gathering systems, pipelines and processing facilities to provide access to markets for their production. Canadian federal
and provincial regulation of oil and gas production, processing and transportation, tax and energy policies, general
economic conditions, and changes in supply and demand could adversely affect the Energy Subsidiaries’ ability to
produce and market oil and natural gas.
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Lower Oil and Gas Prices Increase the Risk of Write-Downs
Under International Financial Reporting Standards (“IFRS”), when indicators of impairment exist, the carrying value of the
Exploration and Evaluation (‘‘E&E’’) assets as well as each Cash Generating Unit (‘‘CGU’’), including goodwill attributed to
the CGU, is compared to its recoverable amount. The recoverable amount is defined as the higher of the fair value less
cost to sell or value in use. A decline in oil and gas prices may be an indicator of CGU impairment and may result in the
estimated recoverable amount of an Energy Subsidiaries’ developed oil and natural gas properties being less than their
carrying value on the balance sheet, resulting in a write-down of the CGU assets. While these write-downs would not
affect cash flow from operations, the charge to earnings may be viewed unfavourably in the market. Impairments to
goodwill and E&E assets are not reversed, however should the conditions that caused the CGU asset impairment reverse
in the future the Company would be required to reverse all, or a portion of the impairment previously recorded.
Unforeseen Title Defects
The Company or the Energy Subsidiaries, as applicable, conduct title reviews in certain circumstances in accordance with
industry practice prior to purchases of assets. However, if conducted, these reviews do not guarantee that an unforeseen
defect in the chain of title will not arise and defeat title to the purchased assets. If this type of defect were to occur, the
Energy Subsidiaries’ entitlement to the production and reserves (and, if applicable, resources) from the purchased assets
could be jeopardized. Furthermore, from time to time, the Energy Subsidiaries may have disputes with industry partners
as to ownership rights of certain properties or resources, including with respect to the validity of oil and gas leases held by
the Energy Subsidiaries. Furthermore, from time to time, the Energy Subsidiaries or their industry partners may owe one
another a contractual or trust related obligation which they may default in satisfying and which may adversely effect the
validity of an oil and gas lease in which the either of the Energy Subsidiaries has an interest. The existence of title defects,
unsatisfied contractual or trust related obligations or the resolution of any disputes with industry partners arising from
same, may have a material adverse effect on the Energy Subsidiaries or their assets and operations and as a result
adversely affect the value of the Company’s common shares.
Risks Relating to the Agriculture Segment – One Earth Farms
Limited Operating History
One Earth Farms has a limited history of operations and is still in the early stage of development. As such, One Earth
Farms is subject to many risks common to such enterprises, including under-capitalization, cash shortages, limitations
with respect to personnel, financial and other resources and lack of revenue. There is no assurance that One Earth
Farms will be successful in achieving a return on shareholders’ investment and the likelihood of success must be
considered in light of its early stage of operations.
The Availability of Land for Growth may be Limited
One Earth Farms’ growth strategy may be constrained in the event that it is unable to secure a large amount of acreage.
One Earth Farms’ current strategy is contingent upon securing a significant amount of new acreage each year to drive
economies of scale. One Earth Farms’ business model is reliant on a high degree of lease renewals. It is possible that
certain parties may not wish to renew land lease agreements at the conclusion of the lease term. One Earth Farms may
suffer certain inefficiencies if it has made investments in infrastructure close to leased properties for which leases are not
renewed. In addition, the optimal process for securing leases is through an INAC Permit. While some bands are currently
following this process, other bands are not. Consequently, some of the leases currently under negotiation and/or signed
are contingent on the band pursuing an INAC Permit or land designation process leading to a lease granted by the
Minister and it cannot be guaranteed that such bands will achieve the internal approval for this to occur. Without an INAC
Permit or a lease granted by the Minister, the legal remedies available to One Earth Farms are limited in the event of a
breach of contract.
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Regulatory Changes
There have been many developments in the Canadian agriculture industry over the past number of years. Public opinion
with respect to corporate farms may place pressure on regulatory bodies to stimulate small farm investment and/or deter
corporate farming initiatives. There is a risk that future changes to the laws and regulations affecting One Earth Farms
could have a negative impact on One Earth Farms’ business, financial condition and results of operations.
Lack of Qualified Personnel
One Earth Farms’ performance depends to a significant extent on its ability to attract and retain highly qualified and skilled
management personnel with farming expertise. The loss of key persons or the inability to recruit appropriate personnel
could have a negative impact on One Earth Farms’ performance. In addition, One Earth Farms will need to hire and
retain qualified employees to work in various operational positions. The inability to fill such positions with qualified
personnel could have a negative impact on One Earth Farms’ business and operational results.
Poor Weather Conditions
Poor weather conditions or climate change may adversely affect One Earth Farms’ operational results. The success of
grain operations is highly dependent on favourable weather conditions during the growing season. In particular, a lack of
adequate rainfall, extremely high moisture levels, or incidents of frost may adversely affect crop yield and therefore
revenue and operational results. One Earth Farms intends to insure its crops against such weather risks and mitigate its
risk through geographical diversification. However, insurance coverage and geographical diversification may not
completely mitigate the negative impact of poor weather conditions.
A Drop in Pricing for Agricultural Commodities Produced and Sold by One Earth Farms
The price of agricultural commodities are subject to wide fluctuations due to unpredictable factors such as weather,
planting intentions, government farm programs and policies, changes in global demand and changes in global production.
One Earth Farms has limited ability to influence price levels for its products and it is therefore subject to changes in price
levels. Adverse changes in price levels for commodities One Earth Farms sells may adversely impact One Earth Farms’
business, financial condition and operational results.
A Rise in the Price of Inputs used by One Earth Farms
Profitability in the farming industry is subject to significant input price volatility. One Earth Farms is susceptible to
significant input cost uncertainty, which may adversely impact One Earth Farms’ business, financial condition and
operational results.
Livestock Disease
One Earth Farms has cattle operations. Cattle are vulnerable to viral infections and other diseases and there can be no
assurance that One Earth Farm’s livestock will not be infected. A serious outbreak of disease amongst One Earth Farms’
cattle may result in losses or costs, and have a negative impact on One Earth Farms’ reputation, which could adversely
affect One Earth Farms’ business, financial condition and operational results. In addition, an outbreak of such disease in
the cattle industry generally, even if it does not directly infect One Earth Farms’ cattle, could impact the cattle industry
negatively and result in losses which could adversely affect One Earth Farms’ business, financial condition and
operational results.
Livestock Fertility Rates
One Earth Farms’ cattle operations is largely dependent on maintaining adequate fertility rates amongst its cows. A
significant decrease in fertility rates amongst One Earth Farms’ cows may lead to a decrease in the herd size and the
quantity of beef and cattle for sale and, consequently, may adversely affect One Earth Farms’ business, financial
condition and operational results.
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Risks Relating to Interest in Stonegate Agricom
Commodity Prices
The profitability of Stonegate Agricom’s operations will be dependent upon the market price of phosphate rock. Mineral
prices fluctuate widely and are affected by numerous factors beyond the control of Stonegate Agricom. The level of
interest rates, the rate of inflation, global and regional consumption patterns, the world supply of and demand for mineral
commodities and the stability of exchange rates can all cause significant fluctuations in prices. Such external economic
factors are in turn influenced by changes in international investment patterns, monetary systems and political
developments. The effect of these factors cannot be accurately predicted. The price of mineral commodities has
fluctuated widely in recent years and future price declines could cause commercial production to be impracticable, thereby
having a material adverse effect on Stonegate Agricom’s business and financial condition.
In addition to adversely affecting Stonegate Agricom’s mineral resource estimates and its financial condition, declining
commodity prices can impact operations by requiring a reassessment of the feasibility of a particular project. Such a
reassessment may be the result of a management decision or may be required under financing arrangements related to a
particular project. Even if the project is ultimately determined to be economically viable, the need to conduct such a
reassessment may cause substantial delays or may interrupt operations until the reassessment can be completed.
The profitability of Stonegate Agricom’s mineral properties will also be dependent on the costs of consumables used in its
operations. Profitability will be impacted by the cost of such consumables including fuel, energy, steel and other products
required to be used in future operations.
Current Global Financial Conditions
Financial markets globally have been subject to increased volatility. Access to financing has been negatively impacted by
liquidity crises and uncertainty with respect to sovereign defaults throughout the world. These factors may impact the
ability of Stonegate Agricom to secure financing in the future and, if obtained, on terms favourable to Stonegate Agricom.
Although there has been an improvement in market conditions since late 2009, if these levels of volatility and market
turmoil continue, Stonegate Agricom may not be able to secure appropriate debt or equity financing, any of which could
affect the trading price of Stonegate Agricom’s securities in an adverse manner.
Stonegate Agricom is also exposed to liquidity risk in the event its cash positions decline or become inaccessible for any
reason, or additional financing is required to advance its projects or growth strategy and appropriate financing is
unavailable, or demand for phosphate falls. Any of these factors may impact the ability of Stonegate Agricom to obtain
further equity based funding, loans and other credit facilities in the future and, if obtained, on terms favourable to
Stonegate Agricom.
Uncertainty of Additional Capital
The exploration and development of Stonegate Agricom’s properties, including continuing exploration and development
projects, the construction of mining facilities and commencement of mining operations and the growth of Stonegate
Agricom, will require substantial additional financing. Stonegate Agricom has limited financial resources and has no
source of operating income. Failure to obtain sufficient financing could result in a delay or indefinite postponement of
exploration, development or production on any or all of Stonegate Agricom’s properties or even a loss of a property
interest. An important source of funds available to Stonegate Agricom is through the sale of equity capital, properties,
royalty interests or the entering into of joint ventures. Additional financing may not be available when needed or, if
available, the terms of such financing might not be favourable to Stonegate Agricom and might involve substantial dilution
to existing shareholders. Failure to raise capital when needed would have a material adverse effect on Stonegate
Agricom’s business, financial condition and results of operations and ability to grow.
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Price Volatility
Securities of mining companies have experienced substantial volatility in the past, often based on factors unrelated to the
financial performance or prospects of the companies involved. These factors include macroeconomic developments in
North America and globally, and market perceptions of the attractiveness of particular industries. As a result of any of
these factors, the market price of the securities of Stonegate Agricom at any given point in time may be subject to market
trends and macroeconomic conditions generally, notwithstanding any potential success of Stonegate Agricom in creating
revenues, cash flows or earnings and may not accurately reflect the long-term value of Stonegate Agricom. There can be
no assurance that continual fluctuations in price will not occur.
The Mantaro Project and the Paris Hill Project are Advanced Exploration Stage Projects
The Mantaro Project and the Paris Hills Project are both in the advanced exploration stage. There is no certainty that the
expenditures made by Stonegate Agricom towards the search and evaluation of mineral deposits on either of these
properties will result in discoveries of commercial quantities of ore. Furthermore, unless Stonegate Agricom acquires
additional properties or projects, any adverse developments affecting these projects or Stonegate Agricom’s rights to
develop mining concessions or other rights that are held on these properties, could materially adversely affect Stonegate
Agricom’s business, financial condition and results of operations.
Limited Operating History
Stonegate Agricom has a very limited history of operations and is in the early stage of development. As such, Stonegate
Agricom is subject to many risks common to such enterprises, including under-capitalization, cash shortages, limitations
with respect to personnel, financial and other resources and the lack of revenue. There is no assurance that Stonegate
Agricom will be successful in achieving a return on shareholders’ investment and the likelihood of success must be
considered in light of its early stage of operations.
No History of Earnings
Stonegate Agricom has limited financial resources, has earned nominal revenue since commencing operations, has no
source of operating cash flow and there is no assurance that additional funding will be available to it for exploration and
development. Furthermore, additional financing will be required to continue the development of Stonegate Agricom’s
properties even if Stonegate Agricom’s exploration program is successful. There can be no assurance that Stonegate
Agricom will be able to obtain adequate financing in the future or that the terms of such financing will be favourable.
Failure to obtain such additional financing could result in delay or indefinite postponement of further exploration and
development of Stonegate Agricom’s properties with the possible loss of such properties.
Government Regulation of the Mining Industry
The current and future operations of Stonegate Agricom, from exploration through development activities and commercial
production, if any, are and will be governed by laws and regulations governing mineral concession acquisition and
retention, prospecting, development, mining, production, exports, taxes, labour standards, occupational health, waste
disposal, toxic substances management, land use, environmental protection, mine safety and other matters. Companies
engaged in exploration activities and in the development and operation of mines and related facilities may experience
increased costs and delays in production and other schedules as a result of the need to comply with applicable laws,
regulations and approvals and authorizations. Approvals and authorizations are subject to the discretion of government
authorities and there can be no assurance that Stonegate Agricom will be successful in obtaining all required approvals.
Amendments to current laws and regulations governing the operations and activities of Stonegate Agricom or more
stringent implementation thereof could have a material adverse effect on Stonegate Agricom’s business, financial
condition and design and results of operations. Further, there can be no assurance that all approvals required for future
exploration, construction of mining facilities, associated ancillary facilities and to operate these facilities will be obtainable
on reasonable terms or on a timely basis, or that such laws and regulations would not have an adverse effect on any
project which Stonegate Agricom may undertake.
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Failure to comply with applicable laws, regulations and permits may result in enforcement actions thereunder, including
the forfeiture of claims, orders issued by regulatory or judicial authorities requiring operations to cease or be curtailed,
and may include corrective and mitigation measures requiring capital and operational expenditures, installation of
additional equipment or costly remedial actions. Stonegate Agricom may be required to compensate those suffering loss
or damage by reason of its mineral exploration activities and may have civil or criminal fines or penalties imposed for
violations of such laws, regulations and permits. Stonegate Agricom is not currently covered by any form of environmental
liability insurance. See “Risk Factors - Risks Relating to Interest in Stonegate Agricom - Insurance and Uninsured Risks”.
Existing and possible future laws, regulations and permits governing operations and activities of exploration companies, or
more stringent implementation thereof, could have a material adverse impact on Stonegate Agricom and cause increases
in capital expenditures or require abandonment or delays in exploration.
Changes, if any, in mining or investment policies or shifts in political attitude in Peru may adversely affect Stonegate
Agricom’s operations or profitability. Operations may be affected in varying degrees by government regulations with
respect to, but not limited to, restrictions on production, price controls, export controls, currency remittance, income taxes,
expropriation of property, foreign investment, maintenance of claims, environmental legislation, land use, land claims of
local people, water use and mine safety.
Failure to comply strictly with applicable laws, regulations and local practices relating to mineral rights applications and
tenure could result in loss, reduction or expropriation of entitlements, or the imposition of additional local or foreign parties
as joint venture partners with varied or other interests. The occurrence of these various factors and uncertainties cannot
be accurately predicted and could have an adverse effect on Stonegate Agricom’s business, financial condition and
results of operations.
Environmental Risks and Hazards
All phases of Stonegate Agricom’s operations are subject to environmental regulations in the various jurisdictions in which
it operates including but not limited to the maintenance of air and water quality, land reclamation, environmental pollution
and the generation of transportable storage and disposal of hazardous and nonhazardous wastes. Environmental
legislation is evolving in a manner that may require stricter effluent and emission standards and enforcement, increased
fines and penalties for non-compliance, more stringent environmental assessments processes and a heightened degree
of responsibility for companies and their officers, directors and employees. There is no assurance that existing or future
environmental regulation will not materially adversely affect Stonegate Agricom’s business, financial condition and results
of operations. Environmental hazards may exist on the properties on which Stonegate Agricom holds interests which are
unknown to Stonegate Agricom at present and which have been caused by previous or existing owners of the properties.
To the extent Stonegate Agricom is subject to environmental liabilities, the payment of any liabilities or the costs that may
be incurred to remedy significant environmental impacts will reduce funds otherwise available for operations.
Climate Change Legislation
Peru is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol
established thereunder. Peru is thereby required to establish legally binding targets to reduce nationwide emissions of
carbon dioxide, methane, nitrous oxide and other “greenhouse gases”. Stonegate Agricom’s future operations and
activities may emit amounts of greenhouse gases which may subject it to legislation regulating emission of greenhouse
gases. The costs of complying with legislation may adversely affect the business of Stonegate Agricom.
Approvals and Permits
Government approvals, permits and authorizations are currently, or may in the future be, required in connection with
Stonegate Agricom’s operations. To the extent such approvals are required and not obtained, Stonegate Agricom may be
curtailed or prohibited from proceeding with planned exploration, development or operation of mineral properties. Failure
to comply with applicable laws, regulations and 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 and mitigation measures requiring capital expenditures, installation of additional equipment, or remedial
actions. Parties engaged in mining operations and parties that were engaged in operations in the past, may be required to
33

compensate those suffering loss or damage by reason of such exploration or mining related activities and may have civil
or criminal fines or penalties imposed for violations of applicable laws or regulations.
Amendments to current laws, regulations and permits governing operations and activities of mining companies, or the
more stringent implementation thereof, could have a material adverse impact on Stonegate Agricom and cause increases
in exploration expenses, capital expenditures or production costs, reduction in levels of production at producing
properties, or abandonment or delays in development of new mining properties.
Foreign Subsidiaries
Stonegate Agricom is a holding company that conducts operations through foreign subsidiaries and substantially all of its
assets are held in such entities. Accordingly, any limitation on the transfer of cash or other assets between the parent
corporation and such entities, or among such entities, could restrict Stonegate Agricom’s ability to fund its operations
efficiently. Any such limitations, or the perception that such limitations may exist now or in the future, could have an
adverse impact on Stonegate Agricom’s valuation and stock price.
Political and Economic Risk in Peru
Some of Stonegate Agricom’s mineral interests are currently located in Peru. Regardless of recent progress in
restructuring its political institutions and revitalizing its economy, Peru’s history since the mid-1980s has been one of
political and economic instability under both democratically elected and dictatorial governments. These governments
frequently have intervened in the national economy and social structure, including periodically imposing various controls,
the effects of which have been to restrict the ability of both domestic and foreign companies to freely operate. Although
Stonegate Agricom believes that the current conditions in Peru are relatively stable and conducive to conducting
business, Stonegate Agricom’s current and future mineral exploration and mining activities in Peru are exposed to various
levels of political, economic and other risks and uncertainties. These risks and uncertainties include, but are not limited to,
terrorism, hostage taking, military repression, extreme fluctuations in currency exchange rates, high rates of inflation,
political and labour unrest, the risks of war or civil unrest, expropriation and nationalization, renegotiation or nullification of
existing concessions, licences, permits and contracts, illegal mining, changes in taxation policies, restrictions on foreign
exchange and repatriation, changing political conditions, fluctuations in currency exchange rates, currency controls and
governmental regulations that favour or require the awarding of contracts to local contractors or require foreign
contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. There has been a significant level of
social unrest in Peru in recent years resulting from a number of factors, including a high rate of unemployment. Protestors
have targeted foreign firms in the resource sector (mining and oil and gas).
Stonegate Agricom’s exploration and development activities may be affected by changes in government, political
instability and the nature of various government regulations relating to the mining industry. Peru’s fiscal regime has
historically been favourable to the mining industry and has been relatively stable over the past 10 years or so. However,
in 2011 Ollanta Humala was elected President of Peru on pledges to raise taxes and exert greater control over the mining
industry. In December 2011, President Humala declared a brief state of emergency in the north Andes following popular
opposition to some major mining projects and environmental concerns. Despite these developments, Stonegate Agricom
believes that the current conditions in Peru are relatively stable and conducive to conducting business; however, there is
no assurance that future social unrest will not have an adverse impact on Stonegate Agricom’s operations.
Labour in Peru is customarily unionized and there are risks that labour unrest or wage agreements may impact
operations. Stonegate Agricom cannot predict the government’s positions on foreign investment, mining concessions,
land tenure, environmental regulation or taxation. A change in government positions on these issues could adversely
affect Stonegate Agricom’s business and/or its holdings, assets and operations in Peru. Any changes in regulations or
shifts in political conditions are beyond the control of Stonegate Agricom. Stonegate Agricom’s operations in Peru will
entail significant governmental, economic, social, medical and other risk factors common to all developing countries. The
status of Peru as a developing country may also make it more difficult for Stonegate Agricom to obtain any required
financing because of the investment risks associated with it.
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Stonegate Agricom’s operations in Peru may be adversely affected by economic uncertainty characteristic of developing
countries. Operations may be affected in varying degrees by government regulations with respect to restrictions on
production, price controls, export controls, currency remittance, income taxes, expropriation of property, foreign
investment, maintenance of claims, environmental legislation, land use, land claims of local people, water use and safety
factors. Any such changes could have a material adverse effect on Stonegate Agricom’s results of operations and
financial condition.
Peru has no limitation on profit or capital remittances to foreign shareholders provided that all applicable Peruvian taxes
have been paid. However, there can be no assurance that additional restrictions on the repatriation of earnings in Peru
will not be imposed in the future.
Risks Relating to the Retention of the Mantaro Project
Stonegate Agricom’s continuing right to maintain its ownership of the Mantaro Project will be dependent upon compliance
with applicable laws and the acquisition agreement it entered into with the previous owners of the project (the “Mantaro
Vendors”). Stonegate Agricom had financial commitments to the Mantaro Vendors to pay up to US$4 million, subject to
successful permitting and conversion of the concessions to non-metallic concessions. The Mantaro Vendors received
US$2.5 million in 2010 and will receive a final payment of US$1.5 million once all approvals are in place, including
community agreements, to develop a mine on certain lands comprising part of the Mantaro Project. Failure to make the
required payments could result in a loss of ownership of the Mantaro Project. There is no assurance that Stonegate
Agricom will be able to obtain and/or maintain all required claim conversions, approvals, authorizations, permits and
licenses required to carry on its operations. Additional expenditures will be required by Stonegate Agricom to maintain its
ownership of the Mantaro Project. These additional expenditures will be required to conduct a feasibility study to prove an
economic ore body and to bring it into production. See “Risk Factors - Risks Relating to Interest in Stonegate Agricom -
Uncertainty of Additional Capital”.
Risks Relating to the Retention of the Paris Hills Project
Stonegate Agricom’s continuing right to maintain its ownership of the Paris Hills Project will be dependent upon
compliance with applicable laws and payment of all lease and option payments with respect to the mining claims and fee
parcels comprising the Paris Hills Project. Failure to make the required payments could result in a loss of the Paris Hills
Project. There is no assurance that Stonegate Agricom will be able to obtain and/or maintain all required permits and
licenses to carry on its operations.
Expiration of Leases and Permits for the Paris Hills Project
The Paris Hills Project is held in the form of leases and permits. If Stonegate Agricom fails to meet certain requirements of
a lease or permit, the lease or permit may terminate or expire. There can be no assurance that all of the obligations
required to maintain each lease or permit will be met. The termination or expiration of Stonegate Agricom’s leases or
permits may have a material adverse effect on Stonegate Agricom’s business.
Land Title
The acquisition of title to mineral properties is a very detailed and time-consuming process. Title to, and the area of,
mineral concessions may be disputed. Although Stonegate Agricom believes it has taken reasonable measures to ensure
proper title to its properties, there is no guarantee that title to any of its properties will not be challenged or impaired. Third
parties may have valid claims underlying portions of Stonegate Agricom’s interests, including prior unregistered liens,
agreements, transfers or claims, including native land claims, and title may be affected by, among other things,
undetected defects. If title defects do exist, it is possible that Stonegate Agricom may lose all or a portion of its right, title,
estate and interest in the Mantaro Project or the Paris Hills Project. Title insurance is generally not available for mining
claims in Peru and Stonegate Agricom’s ability to ensure that it has a secure claim to individual mineral properties may be
constrained. Stonegate Agricom has not surveyed the boundaries of any of its properties and consequently the
boundaries may be disputed. In addition, Stonegate Agricom may be unable to operate its properties as permitted or to
enforce its rights with respect to its properties.
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Possible Failure to Obtain Non-Metallic Mineral Concessions
The Mantaro Project consists of mineral concessions which are either designated as metallic mineral concessions, nonmetallic
mineral concessions or are in the process of being converted from metallic to non-metallic. Category I and II
mining exploration activities can be performed on Stonegate Agricom’s metallic mineral concessions, subject to required
permits, authorizations and approvals. Significant exploration activity on the Mantaro Project will require that the mineral
concessions be converted from metallic mineral concessions to non-metallic mineral concessions. Metallic mineral
concessions may be converted to non-metallic mineral concessions; however, if they overlap agricultural lands, the land
must itself be converted to non-agricultural use first. There is a further risk that Stonegate Agricom will not obtain the
necessary local community co-operation and agreement to convert the mineral concessions from metallic to non-metallic
mineral concessions or will not obtain the necessary local community co-operation and agreement to facilitate the work
recommended under the Mantaro Technical Report.
Possible Failure to Obtain and Convert Surface Rights
The Mantaro Project is located in an area of intensive subsistent agriculture. Before any material exploration activities
can be performed on the Mantaro Project, the surface rights to the concessions which overlap with agricultural lands must
be secured and the surface rights must be converted from agricultural use to non-agricultural use. Once the surface rights
have been converted to non-agricultural use and all agricultural activities cease on the surface, applications can be filed to
convert the mineral concessions from metallic to non-metallic. This process will require both the co-operation of, and
agreements with, the local communities and formal (registrable) agreements to secure interests in surface rights. All
Category I and II exploration and subsequent development and exploitation work requires community consultation and
agreement in Peru and the Mantaro Project cannot be developed until surface rights are secured. However, the nature of
the Mantaro Project requires Stonegate Agricom to accelerate the process of acquiring interests in surface rights in order
to first convert the surface rights from agricultural lands to non-agricultural lands to facilitate conversion of the mineral
concessions from metallic mineral concessions to non-metallic mineral concessions. There is a risk that Stonegate
Agricom will not be able to obtain the co-operation and agreement of the local communities required to do further work on
the Mantaro Project in Category I. There is a risk that Stonegate Agricom will be unable to secure surface rights to the
mineral concessions at a reasonable price and on reasonable terms or at any price. The cost to acquire the surface rights
required cannot be determined at this time but will require the use of Stonegate Agricom’s working capital. While
Stonegate Agricom believes that it has adequate working capital for this purpose, there is no assurance that Stonegate
Agricom’s working capital will in fact be adequate. If some but not all of the surface rights required to be obtained are
secured, Stonegate Agricom’s ability to explore, exploit and develop the Mantaro Project may be seriously impaired. If
sufficient surface rights are not secured, Stonegate Agricom will be unable to explore, exploit and develop the Mantaro
Project.
Community Relations and Project Support
The successful development of the Mantaro Project and the Paris Hills Project is dependent on support from the local
communities surrounding these properties. Stonegate Agricom expects to engage such local communities to secure
support for the advancement of the Mantaro Project and the Paris Hills Project. A community agreement is required to
permit Mantaro Peru to conduct exploration drilling and to complete the conversion of the metallic mineral concessions to
non-metallic. There is no assurance that such an agreement can be reached.
Water Rights
Stonegate Agricom will need to obtain water rights through agreements with holders of local water rights in order to
service activities on the Mantaro Project and the Paris Hills Project. There is no assurance that Stonegate Agricom will be
able to successfully secure such water rights. Accordingly, there is no certainty that Stonegate Agricom will have access
to the amount of water needed to explore or develop its properties or to operate a mine on its properties, which may
prevent Stonegate Agricom from generating revenue, and which could materially adversely affect Stonegate Agricom’s
financial condition, cash flows and the trading price of Stonegate Agricom’s securities.
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Exploration, Development and Operating Risks
The exploration for, and development of, mineral deposits involve significant risks that even a combination of careful
evaluation, experience and knowledge may not eliminate. While the discovery of an ore body may result in substantial
rewards, few properties that are explored are ultimately developed into producing mines. There is no assurance that
Stonegate Agricom’s mineral exploration activities will result in any discoveries of commercial bodies of ore. Major
expenses may be required to locate and establish mineral reserves, to develop metallurgical processes and to construct
mining and processing facilities at a particular site. It is impossible to ensure that the exploration or development
programs planned by Stonegate Agricom or any of its joint venture partners will result in a profitable commercial mining
operation as the economic viability of the project would depend on obtaining favourable exploration results and commodity
prices. The commercial viability of a mineral deposit, if discovered, depends upon a number of factors including, amongst
others, the particular attributes of the deposit (principally size and grade); the proximity to infrastructure; the impact of
mine development on the environment; government regulations, including regulations relating to prices, taxes, royalties,
land tenure, land use, importing and exporting of minerals and environmental protection; and the competitive nature of the
industry which causes mineral prices to fluctuate substantially over short periods of time. The effect of these factors
cannot be accurately predicted, but the combination of these factors may result in Stonegate Agricom not receiving an
adequate return on invested capital. No assurance can be given that the minerals will be discovered in sufficient quantities
to justify commercial operations or that funds required for development can be obtained on a favourable basis. Locating
mineral deposits depends on a number of factors, not the least of which is the technical skill of the exploration personnel
involved.
Stonegate Agricom’s exploration activities will be subject to the availability of third party contractors and equipment.
Western Peru is located over the intersection of three geologic plates which are actively colliding, producing thrust faults
in the near-surface earth’s crust. These thrusts cause energy to be released which may produce earthquakes which are
sometimes sufficient to produce significant damage to property and infrastructure. Normally, these larger magnitude
earthquakes are focused along the coast, far from mining centers, but there is no certainty that a seismic event could not
cause physical damage to the Mantaro Project. There are also physical risks to the exploration personnel.
If any of Stonegate Agricom’s properties are found to have commercial quantities of ore, Stonegate Agricom would be
subject to additional risks respecting any development and production activities. Mining operations generally involve a
high degree of risk. Stonegate Agricom’s future operations would be subject to all the hazards and risks normally
encountered in the exploration, development and production of phosphate rock, including unusual and unexpected
geologic formations, seismic activity, ground failure, rock bursts, cave-ins, flooding and other conditions involved in the
drilling, blasting and removal of material, any of which could result in damage to, or destruction of, mines and other
producing facilities, damage to life or property, environmental damage and possible legal liability.
Mining, processing, development and exploration activities depend, to one degree or another, on adequate infrastructure.
Reliable roads, bridges, power sources and water supply are important determinants that affect capital and operating
costs. No surface water is available on the Mantaro Project and measures to ensure adequate water supply for operations
will be required in order to place the Mantaro Project into production. Unusual or infrequent weather phenomena,
sabotage, government or other interference in the maintenance or provision of such infrastructure could adversely affect
Stonegate Agricom’s operations, financial condition and results of operations. Potable water is supplied from local wells.
Development of suitable water catchment basins and/or a pipeline to bring water from the Mantaro River will be required
for mineral processing operations.
There is no certainty that the expenditures made by Stonegate Agricom towards the search and evaluation of mineral
deposits will result in discoveries of commercial quantities of ore. Stonegate Agricom’s ability to execute its planned
exploration programs on a timely basis is dependent on a number of factors beyond Stonegate Agricom’s control including
availability of drilling services, ground conditions, weather conditions and permitting.
Uncertainty in the Estimation of Mineral Resources
The figures for mineral resources contained in this AIF are estimates only and no assurance can be given that the
anticipated tonnages and grades will be achieved, that the indicated level of recovery will be realized or that mineral
37

esources could be mined or processed profitably. Such estimation is a subjective process, and the accuracy of any
mineral resource estimate is a function of the quantity and quality of available data and of the assumptions made and
judgments used in engineering and geological interpretation.
Stonegate Agricom and the Qualified Persons have carefully prepared and verified the mineral resource figures and
believe the methods of estimating mineral resources have been verified by mining experience. All mineral resource
estimates have been prepared in accordance with the CIM Standards adopted by NI 43-101. However, such figures are
estimates, and no assurance can be given that the indicated level of mineral will be produced. Mineral resources that are
not mineral reserves do not have demonstrated economic viability. There are numerous uncertainties inherent in
estimating mineral resources, including many factors beyond Stonegate Agricom’s control. Fluctuations in the price of
phosphate rock or by-products may render mineral resources containing lower grades of mineralization uneconomic.
Market price fluctuations of phosphate rock may render the present mineral resources unprofitable for periods of time.
Fluctuation in phosphate rock prices, results of drilling, metallurgical testing and production and the evaluation of mine
plans subsequent to the date of any estimate may require revision of such estimate. Any material reductions in estimates
of mineral resources, or of Stonegate Agricom’s ability to extract these mineral resources, could have a material adverse
effect on Stonegate Agricom’s operations and financial condition.
Uncertainty of Inferred Mineral Resources
Inferred mineral resources are not mineral reserves and do not have demonstrated economic viability and are considered
too speculative geologically to have economic considerations applied to them to enable them to be categorized as mineral
reserves. The estimates of mineral resources contained in this AIF contain estimates of inferred mineral resources. Due to
the uncertainty which may attach to inferred mineral resources, there is no assurance that the estimated tonnage and
grades as stated will be achieved or that they will be upgraded to measured and indicated mineral resources or proven
and probable mineral reserves as a result of continued exploration.
Results of Prior Exploration Work
In preparing each of the Mantaro Technical Report and the Paris Hills Technical Report, the authors of such reports relied
on data previously generated by exploration work carried out by other parties. There is no guarantee that data generated
by prior exploration work is 100% reliable and discrepancies in such data not discovered by Stonegate Agricom may exist.
Such errors and/or discrepancies, if they exist, could impact on the accuracy of the Mantaro Technical Report and/or the
Paris Hills Technical Report.
Dependence on Key Personnel
Stonegate Agricom is dependent upon a number of key management and technical personnel. Stonegate Agricom’s
ability to manage its exploration and development activities, and hence its success, will depend in large part on the efforts
of these individuals. Stonegate Agricom faces competition for qualified personnel and there can be no assurance that
Stonegate Agricom will be able to attract and retain such personnel. Failure to retain key employees or to attract and
retain additional key employees with necessary skills could have a materially adverse impact on Stonegate Agricom’s
growth and profitability. Stonegate Agricom does not have “key man” insurance on any of its directors or officers.
Currency Fluctuations
The operations of Stonegate Agricom in Peru and the United States will be subject to currency fluctuations and such
fluctuations may materially affect the financial position and results of Stonegate Agricom. Stonegate Agricom is subject to
the risks associated with the fluctuation of the rate of exchange of the Canadian dollar and the United States dollar.
Stonegate Agricom does not currently take any steps to hedge against currency fluctuations although it may elect to
hedge against the risk of currency fluctuations in the future. There can be no assurance that steps taken by Stonegate
Agricom to address such currency fluctuations will eliminate all adverse effects and, accordingly, Stonegate Agricom may
suffer losses due to adverse foreign currency fluctuations.
38

Insurance and Uninsured Risks
Stonegate Agricom’s business is subject to a number of risks and hazards including adverse environmental conditions,
industrial accidents, labour disputes, unusual or unexpected geological conditions, ground or slope failures, changes in
the regulatory environment and natural phenomena such as inclement weather conditions, floods and earthquakes. Such
occurrences could result in damage to mineral properties or production facilities, personal injury or death, environmental
damage to Stonegate Agricom’s properties or the properties of others, delays in mining, monetary losses and possible
legal liability. Although Stonegate Agricom maintains liability insurance in amounts which it considers adequate, the nature
of these risks is such that liabilities might exceed policy limits, the liabilities and hazards might not be insurable, or
Stonegate Agricom may elect not to insure against such liabilities due to high premium costs or other reasons, in which
event Stonegate Agricom could incur significant costs that could have a materially adverse effect upon its financial
position.
Stonegate Agricom is not insured against environmental risks. Insurance against environmental risks (including potential
liability for pollution or other hazards as a result of the disposal of waste products occurring from exploration) has not been
generally available to companies within the industry. Stonegate Agricom will periodically evaluate the cost and coverage
of the insurance against certain environmental risks that is available to determine if it would be appropriate to obtain such
insurance. Stonegate Agricom may be unable to maintain insurance to cover these risks at economically feasible
premiums. Insurance coverage may not continue to be available or may not be adequate to cover any resulting liability.
Without such insurance, and if Stonegate Agricom becomes subject to environmental liabilities, the payment of such
liabilities would reduce or eliminate its available funds or could exceed the funds Stonegate Agricom has to pay such
liabilities and result in bankruptcy. Should Stonegate Agricom be unable to fund fully the remedial cost of an
environmental problem it might be required to enter into interim compliance measures pending completion of the required
remedial work.
Competition
The mining industry is intensely competitive in all phases of exploration, development and production and Stonegate
Agricom competes with many companies possessing greater financial and technical resources. Competition in the mining
industry is primarily for mineral rich properties that can be developed and produced economically; the technical expertise
to find, develop and operate such properties; the labour to operate such properties; and the capital for the purpose of
funding such properties. Many competitors not only explore for and mine phosphate rock, but conduct refining and
marketing operations on a global basis. Such competition may result in Stonegate Agricom being unable to acquire
desired properties, to recruit or retain qualified employees or to acquire the capital necessary to fund its operations and
develop its properties. There is no assurance that even if commercial quantities of minerals are discovered, a ready
market will exist for their sale. Factors beyond the control of Stonegate Agricom may affect the marketability of any
minerals discovered. These factors include market fluctuations, the proximity and capacity of commercial markets and
processing equipment, government regulations, including regulations relating to prices, taxes, royalties, land tenure, land
use, importing and exporting of minerals and environmental protection. The exact effect of these factors cannot be
accurately predicted, but the combination of these factors may result in Stonegate Agricom not receiving an adequate
return on invested capital or issuing its investment capital. Existing or future competition in the mining industry could
materially adversely affect Stonegate Agricom’s prospects for mineral exploration and success in the future.
Legal Proceedings
Since substantially all of Stonegate Agricom’s assets are located outside of Canada, there may be difficulties in enforcing
any judgments obtained by Stonegate Agricom in foreign jurisdictions in Canadian courts. Stonegate Agricom may be
subject to legal proceedings and judgments in foreign jurisdictions. Similarly to the extent that Stonegate Agricom’s assets
are located outside of Canada, investors may have difficulty collecting from Stonegate Agricom on any judgments
obtained in Canadian courts and predicated on the civil liability provisions of securities legislation. Stonegate Agricom may
also be hindered or prevented from enforcing its rights with respect to a governmental entity or instrumentality because of
the doctrine of sovereign immunity.
39

Conflicts of Interest
Certain directors and officers of Stonegate Agricom are or may become associated with other natural resource companies
which may give rise to conflicts of interest. In accordance with the Ontario Business Corporations Act, directors who have
a material interest in any person who is a party to a material contract or a proposed material contract with Stonegate
Agricom are required, subject to certain exceptions, to disclose that interest and generally abstain from voting on any
resolution to approve the contract. In addition, the directors and the officers are required to act honestly and in good faith
with a view to the best interests of Stonegate Agricom. The directors and some of the officers of Stonegate Agricom have
either other full-time employment or other business or time restrictions placed on them and accordingly, Stonegate
Agricom will not be the only business enterprise of these directors and officers.
Risks Relating to the Corporate Segment and the Company Generally
Commodity Prices
The profitability of the Company’s equity investments, its exploration projects and its oil and natural gas activities will be
dependent upon the market price of mineral commodities, oil and natural gas and other natural resources relevant to the
particular equity investment or exploration project. Mineral and oil and natural gas prices fluctuate widely and are affected
by numerous factors beyond the control of the Company. The level of interest rates; the rate of inflation; global economic
conditions; world supply of mineral commodities, oil and natural gas; consumption patterns for mineral commodities, oil
and natural gas; forward sales of mineral commodities, oil and natural gas by producers; global production of mineral
commodities, oil and natural gas; political conditions; speculative activities; and stability of exchange rates can all cause
significant fluctuations in such prices.
Price Volatility
Securities of natural resource companies have experienced substantial volatility in the past, and especially during the past
24 to 48 months, often based on factors unrelated to the financial performance or prospects of the companies involved.
These factors include macroeconomic developments in North America and globally, and market perceptions of the
attractiveness of particular industries. As a result of any of these factors, the market price of the Company’s common
shares, and the market price of public companies in which the Company invests, at any given point in time may be subject
to market trends and macroeconomic conditions generally, notwithstanding any potential success of such companies in
creating revenues, cash flows or earnings and may not accurately reflect the long-term value of such companies. There
can be no assurance that continual fluctuations in price will not occur.
Private Companies and Illiquid Securities
The Company invests in securities of private companies. In some cases, the Company may be restricted by contract or
by applicable securities laws from selling such securities for a period of time. Such securities may not have a ready
market and the inability to sell such securities or to sell such securities on a timely basis may impair the Company’s ability
to exit such investments when the Company considers it appropriate.
Lack of Control over Companies in which the Company Invests
In certain cases and, in particular, with respect to the Minority Investments, the Company invests in securities of
companies that the Company does not control. These investments will be subject to the risk that the company in which
the investment is made may make business, financial or management decisions with which SRC does not agree or that
the majority stakeholders or management of the company may take risks or otherwise act in a manner that does not serve
SRC’s interests. If any of the foregoing were to occur, the values of investments by the Company could decrease and the
Company’s financial condition and cash flow could suffer as a result.
40

Key management and Amended and Restated MSA with SCLP
The success of the Company will be largely dependent upon the performance of its key officers, consultants and
employees and upon the relationship between the Company and SCLP through the Amended and Restated MSA.
Pursuant to the Amended and Restated MSA, SCLP may terminate the Amended and Restated MSA upon 180 days
notice. The termination of the Amended and Restated MSA by SCLP may have a negative effect on the performance of
the Company. The Company has not purchased any “key-man” insurance with respect to any of its directors, officers or
key employees and has no current plans to do so.
Lack of Diversification
From time to time, the Company may have only a limited number of investments and projects and, as a result, the
performance of the Company may be adversely affected by the unfavourable performance of one investment or project.
As well, the Company’s investments and projects are concentrated in the natural resource sector. As a result, the
Company’s performance will be disproportionately subject to adverse developments in this particular sector.
Due Diligence
Before making investments the Company conducts due diligence that it deems reasonable and appropriate based on the
facts and circumstances applicable to each investment. When conducting due diligence, the Company may be required
to evaluate important and complex business, financial, tax, accounting, environmental and legal issues. Outside
consultants, legal advisors, accountants and investment banks may be involved in this due diligence process in varying
degrees depending on the type of investment. Nevertheless, when conducting due diligence and making an assessment
regarding an investment, the Company relies on the resources available to it, including information provided by the target
of the investment and, in some cases, third party investigations. The due diligence investigation that the Company will
carry out with respect to any investment opportunity may not reveal or highlight all relevant facts that may be necessary or
helpful in evaluating such investment opportunity. Moreover, such an investigation will not necessarily result in the
investment being successful.
Conflicts of Interest
Certain directors and officers of the Company are or may become associated with other natural resource companies,
SCLP or Sprott Asset Management LP, which may give rise to conflicts of interest. In accordance with the Canada
Business Corporations Act, directors who have a material interest in any person who is a party to a material contract or a
proposed material contract with the Company are required, subject to certain exceptions, to disclose that interest and
generally abstain from voting on any resolution to approve the contract. In addition, the directors and the officers are
required to act honestly and in good faith with a view to the best interests of the Company. The directors and most of the
officers of the Company have either other full-time employment or other business or time restrictions placed on them and
accordingly, the Company will not necessarily be the only business enterprise of these directors and officers.
No History of Dividends
The Company has never paid a dividend on its common shares. Any future determination to pay dividends will be at the
discretion of the Board of Directors and will depend upon the capital requirements of the Company, results of operations
and such other factors as the Board of Directors considers relevant.
Gold Price Volatility
The price of the Company’s common shares will depend in part on, and fluctuate with, the price of gold bullion, which may
be affected by a variety of unpredictable, international, economic, monetary and political considerations, including,
inflation expectations, sales of gold bullion by central banks and the International Monetary Fund, confidence in the United
States dollar and other currencies, interest rates, financial and banking crises and international conflicts.
41

Uninsured and Underinsured Losses regarding Gold Bullion
The Company’s gold bullion is stored in the vaults of a Schedule 1 Bank in Toronto. It is segregated and insured.
However, there can be no assurance that the insurance carried by the bank will be sufficient to cover all the losses arising
out of any loss or damage to the Company’s gold held for safekeeping. In addition, insurance is not available for certain
risks, including, but not limited to, war, terrorist events, nuclear incident and government confiscations. Any uninsured
loss would negatively impact the value of the Company’s assets and the price of its shares.
Regulatory Changes regarding Gold or Silver Bullion
The Company may be negatively affected by changes in Canadian laws regarding the holding of gold and/or silver bullion
that would restrict or outlaw the Company’s ownership of gold and/or silver bullion. If such a change were to occur, it
would negatively impact the value of the Company’s assets and the price of its shares.
Leverage Risk
The Company may have significant leverage. On February 28, 2012, the Company entered into a prime brokerage
services and pledge agreement and other ancillary agreements with a Schedule 1 Bank (the “PB Agreements”).
Pursuant to the PB Agreements, the bank opened a trading account and granted a margin facility to the Company,
through which the Company is permitted to buy and sell securities on margin (the “Margin Facility”). In turn, the
Company is required to provide margin. The Company utilized the Margin Facility to fund its investment in ICD using gold
bullion as collateral.
The Company may utilize the Margin Facility or other forms of leverage to implement an investment strategy. If income
and appreciation on investments made with borrowed funds are less than the cost of leverage, the value of the
Company’s net assets may decrease. A leveraged capital structure increases exposure to adverse economic factors
such as rising interest rates, downturns in the economy and/or deterioration in the condition of the company in which a
leveraged investment was made. Such increased exposure to adverse economic factors may decrease the overall return
on a leveraged investment realized by the Company from the overall return on such investment had leveraged capital
structures not been used. In addition, increases in the amount of margin or similar payments could result in the need for
trading at times or prices that are disadvantageous to the Company and which could result in a loss for the Company.
There can be no assurance that the leveraged investment strategy employed by the Company at times will enhance
returns.
United States Federal and State Regulatory Risk
The U.S. Environmental Protection Agency has commenced a study of the potential environmental impacts of hydraulic
fracturing, including the impact on drinking water sources and public health. Legislation has been introduced before the
U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in
the fracturing process. In addition, some states have, and others are considering, adopting regulations that could restrict
hydraulic fracturing in certain circumstances. Any new laws, regulation or permitting requirements regarding hydraulic
fracturing could lead to operational delay, or increased operating costs or third party or governmental claims. Regulations
could result in additional burdens that could serve to delay or limit the drilling services ICD provides to third parties, as the
drilling operations of these third parties could be impacted by these regulations, their costs of compliance and doing
business could be increased or the development of unconventional gas resources from shale formations could be
delayed.
New Rig Construction Project Risks
New rig construction projects are subject to risks which could cause delays or cost overruns and adversely affect ICD’s
cash flows, results of operations, and financial position. New drilling rigs may experience start-up complications during
construction or following delivery, and may encounter other operational problems that could result in significant delays,
uncompensated downtime, reduced day rates or the cancellation, termination or non-renewal of drilling contracts. Rig
42

construction projects are subject to risks of delay or cost overruns inherent in any large construction project from
numerous factors, including the following:
• shortages of equipment, materials or skilled labor;
• unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
• failure of equipment to meet quality and/or performance standards;
• financial or operating difficulties of equipment vendors;
• unanticipated actual or purported change orders;
• inability by ICD or its customer to obtain required permits or approvals, or to meet applicable regulatory
standards in ICD’s areas of operations;
• unanticipated cost increases between order and delivery;
• adverse weather conditions and other events of force majeure;
• design or engineering changes; and
• work stoppages and other labor disputes.
Significant cost overruns or delays could adversely affect ICD’s financial position, results of operations and cash flows.
Additionally, failure to complete a rig on time may result in the delay or loss of revenue from that rig, which also could
adversely affect ICD’s business, results of operations, financial condition and growth strategy.
ICD is Dependent on Entering into Additional Drilling Contracts to Grow its Business
ICD’s business strategy is highly dependent upon it obtaining drilling contracts on attractive terms for its newly
manufactured rigs. Its business strategy is also highly dependent upon its ability to begin quickly to earn market day-rates
for its services, after an initial introductory period in which ICD will offer its services at discounted rates. ICD faces strong
competition from a wide variety of competitors, including competitors that have considerably greater financial, marketing
and technological resources, who may affect its ability to compete for new contracts, which is essential for its growth.
ICD’s Dependence on Skilled and Qualified Workers
ICD’s growth strategy requires it to rapidly recruit and retain skilled and qualified workers in order to market and operate
the new rigs it intends to manufacture and introduce to the market. ICD may be unable to employ a sufficient number of
skilled and qualified workers.
The delivery of ICD’s services and products and construction of its rigs requires personnel with specialized skills and
experience who can perform physically demanding work. As a result of the volatility of the contract drilling industry and the
demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work
environment at wage rates that are competitive. The demand for skilled workers is currently high and the supply is limited.
Potential inability or lack of desire by workers to commute to ICD’s facilities and job sites and competition for workers from
competitors or other industries are factors that could affect its ability to attract and retain workers. A significant increase in
the wages paid by competing employers could result in a reduction of ICD’s skilled labor force, increases in the wage
rates that it must pay, or both. If either or both of these events were to occur, ICD’s capacity and profitability could be
diminished and its growth potential could be impaired. ICD’s ability to be productive and profitable will depend upon its
ability to employ and retain skilled personnel and its ability to expand its operations will depend in part on its ability to
increase the size of its skilled labor force.
EMPLOYEES
At December 31, 2011, the Company (including its Subsidiaries and Stonegate Agricom) had 148 full and part time
employees. The Company and its Subsidiaries made use of a variable number of consultants as required for operations.
43

ENVIRONMENTAL POLICY
The environmental policy of the Company provides that the Company is committed to balancing good stewardship in the
protection of the environment with the need for economic growth. In particular, it is the Company’s policy:
• to measure, maintain and improve the Company’s compliance with environmental laws and regulations;
• to place a high priority on environmental considerations in planning, exploring, constructing, operating
and closing facilities;
• to place primary responsibility for compliance with environmental laws with operations management;
• in the absence of any regulation, to recognize and cost-effectively manage environmental risks in a
manner that protects the environment and the Company’s economic future;
• to promote employee involvement in implementing its environmental policy; and
• to encourage employee reporting of suspected environmental problems.
The Company ensures that all personnel and consultants working for the Company are aware of the importance of
preserving the environment, that the Company’s exploration activities are designed to have as small an impact as is
practical while still achieving the exploration goal and that the Company only carries out activities that are condoned by
the authorities in each area in which the Company operates.
DIVIDENDS
The Company has not paid any dividends since incorporation in 1994. The actual timing, payment and amount of
dividends paid by the Company would be determined by the Board of Directors of the Company based upon, among other
things, the cash flow, results of operations and financial condition of the Company, the need for funds to finance ongoing
operations and such other business considerations as the Board of Directors of the Company considers relevant.
MARKET FOR SECURITIES
The common shares of the Company are listed on the TSX under the symbol “SCP”.
Information concerning the trading prices and volumes of the Company’s common shares on the TSX during fiscal 2011 is
set out below:
Month High Low Share Volume
January $5.19 $4.33 8,976,460
February $5.60 $5.11 10,389,975
March $5.80 $4.91 10,251,060
April $5.51 $4.78 4,851,618
May $5.16 $4.75 4,531,677
June $5.02 $4.26 5,238,944
July $5.36 $4.51 4,058,088
August $5.30 $4.34 4,538,061
September $5.20 $3.96 3,763,437
October $4.43 $3.35 4,321,453
November $4.74 $3.90 2,222,709
December $4.32 $3.65 4,017,502
44

DIRECTORS AND OFFICERS
Name, Occupation and Security Holdings
The following table sets forth the name; province or state and country of residence; position held with the Company;
principal occupation within the five preceding years; period of directorship with the Company; and shareholdings of each
of the directors and executive officers of the Company. Directors of the Company hold office until the next annual meeting
of shareholders or until their successors are duly elected or appointed.
Name,
Province/State
and Country of
Residence
Michael Winn (1)(2)
California, United
States
Kevin T.
Bambrough (2)
Ontario, Canada
John P. Embry
Ontario, Canada
Terrence A.
Lyons (1)
British Columbia,
Canada
Position
held with
the
Company
Chairman
and Director
President,
Chief
Executive
Officer and
Director
Director
Director
Principal Occupation
President, Terrasearch
Inc. (consulting company
providing analysis on
mining and energy
companies)
President, Chief
Executive Officer and
Director, Sprott Resource
Corp.
Chief Investment
Strategist, Sprott Asset
Management LP (an
investment management
limited partnership)
Chairman, EACOM
Timber Corporation
(lumber company), and
Corporate Director
Director
Since
Number of
Voting
Securities
Owned (3)
2003 280,000 (4) 0.25%
2007 1,729,375 1.54%
2007 1,650,000 1.46%
2005 101,700 0.09%
Percentage
of Issued
and
Outstanding
Voting
Securities
A. Murray
Sinclair (1)(2)
British Columbia,
Canada
Eric S. Sprott
Ontario, Canada
Paul Dimitriadis
Ontario, Canada
Stephen Yuzpe
Ontario, Canada
Director
Director
Chief
Operating
Officer
Chief
Financial
Officer
Chairman, Sprott
Resource Lending Corp.
(company providing
lending facilities to the
resource sector)
Chairman, Chief
Executive Officer and
Chief Investment Officer,
Sprott Asset
Management LP
Chief Operating Officer,
Sprott Resource Corp.
Chief Financial Officer,
Sprott Resource Corp.
2003 45,000 (5) 0.04%
2007 7,018,100 6.23%
N/A 80,000 0.07%
N/A 26,000 0.02%
45

Notes
Name,
Province/State
and Country of
Residence
Arthur Einav
Ontario, Canada
Position
held with
the
Company
General
Counsel and
Corporate
Secretary
Principal Occupation
Director
Since
Number of
Voting
Securities
Owned (3)
Managing Director, SCLP N/A 1,140 0.00%
Percentage
of Issued
and
Outstanding
Voting
Securities
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) The information as to the number and percentage of common shares beneficially owned, directly or indirectly, or over which control or direction is
exercised, by the directors and executive officers, but which are not registered in their names and not being within the knowledge of the Company, has
been furnished by such directors and officers.
(4) The 280,000 shares in the Company are owned by MDW & Associates LLC, of which Mr. Winn is a shareholder.
(5) In addition to the 45,000 shares in the Company, Mr. Sinclair also owns 250,000 shares in OEOG.
Each of the foregoing individuals have been engaged in the principal occupation set forth opposite his or her name during
the past five years or in a similar capacity with a predecessor organization except for: (i) Kevin Bambrough who, prior to
January 1, 2008, was Market Strategist, Sprott Asset Management LP; (ii) Terrence A. Lyons who was Chairman of
Northgate Minerals Corporation until October 2011 when the company was sold to Aurico Gold Inc.; (iii) Paul Dimitriadis
who, prior to June 1, 2008, was Legal Counsel, SCLP, and, prior to September 15, 2007, practiced law at Blake, Cassels
& Graydon LLP (a law firm); (iv) Steven Yuzpe who, prior to April 1, 2009, was Vice President Operations at Cormark
Securities Inc. (a brokerage firm), prior to April 1, 2008, was the Chief Financial Officer at the Windmill Development
Group (a real estate development company) and prior to March 1, 2007, was the Chief Financial Officer at Points
International Ltd. (a reward currency management company); and (v) Arthur Einav who, prior to May 10, 2010, practiced
law at Davis Polk & Wardwell LLP (a law firm).
As of the date of this AIF, the directors and executive officers of the Company as a group, beneficially owned, directly or
indirectly, or exercised control or direction over approximately 10,931,315 common shares of the Company, being
approximately 9.7% of the issued and outstanding common shares. The information as to the number of common shares
beneficially owned, directly or indirectly, or over which control or direction is exercised, by the directors and executive
officers, but which are not registered in their names and are not within the knowledge of the Company, has been furnished
by such directors and officers.
Cease Trade Orders, Bankruptcies, Penalties or Sanctions
The directors and executive officers of the Company have furnished the following information.
Except as set out further below, no director or executive officer of the Company is, as at the date hereof, or was within 10
years before the date hereof, a director, chief executive officer or chief financial officer of any company (including the
Company) that was subject to a cease trade order, an order similar to a cease trade order, or an order that denied the
relevant company access to any exemption under securities legislation, in effect for a period of more than 30 consecutive
days:
46

(a) that was issued while the director or executive officer was acting in the capacity as director, chief executive
officer or chief financial officer, or
(b) 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 that person was acting in the capacity
as director, chief executive officer or chief financial officer.
In addition, except as set forth below, no director or executive officer of the Company:
(a) is, as of the date hereof, or has been within 10 years before the date hereof, 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
(b) has, within 10 years before the date hereof, 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 director or
executive officer.
Finally, except as set forth below, no director or executive officer of the Company has been subject to:
(a) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory
authority or has entered into a settlement agreement with a securities regulatory authority; or
(b) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered
important to a reasonable investor in making an investment decision.
A. Murray Sinclair was a director of Katanga Mining Limited (formerly Balloch Resources Ltd. and New Inca Gold Ltd.
(“NIGL”)) from May 1, 1998 to July 10, 2006. On February 25, 2002, February 25, 2002 and March 12, 2002, NIGL was
issued cease trading orders by the Ontario, British Columbia and Alberta Securities Commissions, respectively, for failing
to file financial statements and paying filing fees within the prescribed times. These orders were rescinded on September
20, 2002, October 1, 2003 and October 23, 2003, respectively, following the filing of the financial statements and
payments of outstanding fees.
Mr. Sinclair was a director of Etrion Corporation (formerly PetroFalcon Corporation and Petrium Industries Inc.) from
November 28, 2001 to June 4, 2003. On February 27, 2002, the British Columbia Securities Commission (“BCSC”) issued
an order regarding a private placement of PetroFalcon Corporation, which was a private company. The BCSC considered
it to be in the public interest to remove the applicability of certain exemptions from the prospectus and registration
requirements of the Securities Act (British Columbia) for PetroFalcon Corporation until a shareholders meeting of
PetroFalcon Corporation was held. In addition, the BCSC removed the applicability of the same exemptions for Quest
Ventures Ltd. in respect of the common shares received pursuant to the private placement. Approval of shareholders was
received on May 23, 2002 and the BCSC reinstated the applicability of the exemptions from the prospectus and
registration requirements for both companies shortly thereafter.
Mr. Terrence Lyons was the President and a director of FT Capital Ltd., which was subject to cease trade orders in each
of the Provinces of British Columbia, Alberta, Manitoba, Ontario and Quebec for failure to file financial statements for the
financial years ended December 31, 2001 and subsequent periods. At the request of Brascan Financial Corporation (now
Brookfield Asset Management Inc. (“Brookfield”)), Mr. Lyons joined the board of FT Capital Ltd. and was appointed its
President in 1990 in order to assist in its financial restructuring. In June 2009, FT Capital Ltd. was wound up and Mr.
Lyons resigned as a director.
Mr. Lyons was also a director of Royal Oak Ventures Inc. at the request of Brookfield (“Royal Oak”), which is currently
subject to cease trade orders in each of the provinces in British Columbia, Alberta, Ontario and Quebec due to the failure
47

of Royal Oak to file financial statements since the financial year ended December 31, 2003. Royal Oak’s financial
restructuring is ongoing.
Mr. Lyons was elected to the Board of Directors of Royal Oak and FT Capital Ltd. because of his valuable experience and
expertise in financial restructurings in the insolvency context.
Mr. Lyons was also a director of International Utilities Structures Inc. (“IUSI”) from 1991 - 2005. On October 17, 2003, IUSI
was granted protection from its creditors under the Companies’ Creditors Arrangement Act (“CCAA”) by the Court of
Queen’s Bench in Alberta. On March 31, 2005, an order was granted approving a final plan and distribution to creditors for
IUSI under the CCAA. That plan was accepted by all parties and Mr. Lyons resigned as a director concurrent with the final
order under the CCAA.
Conflicts of Interest
Certain of the Company’s directors and officers currently, or may in the future, act as directors and/or officers of other
companies and, consequently, there exists the possibility that a conflict may arise between their duties as a director or
officer of the Company and their duties as a director or officer of any such other company. There can be no assurance
that while performing their duties for the Company, the Company’s directors or officers will not be in situations that could
give rise to conflicts of interest. There can be no assurance that these conflicts will be resolved in the Company’s favour.
As a result of any such conflict, the Company may miss the opportunity to participate in certain transactions, which may
have a material adverse effect on the Company.
The Company’s directors and officers are aware of the existence of laws governing accountability of directors and officers
for corporate opportunity and requiring disclosure by directors and officers of conflicts of interest and the fact that the
Company will rely upon such laws in respect of any director’s or officer’s conflicts of interest or in respect of breaches of
duty by any of the Company’s directors or officers. All such conflicts must be disclosed by such directors or officers in
accordance with the Canada Business Corporations Act, and they will govern themselves in respect thereof to the best of
their ability in accordance with the obligations imposed upon them by law.
In addition, the Company’s directors and officers and SCLP, and their respective affiliates, may provide investment,
administrative and other services to other entities and parties. The Company’s directors and officers, and the directors
and officers of SCLP have undertaken to devote such reasonable time as is required to properly fulfill their responsibilities
in respect to the Company’s business and affairs, as they arise from time to time.
AUDIT COMMITTEE INFORMATION
The following information is provided in accordance with Form 52-110F1 under the Canadian Securities Administrators’
National Instrument 52-110 – Audit Committees (“NI 52-110”).
The Audit Committee’s Charter
The text of the Company’s Audit Committee Charter is set out in Appendix “G” hereto.
Composition of the Audit Committee
Currently, the audit committee of the Company (the “Audit Committee”) is composed of the following three directors:
Messrs. Lyons (Chair), Winn and Sinclair. All three members are considered “independent” and “financially literate” (as
such terms are defined in NI 52-110).
Relevant Education and Experience
Collectively, the Audit Committee has the education and experience to fulfill the responsibilities outlined in the Audit
Committee Charter. The education and current and past experience of each Audit Committee member that is relevant to
the performance of his responsibilities as an Audit Committee member is summarized below:
48

Name
Terrence A.
Lyons (Chair)
Michael Winn
A. Murray
Sinclair
Education and Experience
Mr. Lyons is currently Chairman of EACOM Timber Corporation which
operates eight sawmills in Eastern Canada. Mr. Lyons is a director of several
public and private corporations and currently serves as lead director and
chairman of the Audit Committee of Canaccord Financial Inc. Mr. Lyons
received his MBA from the University of Western Ontario and Bachelor of
Applied Sciences from the University of British Columbia.
Mr. Winn manages a consulting company that provides consulting and
financial services to energy and mining companies. He is a director and audit
committee member of several public companies operating in the mining and
oil and gas sectors. Prior to starting his own company, Mr. Winn was a
financial analyst for a southern California brokerage firm where he was
responsible for the evaluation of small cap resources stock. Mr. Winn has a
Bachelor of Science in geology and has completed undergraduate and
graduate business courses.
Mr. Sinclair is currently the Chairman and a director of Sprott Resource
Lending Corp. (“SRLC”) (formerly known as Quest Capital Corp. (“Quest”)),
a provider of bridge and mezzanine financing to companies in the natural
resource sector. SRLC is listed on the TSX and NYSE AMEX. Prior to his
current position, Mr. Sinclair also served as Co-Chairman and Managing
Director of Quest. Mr. Sinclair has extensive knowledge in areas of asset
backed lending, real estate, corporate restructuring and natural resources.
He is also a director and officer of several other public companies. Mr.
Sinclair received his Bachelor of Commerce degree from Queen’s University.
Pre-Approval Policies and Procedures
In accordance with the Audit Committee Charter, all non-audit services to be provided to the Company by the Company’s
auditor must be pre-approved by the Audit Committee. During 2011, the Audit Committee pre-approved $25,000 plus
applicable taxes in tax related services.
External Auditor Service Fees (By Category)
For the years ended December 31, 2011 and 2010, PricewaterhouseCoopers LLP (“PwC”) and its affiliates received or
accrued fees from the Company and Subsidiaries as detailed below:
December 31, 2011 December 31, 2010
($) ($)
Audit Fees 497,153 527,000
Audit-Related Fees 670,350 242,475
Tax Fees 151,891 24,800
All Other Fees 81,745 114,200
Total Fees 1,401,139 908,475
The “Audit-Related Fees” noted above were paid to PwC in connection with the review of interim financial statements,
accounting guidance, business acquisition reports, and IFRS scoping work. “Tax Fees” related to tax compliance work in
respect of Canadian corporate tax returns and tax planning advice. “All Other Fees” relate to due diligence conducted in
connection with acquisitions.
49

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
For the year ended December 31, 2011, the Company has a management fee and compensation expense of $10.3
million pursuant to the Management and Services Agreement and Amended and Restated MSA. SRCLP did not receive
any Management Profit Distribution (as defined below) under the Partnership Agreement in 2011.
The general partner of SCLP is Sprott Consulting GP Inc. The directors and officers of Sprott Consulting GP Inc. are:
Kevin Bambrough, Ontario (CEO and director), Peter Grosskopf, Ontario (President and director), Paul Dimitriadis,
Ontario (COO and director), Steve Yuzpe, Ontario (CFO) and Arthur Einav, Ontario (General Counsel and Secretary).
The sole limited partner of SCLP, and the sole shareholder of Sprott Consulting GP Inc., is Sprott Inc. (“SII”). The
directors and officers of SII are: Eric Sprott, Ontario (Chairman), Kevin Bambrough, Ontario (President), Peter Grosskopf,
Ontario (CEO and director), Jack C. Lee, Alberta (director), Arthur Richards Rule, California (director), James T. Roddy,
Ontario (director), Marc Faber, Thailand (director), Steven Rostowsky, Ontario (CFO) and Arthur Einav, Ontario (General
Counsel and Corporate Secretary). SII is a publicly traded corporation on the TSX (TSX:SII).
The General Partner of SRCLP is Sprott Resource Consulting GP Inc., which is a fully owned subsidiary of SCLP. The
directors and officers of Sprott Resource Consulting GP Inc. are: Kevin Bambrough, Ontario (CEO and director), Paul
Dimitriadis, Ontario (COO and director), Steve Yuzpe, Ontario (CFO and director) and Arthur Einav, Ontario (General
Counsel and Secretary). The sole limited partner of SRCLP, and the sole shareholder of Sprott Resource Consulting GP
Inc., is SCLP.
The Company has retained Sprott Asset Management LP (“SAM LP”) as a manager of certain of its equity assets. Eric S.
Sprott is the principal shareholder of SII, which is the sole limited partner of SAM LP, and is a director and officer of each
of Sprott Asset Management GP Inc. and SII and a director of the Company.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Company’s common shares is CIBC Mellon Trust Company, P.O. Box 700,
Station B, Montreal, QC, H3B 3K3. The register of transfers of the Company’s common shares is located in the Toronto
office of CIBC Mellon Trust Company.
Material Contracts Entered into During 2011
Investor Agreement
MATERIAL CONTRACTS
Concurrently with the Arrangement, the Company entered into an investor agreement (the “Investor Agreement”) with
WestFire. Pursuant to the Investor Agreement, the Company has agreed that, without the prior written consent of
WestFire: (i) it will not sell its WestFire Shares acquired by it pursuant to the Arrangement or its WestFire Shares acquired
upon the conversion of WestFire Non-Voting Shares for a period beginning on the effective date of the Arrangement (the
“Effective Date”) and ending on the earlier of (a) the date that is 18 months following the Effective Date, and (b) the date
of the completion of a “Change of Control Transaction” (as defined in the Investor Agreement); and (ii) it will not sell its
WestFire Non-Voting Shares, in a single transaction or series of related transactions, to one or more purchaser(s), unless
the aggregate gross proceeds due to the Company as a result of such transaction(s) exceed $10 million. The Investor
Agreement also provides for certain “drag-along” rights in the event of a change of control of WestFire for the benefit of
WestFire and certain “demand registration” rights for the benefit of the Company.
Amended and Restated MSA
On October 1, 2011, the Company’s Board of Directors and the general partner of SCLP approved changes to the MSA
and the Amended and Restated MSA was entered into. Pursuant to the Amended and Restated MSA, SCLP has agreed
to provide management and other administrative services to the Company. These services include, amongst other things,
administering day-to-day business affairs, assisting in the compliance with regulatory and securities legislation, and
50

managing the Company’s internal accounting, audit and legal functions. In addition, SCLP provides the Company with two
individuals as nominees to serve as directors; one individual as nominee to serve as a director, president and chief
executive officer; and one individual to serve as chief financial officer.
The Amended and Restated MSA became effective on October 1, 2011 and shall be in force until terminated by one of
the parties upon 180 days prior written notice (or such shorter period as the parties may mutually agree upon) or
otherwise terminated pursuant to its terms. The Amended and Restated MSA will terminate immediately where a windingup,
liquidation, dissolution, bankruptcy, sale of substantially all assets, sale of business or insolvency proceeding has
been commenced or is being contemplated by SCLP, and will terminate upon the completion of any such proceeding by
the Company. The Company may terminate the Amended and Restated MSA at any time if SCLP breaches any of its
material obligations thereunder and such breach has not been cured within 30 days following notice thereof from the
Company. In addition, in the event that a person or group of persons, acting jointly or in concert, acquires control over at
least 50% of the voting securities of the Company (a “Change of Control”), SCLP may elect, in its sole discretion, to
terminate the Amended and Restated MSA by giving the Company written notice of such termination within 90 days after
such Change of Control. In the event that SCLP terminates the Amended and Restated MSA upon a Change of Control,
the Amended and Restated MSA requires the Company (i) to pay a termination fee to SCLP equal to 5% of the Net Asset
Value of the Company, plus an amount equal to 20% of the amount by which the market capitalization of the Company
exceeds the Net Asset Value of the Company, all as of the effective date of the termination, and (ii) to call a meeting of
shareholders to approve changing the Company’s name to remove any reference to “Sprott”. The “Net Asset Value of
the Company” on a termination date is the amount equal to the Company’s total assets less its total liabilities less its
minority interest, all as at such date as set forth in the Company's consolidated financial statements prepared as at such
date.
In consideration for the services provided by SCLP to the Company pursuant to the Amended and Restated MSA, the
Company is required to pay SCLP, in respect of each fiscal quarter, a management services fee equal to 0.5% of the
Quarterly Net Asset Value of the Company for such fiscal quarter, less the total compensation paid to management who
are employed by both the Company and SCLP for such fiscal quarter (the “Management Services Fee”). The “Quarterly
Net Asset Value of the Company” on each valuation date is the amount equal to the average of the Net Asset Value of
the Company as at the end of such fiscal quarter and the Net Asset Value of the Company as at the end of the
immediately preceding fiscal quarter.
A copy of the Amended and Restated MSA has been filed on SEDAR and can be found at www.SEDAR.com.
Partnership Agreement
On September 28, 2011, the Company and an affiliate each subscribed for and purchased one Class B Unit (as defined in
the Partnership Agreement) at a price of $100 paid in cash per Class B Unit and formed a general partnership (the
“Partnership”) under the name “Sprott Resource Partnership”. The Company now invests and operates in the natural
resource sector through the Partnership.
Concurrently with entering into the Amended and Restated MSA on October 1, 2011, the Company subscribed for and
purchased 4.4 million Class B Units by way of a contribution of most of its assets to the Partnership, following which
SRCLP, as managing partner, (the “Managing Partner”) subscribed for and purchased 10 Class A Units (as defined in
the Partnership Agreement) at a price of $100 paid in cash per Class A Unit and was admitted to the Partnership pursuant
to the Partnership Agreement. Following execution of the Partnership Agreement, the Class B Unit held by the
Company’s affiliate was redeemed by the Partnership and the affiliate ceased to be a partner of the Partnership.
Pursuant to the terms of the Partnership Agreement, the Company holds all voting Partnership units, entitling the
Company to control the strategic, operating, financing and investing activities of the Partnership.
The Managing Partner holds all non-voting Partnership units and, within the terms and conditions established by the
Company, will manage the Partnership’s investment activities and assets, and administer the day-to-day operations of the
Partnership. SRCLP may be removed as the managing partner of the Partnership by way of a Special Resolution (as
51

defined in the Partnership Agreement) approved by no less than two thirds of the votes cast by the holders of the voting
Partnership units who vote on the resolution.
SRCLP, as managing partner, has the power and authority to transact the business of the Partnership and to deal with
and in the Partnership assets for the use and benefit of the Partnership, except as limited by any direction of the Board of
Directors of the Company, and subject to certain limits on authority established from time to time by the Board of Directors
of the Company.
SRCLP is entitled to receive, on an annual basis, 20% of the difference (if positive) (the “Management Profit
Distribution”) between: (i) the sum of the net profits of the Partnership and net losses of the Partnership since the fiscal
year in respect of which the last Management Profit Distribution was made; and (ii) the sum of the Annual Hurdles for
each fiscal year since the fiscal year in respect of which the last Management Profit Distribution was made. “Annual
Hurdle” means, for any fiscal year of the Partnership, an amount equal to the sum of the following amounts: (i) the
product of the average Quarterly Net Asset Value of the Partnership for such fiscal year multiplied by the average yield of
the Canadian 30-Year Generic Bond Index (Bloomberg Ticker: GCAN30YR Index) or such successor index, or Canadian
federal or provincial government bond having a term of approximately 30 years, as may be agreed to in writing by the
partners from time to time; and (ii) two percent of the average Quarterly Net Asset Value of the Partnership for such fiscal
year; provided that in respect of any fiscal year, the Annual Hurdle may be adjusted by an amount to be determined by the
partners. “Quarterly Net Asset Value of the Partnership” means, in respect of a fiscal quarter of the Partnership, the
average of the net asset value of the Partnership as at end of such fiscal quarter and the net asset value of the
Partnership as at the end of the immediately preceding fiscal quarter.
If the Partnership does not have sufficient cash on hand considered necessary in the opinion of the Managing Partner to
meet anticipated future operating deficiencies and future expenses and liabilities, the Managing Partner shall distribute
only such cash on hand that is available for distribution and the Partnership shall be indebted to the Managing Partner or
the Company, as the case may be, in an amount equal to the unpaid portion of such distribution and shall repay such
indebtedness as cash becomes available to it for distribution. In addition, any Management Profit Distribution resulting
from a disposition of an asset for non-cash consideration shall not be made until the earlier of such time as (a) such noncash
consideration is disposed of for cash and cash equivalents, in which event the amount of such distribution shall be
based on the amount of cash received by the Partnership for such non-cash consideration; (b) the Managing Partner is
removed as managing partner of the Partnership; and (c) the Partnership is liquidated or dissolved.
In addition to the above, the Company is entitled to receive, on an annual basis, out of the net profits of the Partnership for
the fiscal year, an amount equal to the net profits of the Partnership for such fiscal year less the Management Profit
Distribution for such fiscal year.
The Partnership shall continue until the earlier of:
• the passing of a Special Resolution to dissolve the Partnership;
• the disposition of all or substantially all of the assets of the Partnership;
• the date on which one partner holds all voting and non-voting units of the Partnership; and
• the entry of a final judgment, order or decree of a court of competent jurisdiction adjudicating the
Partnership to be a bankrupt, and the expiration without appeal of the period, if any, allowed by applicable
law in which to appeal therefrom.
A copy of the Partnership Agreement has been filed on SEDAR and can be found at www.SEDAR.com.
Names and Interests of Experts
INTERESTS OF EXPERTS
The Company’s auditors are PricewaterhouseCoopers LLP, Chartered Accountants, 250 Howe Street, Suite 700,
Vancouver, British Columbia, V6C 3S7. PwC have advised that they are independent of the Company in accordance with
applicable rules of professional conduct.
52

The Company’s independent qualified reserves evaluator is McDaniel & Associates Consultants Ltd. (“McDaniel”), 2200,
255 – 5 th Avenue S.W. Calgary, Alberta, T2P 3G6. As of the respective dates of the reports prepared by McDaniel in
respect of the Company’s reserves, the “designated professionals” (as defined in Form 51-102F2 under the Canadian
Securities Administrators’ National Instrument 51-102 – Continuous Disclosure Obligations) of McDaniel did not
beneficially own, directly or indirectly, any of the Company’s common shares.
The Company’s Qualified Persons who prepared the Mantaro Technical Report are Donald H. Hains, P.Geo., of Hains
Technology Associates (“Hains”), 605 Royal York Road, Toronto, Ontario, M8Y 4G5 and Michelle Stone, P.Geo., Ph.d, of
Caracle Creek International Consulting Inc. (“Caracle”), 34 King St. East, 9 th Floor, Toronto, Ontario, M5C 2X8. As of the
date of the Mantaro Technical Report, the “designated professionals” of Hains and Caracle did not beneficially own,
directly or indirectly, any of the Company’s common shares.
The Company’s Qualified Persons who prepared the Paris Hills Technical Report are Leo J. Gilbride, P.E., Vanessa
Santos, P.G., and Gary L. Skaggs, P.E., P.Eng., of Agapito Associates, Inc. (“Agapito”), 715 Horizon Drive, Suite 340,
Grand Junction, Colorado, 81506 USA. As of the date of the Paris Hills Technical Report, the “designated professionals”
of Agapito did not beneficially own, directly or indirectly, any of the Company’s common shares.
ADDITIONAL INFORMATION
Additional information relating to the Company may be found on SEDAR at www.SEDAR.com.
Additional information, including directors’ and officers’ remuneration, principal holders of the Company’s securities and
securities authorized for issuance under equity compensation plans, is contained in the Company’s information circular for
its most recent annual meeting of security holders involving the election of directors.
Additional financial information is provided in the Company’s financial statements and MD&A for its most recently
completed financial year.
53

APPENDIX “A”
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION (FORM 51-101F1)
[SEE NEXT PAGE]

SPROTT RESOURCE CORP.
FORM 51-101F1
STATEMENT OF RESERVES DATA
AND OTHER OIL AND GAS INFORMATION
This is the form referred to in item 1 of section 2.1 of National Instrument 51-101 Standards of Disclosure for
Oil and Gas Activities ("NI 51-101"). The terminology used in this Statement (as defined below) have the
meanings assigned thereto in NI 51-101 and related instruments and notices.
The Company carries on its oil and gas activities through its subsidiaries Waseca Energy Ltd. (“Waseca”) and One
Earth Oil & Gas Inc. (“One Earth Oil & Gas” or “OEOG”) (collectively, the “Oil & Gas Subsidiaries” and each
individually an “Oil & Gas Subsidiary”). The Company consolidates its earnings with its Oil & Gas Subsidiaries and,
as required under Items 2.3 and 2.4 of Form 51-101F1 of the Canadian Securities Administrators, the information in
this Statement of Reserves Data and Other Oil and Gas Information (the “Statement”) reflects 100 percent of the
reserves and related estimated future net revenue, production and related information of its Oil & Gas Subsidiaries.
All of the Company’s reserves are located in Canada (Alberta and Saskatchewan).
As at December 31, 2011, the Company owned 81.1 percent of the outstanding shares of Waseca, representing
73,632,240 of the 90,806,181 outstanding shares of Waseca. As a result, 18.9 percent of the Company’s reserves,
future net revenue, production and related information owned through Waseca and reflected in this Statement are
attributable to the 18.9 percent minority interest in Waseca which is not owned by the Company.
As at December 31, 2011, the Company owned 91.1 percent of the outstanding shares of One Earth Oil & Gas,
representing 17,300,000 of the 18,994,000 outstanding shares of One Earth Oil & Gas. As a result, 8.9 percent of the
Company’s reserves, future net revenue, production and related information owned through One Earth Oil & Gas and
reflected in this Statement are attributable to the 8.9 percent minority interest in One Earth Oil & Gas which is not
owned by the Company.
As at December 31, 2011, Waseca had warrants and options outstanding, the conversion or exercise of some or all of
which would dilute the Company’s interest in Waseca. As at December 31, 2011, One Earth Oil & Gas had options
outstanding, the exercise of some or all of which would dilute the Company’s interest in One Earth Oil & Gas. For a
breakdown of the capital stock of Waseca and One Earth Oil and Gas as at December 31, 2011, see page 7 of the
Company’s Annual Information Form (“AIF”). Waseca and One Earth Oil & Gas may raise additional funds through
future financings in which the Company may not participate, which would also dilute the Company’s interest therein.
McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineers of Calgary, Alberta,
evaluated 100 percent of Waseca’s proved and probable reserves in a report dated March 15, 2012 and effective
December 31, 2011 (the "Waseca Reserve Report"). McDaniel also evaluated 100 percent of One Earth Oil & Gas’
proved and probable reserves in a report dated March 14, 2012 and effective December 31, 2011 (the “One Earth Oil
& Gas Reserve Report”).
The information included in this Statement is based on and derived from the Waseca Reserve Report and the One
Earth Oil & Gas Reserve Report.
In addition, it should be noted that:
(i)
(ii)
estimates in the Statement of future net revenue, whether calculated without discount or using a discount
rate, do not represent fair market value; and
estimates in the Statement of reserves and future net revenue for individual properties may not reflect the
same confidence level as estimates of reserves and future net revenue for all properties, due to the
effects of aggregation.
- 1 -

All values in this report are expressed in Canadian dollars, unless specifically noted otherwise. Certain
numbers in the tables in this report may not add due to rounding.
PART 1 – DATE OF STATEMENT
Relevant Dates
Statement date: March 29, 2012
Effective date: December 31, 2011
Preparation date: March 15, 2012 (Waseca) and March 14, 2012 (One Earth Oil & Gas)
- 2 -

PART 2 – DISCLOSURE OF RESERVE DATA
The following tables set forth the gross and net reserves of the Company as at December 31, 2011, as well as the
estimated net present value of future net revenue associated with such reserves, using forecast prices and costs.
SUMMARY OF OIL AND GAS RESERVES
AS OF DECEMBER 31, 2011
FORECAST PRICES AND COSTS
Light and Medium Heavy Oil Natural Gas Natural Gas Liquids
Crude Oil
Reserves Category Gross Net Gross Net Gross Net Gross Net
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (Mbbls) (Mbbls)
Waseca
Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved Reserves
Probable Reserves
Total Proved plus Probable Reserves
- - 2,967 2,377 - - - -
- - 120 99 503 400 - -
- - 1,249 1,054 - - - -
- - 4,336 3,530 503 400 - -
- - 19,887 17,445 1,243 982 - -
- - 24,223 20,976 1,746 1,382 - -
One Earth Oil & Gas
Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved Reserves
Probable Reserves
Total Proved plus Probable Reserves
Company Total
Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved Reserves
Probable Reserves
Total Proved plus Probable Reserves
28 25 - - 1,500 1,272 16 13
43 37 - - 464 408 4 3
- - - - - - - -
71 63 - - 1,964 1,679 20 16
73 63 - - 1,526 1,317 15 12
144 125 - - 3,490 2,997 35 28
28 25 2,967 2,377 1,500 1,272 16 13
43 37 120 99 967 807 4 3
- - 1,249 1,054 - - - -
71 63 4,336 3,530 2,467 2,079 20 16
73 63 19,887 17,445 2,769 2,299 15 12
144 125 24,223 20,976 5,236 4,378 35 28
- 3 -

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2011
FORECAST PRICES AND COSTS
Before Deducting Income Taxes Discounted at After Deducting Income Taxes Discounted at
Reserves Category 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
Waseca
Proved Reserves
Developed Producing
111.5 104.5 98.5 93.3 88.6 83.6 78.4 74.0 70.1 66.7
Developed Non-Producing 4.8 3.9 3.3 2.7 2.3 3.7 3.0 2.4 2.0 1.6
Undeveloped 28.0 23.9 20.6 17.8 15.5 16.1 13.2 10.9 9.0 7.4
Total Proved Reserves
Probable Reserves
Total Proved plus Probable Reserves
144.2 132.4 122.3 113.8 106.4 103.3 94.6 87.3 81.1 75.7
656.9 382.4 239.1 158.1 109.0 485.1 281.7 175.4 115.3 78.8
801.1 514.7 361.4 271.9 215.4 588.4 376.3 262.7 196.4 154.5
One Earth Oil & Gas
Proved Reserves
Developed Producing
6.5 5.7 5.1 4.6 4.2 6.5 5.7 5.1 4.6 4.2
Developed Non-Producing 3.3 2.9 2.5 2.3 2.1 3.3 2.9 2.5 2.3 2.1
Undeveloped 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Total Proved Reserves
9.8 8.6 7.6 6.9 6.3 9.8 8.6 7.6 6.9 6.3
Probable Reserves
8.8 5.6 3.9 2.9 2.2 7.2 4.7 3.3 2.5 1.9
Total Proved plus Probable Reserves 18.6 14.2 11.5 9.8 8.5 17.0 13.2 10.9 9.3 8.2
Company Total
Proved Reserves
Developed Producing
118.0 110.2 103.6 97.8 92.8 90.1 84.1 79.1 74.7 70.9
Developed Non-Producing 8.0 6.8 5.8 5.0 4.4 7.0 5.8 4.9 4.3 3.7
Undeveloped 28.0 23.9 20.6 17.8 15.5 16.1 13.2 10.9 9.0 7.4
Total Proved Reserves
154.0 140.9 129.9 120.6 112.7 113.1 103.1 94.9 87.9 82.0
Probable Reserves
665.7 388.0 243.0 161.0 111.2 492.3 286.4 178.7 117.8 80.7
Total Proved plus Probable Reserves 819.7 528.9 372.9 281.7 223.9 605.4 389.5 273.6 205.7 162.7
- 4 -

The following table sets forth the elements of the future net revenue attributable to each of the Company’s proved
reserves and proved plus probable reserves, using forecast prices and costs and calculated without discount.
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2011
FORECAST PRICES AND COSTS
Reserves Category Revenue Royalties
Operating
Costs
Development
Costs
Abandonment
and
Reclamation
Costs
Future Net
Revenue
Before
Future Income
Tax Expenses
Future Income
Tax Expenses
Future Net
Revenue
After Income
Taxes
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
Waseca
Total Proved
Total Probable
Total Proved plus Probable
One Earth Oil & Gas
Total Proved
Total Probable
Total Proved plus Probable
Company Total
Total Proved
Total Probable
Total Proved plus Probable
320.97 65.23 89.89 19.22 2.42 144.20 40.92 103.28
1,524.39 214.47 460.70 189.32 2.97 656.93 171.79 485.13
1,845.35 279.69 550.60 208.54 5.39 801.13 212.71 588.42
18.34 2.52 5.23 0.49 0.31 9.79 - 9.79
19.47 2.73 6.13 1.66 0.12 8.82 1.63 7.19
37.81 5.25 11.36 2.15 0.44 18.61 1.63 16.98
339.31 67.74 95.12 19.71 2.74 153.99 40.92 113.07
1,543.85 217.20 466.84 190.98 3.09 665.74 173.42 492.33
1,883.16 284.95 561.96 210.69 5.83 819.73 214.34 605.40
- 5 -

The following table sets forth the estimated net present value of future net revenue attributable to the Company's
proved reserves and proved plus probable reserves by production group, estimated using forecast prices and costs,
calculated using a 10% discount rate and before deducting future income tax expenses. The table also sets forth the
net present value on a unit basis (i.e., $ per bbl or Mcf) using net reserves, a 10% discount rate and before deducting
future income tax expenses.
FUTURE NET REVENUE
BY PRODUCTION GROUP
AS OF DECEMBER 31, 2011
FORECAST PRICES AND COSTS
Waseca
Total Proved
Total Proved Plus Probable Reserves
One Earth Oil & Gas
Total Proved
Total Proved Plus Probable Reserves
Company Total
Total Proved
Total Proved Plus Probable Reserves
Production Group Future Net Revenue Unit Unit
Before Income Taxes Value Value
(discounted at 10%/yr) (discounted at 10%/yr) (discounted at 10%/yr)
(M$) ($/bbl) ($/Mcf)
Heavy Oil 122,112 34.59 N/A
Natural Gas (2) 221 N/A 0.55
Heavy Oil 360,152 17.17 N/A
Natural Gas (2) 1,278 N/A 0.92
Medium and Light Oil (1) 3,249 57.15 N/A
Natural Gas (2) 4,358 N/A 3.17
Medium and Light Oil (1) 5,136 44.10 N/A
Natural Gas (2) 6,388 N/A 2.64
Heavy Oil 122,112 34.59 N/A
Medium and Light Oil (1) 3,249 57.15 N/A
Natural Gas (2) 4,579 N/A 2.58
Heavy Oil 360,152 17.17 N/A
Medium and Light Oil (1) 5,136 44.10 N/A
Natural Gas (2) 7,666 N/A 2.02
- 6 -

PART 3 – PRICING ASSUMPTIONS
The following tables set forth the price forecasts and inflation and exchange rate assumptions utilized in preparing
the Company’s reserves data in this Statement. The Company’s reserves owned through Waseca and One Earth
Oil & Gas were calculated using forecasts and inflation and exchange rate assumptions provided by McDaniel,
effective January 1, 2012. Also set forth below are the Company’s weighted average prices received for each
product type in 2011.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
FORECAST PRICES AND COSTS
Alberta Alberta Sask. Sask. British
U.S. AECO Alberta Alberta Spot Prov. Spot Columbia
Henry Hub Spot Average Aggregator Sales Gas Sales Average
Gas Price Price Plantgate Plantgate Plantgate Plantgate Plantgate Plantgate
Year $US/MMBtu $C/MMBtu $C/MMBtu $C/MMBtu $C/MMBtu $C/MMBtu $C/MMBtu $C/MMBtu
(1)
2012 3.75 3.50 3.30 3.30 3.30 3.40 3.40 3.20
2013 4.50 4.20 4.00 4.00 4.00 4.10 4.10 3.90
2014 5.05 4.70 4.50 4.50 4.50 4.60 4.60 4.40
2015 5.50 5.10 4.90 4.90 4.90 5.00 5.00 4.80
2016 5.95 5.55 5.35 5.35 5.35 5.45 5.45 5.25
2017 6.35 5.90 5.70 5.70 5.70 5.80 5.80 5.60
2018 6.70 6.25 6.00 6.00 6.00 6.10 6.10 5.90
2019 6.95 6.45 6.20 6.20 6.20 6.30 6.30 6.10
2020 7.20 6.70 6.45 6.45 6.45 6.55 6.55 6.35
2021 7.35 6.85 6.60 6.60 6.60 6.70 6.70 6.50
2022 7.45 6.95 6.70 6.70 6.70 6.80 6.80 6.60
2023 7.60 7.05 6.80 6.80 6.80 6.90 6.90 6.70
2024 7.75 7.20 6.95 6.95 6.95 7.10 7.10 6.80
2025 7.95 7.40 7.15 7.15 7.15 7.30 7.30 7.00
2026 8.10 7.55 7.30 7.30 7.30 7.45 7.45 7.15
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr
(1) This forecast also applies to direct sales contracts and the Alberta gas reference price used in the Crow n royalty calculations.
- 7 -

Alberta Sask Edmonton
WTI Brent Edmonton Bow River Alberta Cromer Cond. & US/CAN
Crude Crude Light Hardisty Heavy Medium Natural Edmonton Edmonton Edmonton Exchange
Oil Oil Crude Oil Crude Oil Crude Oil Crude Oil Gasolines Propane Butanes NGL Mix Inflation Rate
Year $US/bbl $US/bbl $C/bbl $C/bbl $C/bbl $C/bbl $/bbl $/bbl $/bbl $/bbl % $US/$CAN
(1) (2) (3) (4) (5) (6) (7)
2012 97.50 107.50 99.00 82.00 74.00 91.00 106.00 54.60 76.20 72.40 2.0 0.975
2013 97.50 102.60 99.00 82.00 74.00 91.00 104.10 56.40 79.80 74.10 2.0 0.975
2014 100.00 102.60 101.50 84.10 75.90 93.30 104.60 58.90 81.80 76.10 2.0 0.975
2015 100.80 103.50 102.30 84.70 76.50 94.10 105.50 60.40 82.40 77.10 2.0 0.975
2016 101.70 104.40 103.20 85.50 77.10 94.90 106.40 62.00 83.20 78.30 2.0 0.975
2017 102.70 105.50 104.20 86.30 77.90 95.80 107.50 63.40 84.00 79.40 2.0 0.975
2018 103.60 106.40 105.10 87.10 78.60 96.60 108.50 64.60 84.70 80.40 2.0 0.975
2019 104.50 107.40 106.00 87.80 79.20 97.50 109.40 65.60 85.40 81.30 2.0 0.975
2020 105.40 108.30 106.90 88.60 79.90 98.30 110.40 66.70 86.10 82.20 2.0 0.975
2021 107.60 110.60 109.20 90.40 81.60 100.30 112.80 68.10 88.00 84.00 2.0 0.975
2022 109.70 112.70 111.30 92.20 83.20 102.30 115.00 69.40 89.70 85.60 2.0 0.975
2023 111.90 115.00 113.50 94.00 84.80 104.30 117.20 70.60 91.50 87.20 2.0 0.975
2024 114.10 117.30 115.80 95.90 86.50 106.40 119.60 72.10 93.30 89.00 2.0 0.975
2025 116.40 119.60 118.10 97.80 88.20 108.50 122.00 73.70 95.20 90.90 2.0 0.975
2026 118.80 112.10 120.50 99.80 90.10 110.80 124.50 75.20 97.10 92.70 2.0 0.975
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 2.0 0.975
(1) West Texas Intermediate at Cushing Oklahoma 40 degrees API/0.5% sulphur.
(2) North Sea Brent Blend 37 degrees API/1.0% sulphur.
(3) Edmonton Light Sw eet 40 degrees API, 0.3% sulphur.
(4) Bow River at Hardisty Alberta (Heavy stream).
(5) Heavy crude oil 12 degrees API at Hardisty Alberta (after deduction of blending costs to reach pipeline quality).
(6) Midale Cromer crude oil 29 degrees API, 2.0% sulphur.
(7) NGL Mix based on 45 percent propane, 35 percent butane and 20 percent natural gasolines.
- 8 -

SUMMARY OF THE COMPANY’S 2011 WEIGHTED AVERAGE PRICES
Waseca
One Earth Oil & Gas
Company Total
Light & Medium Oil ($/bbl) Heavy Oil ($/bbl) Natural Gas ($/Mcf) NGL ($/bbl)
- 68.61 - -
- - 3.78 76.25
- 68.61 3.78 76.25
- 9 -

PART 4 – RECONCILIATION OF CHANGES IN RESERVES
The following tables reconcile the Company’s oil and natural gas reserves (on a gross reserves basis) from
December 31, 2010 to December 31, 2011 using forecast prices and costs. Tables are provided for each Oil & Gas
Subsidiary and a total reconciliation for the Company.
RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS (WASECA)
Light and Medium Oil Heavy Oil Natural Gas Liquids
Proved
Probable
Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Associated and Non-Associated
Gas
Proved Probable Proved Plus
Probable
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MMcf)
December 31, 2010 - - - 2,259 2,191 4,451 - - - 503 820 1,323
Discoveries - - - - - - - - - - - -
Extensions and Improved Recovery - - - 3,147 18,325 21,472 - - - - 534 534
Technical Revisions - - - (262) (629) (892) - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - (111) (111)
Production - - - (808) - (808) - - - - -
At December 31, 2011 - - - 4,336 19,887 24,223 - - - 503 1,243 1,746
- 10 -

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS (ONE EARTH OIL & GAS)
Proved
Light and Medium Oil Heavy Oil Natural Gas Liquids Associated and Non-Associated
Gas
Probable
Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Proved Probable Proved Plus
Probable
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MMcf)
December 31, 2010 7 18 25 - - - 12 27 39 1,385 2,920 4,305
Discoveries - - - - - - - - - - - -
Extensions and Improved Recovery 47 66 113 - - - 3 5 9 388 642 1,029
Technical Revisions (2) (15) (17) - - - 7 (17) (10) 325 (2,079) (1,754)
Acquisitions 20 5 24 - - - 1 - 1 168 43 211
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (2) - (2) - - - (3) - (3) (301) - (301)
At December 31, 2011 71 73 144 - - - 20 15 35 1,964 1,526 3,490
- 11 -

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS (COMPANY TOTAL)
Light and Medium Oil Heavy Oil Natural Gas Liquids
Proved
Probable
Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Proved Probable Proved
Plus
Probable
Associated and Non-Associated
Gas
Proved Probable Proved Plus
Probable
(Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (Mbbls) (MMcf) (MMcf) (MMcf)
December 31, 2010 7 18 25 2,259 2,191 4,451 12 27 39 1,888 3,740 5,628
Discoveries - - - - - - - - - - - -
Extensions and Improved Recovery 47 66 113 3,147 18,325 21,472 3 5 9 388 1,176 1,563
Technical Revisions (2) (15) (17) (262) (629) (892) 7 (17) (10) 325 (2,079) (1,754)
Acquisitions 20 5 24 - - - 1 - 1 168 43 211
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - (111) (111)
Production (2) - (2) (808) - (808) (3) - (3) (301) - (301)
At December 31, 2011 71 73 144 4,336 19,887 24,223 20 15 35 2,467 2,769 5,236
- 12 -

PART 5 – ADDITIONAL INFORMATION RELATING TO RESERVES DATA
Undeveloped Reserves
Undeveloped Reserves were attributed by McDaniel in respect of Waseca and One Earth Oil & Gas in accordance
with the standards and procedures contained in the Canadian Oil & Gas Evaluation (COGE) Handbook. The
following tables set out, for each product type, the volumes of proved undeveloped reserves and probable
undeveloped reserves that were first attributed in each of the three most recent financial years and in the aggregate
before that time.
UNDEVELOPED RESERVES (WASECA)*
Proved Undeveloped Reserved and Year First Attributed
Light and Medium Oil
Heavy Oil
Natural Gas
(Mbbl)
(Mbbl)
(MMcf)
NGLs
(Mbbl)
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
Year
Prior - - 239 239 - - - -
2009 - - 160 340 - - - -
2010 - - 1,065 1,065 - - - -
2011 - - 971 1,248 - - - -
Probable Undeveloped Reserves and Year First Attributed
Light and Medium Oil
(Mbbl)
Heavy Oil
(Mbbl)
Natural Gas
(MMcf)
NGLs
(Mbbl)
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
Year
Prior - - 109 109 - - - -
2009 - - 200 290 - - - -
2010 - - 1,821 1,631 - - - -
2011 - - 18,054 18,461 - - - -
* Waseca was established in 2008.
- 13 -

UNDEVELOPED RESERVES (ONE EARTH OIL AND GAS)*
Light and Medium Oil
First
Attributed
(Mbbl)
Proved Undeveloped Reserves and Year First Attributed
Cumulative
at Year End
First
Attributed
Heavy Oil
(Mbbl)
Cumulative
at Year End
First
Attributed
Natural Gas
(MMcf)
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
Year
Prior - - - - - - - -
2009 - - - - - - - -
2010 - - - - - - - -
2011 - - - - - - - -
NGLs
(Mbbl)
Light and Medium Oil
First
Attributed
(Mbbl)
Probable Undeveloped Reserves and Year First Attributed
Cumulative
at Year End
First
Attributed
Heavy Oil
(Mbbl)
Cumulative
at Year End
First
Attributed
Natural Gas
(MMcf)
Cumulative
at Year End
First
Attributed
(Mbbl)
Cumulative
at Year End
Year
Prior - - - - - - - -
2009 - - - - - - - -
2010 14 14 - - 2,112 2,112 21 21
2011 43 44 - - 192 442 2 5
NGLs
* One Earth Oil and Gas was established in 2010.
UNDEVELOPED RESERVES (COMPANY)
Proved Undeveloped Reserved and Year First Attributed
Light and Medium Oil Heavy Oil Natural Gas NGLs
(Mbbl)
First
Attributed
Cumulative
at Year End
First
Attributed
(Mbbl) (MMcf) (Mbbl)
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
Year
Prior - - 239 239 - - - -
2009 - - 160 340 - - - -
2010 - - 1,065 1,065 - - - -
2011 - - 971 1,248 - - - -
Probable Undeveloped Reserves and Year First Attributed
Light and Medium Oil Heavy Oil Natural Gas NGLs
(Mbbl)
(Mbbl)
(MMcf)
(Mbbl)
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
First
Attributed
Cumulative
at Year End
Year
Prior - - 109 109 - - - -
2009 - - 200 290 - - - -
2010 14 14 1,821 1,631 2,112 2,112 21 21
2011 43 44 18,054 18,461 192 442 2 5
- 14 -

Proved undeveloped reserves are generally those reserves related to infill wells that have not been drilled or wells
further away from gathering systems requiring relatively high capital to bring on production. Probable undeveloped
reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and
lands contiguous to production. This also includes the probable undeveloped wedge from the proved undeveloped
locations.
The significant majority of the Company’s undeveloped reserves are scheduled to be developed within the next two
years. However, the Oil & Gas Subsidiaries will manage capital programs and may choose to delay development,
depending on a number of circumstances, including the existence of higher priority expenditures and prevailing
commodity prices and cash flows.
Significant Factors or Uncertainties
Other than as set forth in this Statement and the AIF, the Company does not anticipate any significant economic
factors or significant uncertainties that will affect any particular component of the reserves data. However, the
reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs and
well performance that are beyond the Company's control.
Future Development Costs
The following table sets forth the amount of development costs deducted in the estimation of future net revenue for
the reserves categories indicated using forecast prices and costs. The Company expects that each Oil & Gas
Subsidiary will fund the development costs of its reserves through a combination of cash flow, the issuance of
shares, or possibly debt. The Company does not anticipate that the costs of funding the estimated future
development costs will have any material effect on the disclosed reserves or estimated future net revenue.
Waseca
One Earth Oil & Gas
Company Total
Proved Proved Proved
Proved Plus Probable Proved Plus Probable Proved Plus Probable
M$ M$ M$ M$ M$ M$
2012 13,668 24,878 489 1,878 14,157 26,756
2013 4,963 36,003 - - 4,963 36,003
2014 554 56,775 - - 554 56,775
2015 - 1,158 - - - 1,158
2016 39 1,259 - - 39 1,259
Remainder - 88,469 - 272 - 88,741
Total for all
years
undiscounted 19,224 208,541 489 2,150 19,713 210,691
Total for all
years
discounted at
10% per year 17,796 128,358 466 1,855 18,262 130,213
- 15 -

PART 6 – OTHER OIL AND GAS INFORMATION
Oil and Gas Properties and Wells
Waseca
All of Waseca’s properties are within approximately 100 kilometers of the city of Lloydminster, which straddles the
Alberta/Saskatchewan border.
As of December 31, 2011, Waseca has leased Crown and Freehold Petroleum and Natural Gas rights to 17,122
gross hectares of which 92% were located within Saskatchewan. In the first quarter of 2012, Waseca gained an
additional 2,023 hectares, bringing the total gross holdings to 19,146 hectares. Waseca holds an average of
99.7% working interest in, and operates nearly all of, its properties.
Waseca is an active driller and, as of December 31, 2011, had 83 producing heavy oil wells. Waseca has acquired
or purchased approximately 2,328 kilometers of 2D seismic and 15.3 km 2 of 3D seismic to support the ongoing
efforts to discover and develop new pools. As of December 31, 2011, there are 24 separate pools in various
stages of development, and another 42 undrilled exploratory wells in inventory. In the first quarter of 2012, Waseca
drilled five exploration and 15 development wells and is shooting approximately 156 kilometers of 2D seismic data.
Waseca’s properties are prospective for, and producing from, various formations within the Lower Cretaceous
Mannville Group. All of the production is primary cold heavy oil production that ranges in quality from 11° - 16° API.
In addition, Waseca carries a small amount of non-producing heavy oil and natural gas reserves, and a significant
amount of undeveloped reserves stemming from the Golden Lake Waseca Channel that has SAGD potential. The
non-producing heavy oil and natural gas reserves, which have been discovered through the drilling of various wells
since late 2008, are relatively close to infrastructure, and will be brought on stream either when natural gas prices
recover or, in the case of a producing well, when the currently producing zone reaches its’ economic limit. The
reserves associated with the Golden Lake SAGD project were first recognised in October 2011 when the Minister’s
Order approving the SAGD project under the Oil and Gas Conservation Act of Saskatchewan was garnered.
Waseca has commissioned a salt water disposal facility located in the Tangleflags area to reduce hauling and third
party water disposal costs and is currently constructing another in the Celtic area. Tangleflags and Celtic are
Waseca’s two most significant areas in terms of oil production rates. All of Waseca’s producing wells are equipped
with single well batteries, with the oil and water trucked to various sales points. The use of single well batteries
results in relatively low capital costs. The Lloydminster area also has extensive third party infrastructure including
an upgrader, refinery, pipelines, produced water disposal, oil treating and oil blending facilities. Waseca utilizes this
infrastructure extensively and to date there have not been any material access restrictions to the third party
infrastructure.
Tangleflags/Greenstreet
Tangleflags/Greenstreet is located in Townships 51 to 52, and Ranges 24 to 28 W3M. Full year 2011 production
averaged 1,105 bbl/d increasing from 241 bbl/d in 2010.
Edam/Celtic
Edam/Celtic is located in Townships 49 to 52, and Ranges 20 to 23 W3M. Full year 2011 production averaged 650
bbl/d increasing from 106 bbl/d in 2010.
Golden Lake
Golden Lake is located in Township 48, Range 23 W3M. Production to the end of 2011 consisted of primary cold
production from a pool which is overlain by a separate undeveloped pool that is amenable to recovery utilizing
SAGD. Full year 2011 cold production averaged 223 bbl/d compared to 121 bbl/d in 2010.
The pool that is amenable to SAGD is a sandstone dominated estuarine deposit consisting predominately of
unconsolidated quartz sands. The reservoir is encountered at a depth of approximately 475 meters with net oil pay
ranging up to 23 meters in thickness. The oil column is underlain by bottom water and overlain with a thin gas cap.
The reservoir is highly porous with an average porosity in excess of 30%. Oil extracted from the core indicates the
- 16 -

oil gravity is between 10° to 11.5°API with viscosities ranging from 50,000 to 500,000 cp. The reservoir
characteristics encountered are similar to many other properties producing with SAGD.
On October 22, 2011, the Saskatchewan Ministry of Energy and Resources granted a Minister’s Order approving
the SAGD project under the Oil and Gas Conservation Act of Saskatchewan. In the Waseca Reserve Report,
McDaniel recognized 16.564 MMbbls as probable undeveloped reserves.
Other
Outside of the key areas, production averaged 236 bbl/d in 2011 compared to 94 bbl/d in 2010.
One Earth Oil & Gas
One Earth Oil & Gas has properties in central Alberta and north central Montana. As of December 31, 2011, the
majority of One Earth Oil & Gas’ properties were in the Wetaskiwin area of central Alberta.
Reserves are primarily attributable to the properties in the Wetaskiwin in Townships 45 and 46, Ranges 24, 25 and
26, West of 4. The Wetaskiwin area properties have extensive geological, geophysical and engineering
evaluations. One Earth Oil & Gas has access to approximately three townships with 3D seismic data with
significant geological control. The non-producing reserves, representing two wells in the Wetaskiwin area, have
been shut in for over one year due to low gas prices. All other wells in the area are pipeline connected and on
stream as of the date of this Statement. Pipelines are present in the area with lots of capacity. There were no
significant changes in ownership over the course of the year.
Oil and Gas Wells
The following table sets forth the number of producing and non-producing wells of the Oil & Gas Subsidiaries and
the Company as a whole as at December 31, 2011.
Producing Wells
Non-Producing Wells
Oil Gas Oil Gas
Gross Net Gross Net Gross Net Gross Net
Waseca
Alberta - - - - 2.0 2.0 - -
Saskatchew an 84.0 81.9 - - 39.0 39.0 2.0 2.0
Total
One Earth Oil & Gas
Alberta 3.0 2.2 4.0 2.7 - - 9.0 4.2
Montana - - - - 3.0 1.8 - -
Total
Company Total
Alberta 3.0 2.2 4.0 2.7 2.0 2.0 9.0 4.2
Saskatchew an 84.0 81.9 - - 39.0 39.0 2.0 2.0
Montana - - - - 3.0 1.8 - -
Total 87.0 84.1 4.0 2.7 44.0 42.8 11.0 6.2
Properties with No Attributed Reserves
Waseca
Waseca unproven properties are all located in Canada and consist of 15,660 hectares in Saskatchewan and
1,455.7 hectares of 100% working interest land in Alberta for a total of 17,115.7 hectares as of December 31, 2011.
Waseca holds three freehold mineral leases that have expiry dates in 2012, totaling 193.462 net hectares, of which
128 net hectares may actually expire.
- 17 -

One Earth Oil & Gas
One Earth Oil & Gas has unproven properties in Alberta and in Montana, consisting of a total of 79,369 gross acres
(20,789 net acres). On the Ermineskin First Nation (Wetaskiwin area) land, One Earth Oil & Gas will maintain
acreage by drilling a minimum of one well per year for four years. There are no work commitments on the other
lands as of December 31, 2011.
One Earth Oil & Gas has no significant land expiries by January 1, 2013.
Forward Contracts
Neither the Company nor the Oil & Gas Subsidiaries have entered into any agreements under which they may be
precluded from fully realizing, or may be precluded from the full effect of, future market pricing for oil and gas.
Abandonment and Reclamation Costs
Waseca
Waseca uses industry historical costs or third party cost estimates to estimate its total abandonment and
reclamation costs. The costs are estimated and then applied on a well by well basis. As of December 31, 2011,
Waseca had 148 gross (145.9 net) producing and standing wells for which it expects to incur abandonment and
reclamation costs.
Waseca estimates that its total abandonment and reclamation costs will be $3,056,000 undiscounted and
$1,543,000 discounted at 10%. Of the total undiscounted total abandonment and reclamation costs, the entire
amount was included in estimating future net revenue (total proved plus probable). Waseca expects to pay
$32,000 (undiscounted) in such costs in the next three years.
One Earth Oil & Gas
One Earth Oil & Gas uses industry historical costs or third party cost estimates to estimate its total abandonment
and reclamation costs. The costs are estimated and then applied on a well by well basis. One Earth Oil & Gas
currently has 21 gross (10.4 net) wells for which it expects to incur abandonment and reclamation costs.
One Earth Oil & Gas estimates that its total abandonment and reclamation costs will be $500,000 undiscounted
and $320,000 discounted at 10%. Of the total undiscounted total abandonment and reclamation costs, 87% was
included in estimating future net revenue (total proved plus probable). One Earth Oil & Gas does not expect to pay
any such costs in the next three years.
Tax Horizon
The Company’s oil and gas activities are conducted through the Oil & Gas Subsidiaries and will be taxed within the
respective Oil & Gas Subsidiary. Depending on production, commodity prices and capital spending levels, the
Company does not expect Waseca to pay current income taxes until the second half of 2012 and does not expect
One Earth Oil & Gas to pay current income taxes until approximately 2017.
Costs Incurred
The following table sets forth the costs incurred by each of the Oil & Gas Subsidiaries and in the aggregate in 2011:
- 18 -

Waseca One Earth Oil & Gas Company Total
$ $ $
Costs
Canada
Proved Property Acquisitions (including facilities ) - 1,772,654 1,772,654
Unproved Property Acquisitions 11,640 382,077 393,717
Exploration 3,648,341 1,620,732 5,269,073
Development 30,007,759 1,828,763 31,836,522
Total 33,667,740 5,604,226 39,271,966
United States -
Proved Property Acquisitions (including facilities ) - - -
Unproved Property Acquisitions - - -
Exploration - 484,808 484,808
Development - -
Total - 484,808 484,808
Exploration and Development Activities for 2011
The following table sets forth the number and type of development and exploratory wells completed by each of the
Oil & Gas Subsidiaries, and in the aggregate, in 2011.
Oil Wells
Gas Wells
Service Wells and Stratigraphic Test Wells
Dry Holes
Total Completed Wells
Oil Wells
Gas Wells
Service Wells and Stratigraphic Test Wells
Dry Holes
Total Completed Wells
Oil Wells
Gas Wells
Service Wells and Stratigraphic Test Wells
Dry Holes
Total Completed Wells
Development Wells Exploratory Wells
Gross Net Gross Net
Waseca
63 60 2 2
1 1 - -
- - - -
6 6 - -
72 69 3 3
One Earth Oil & Gas
1 1 2 2
- - 1 1
- - - -
- - - -
1 1 5 4
Company Total
64 61 4 4
1 1 1 1
- - - -
6 6 - -
73 70 8 7
For a description of the Company’s most important and likely exploration and development activities, see “Oil and
Gas Properties” above.
- 19 -

Production Estimates
The following table summarizes the estimated 2012 average daily production reflected in the estimates of gross
proved reserves and gross probable reserves disclosed under Part 2 of this Statement. These estimates were
provided by McDaniel.
Light/Medium Natural Gas Natural Total
Oil Heavy Oil Liquids Gas Production
(bbls/d) (bbls/d) (bbls/d) (Mcf /d) (boe/d)
Waseca
Gross Proved Reserves - 3,952 - - 3,952
Gross Probable Reserves - 538 - - 538
One Earth Oil & Gas
Gross Proved Reserves 54 - 15 1,527 323
Gross Probable Reserves 12 - 2 212 50
Company Total
Gross Proved Reserves 54 3,952 15 1,527 4,275
Gross Probable Reserves 12 538 2 1,527 587
- 20 -

Production History and Netbacks
The following table indicates the gross average daily production from the Company’s important fields for the year
ended December 31, 2011 and the netbacks received:
Quarter Ended
March 31, 2011
Quarter Ended
June 30, 2011
Quarter Ended
September 30, 2011
Quarter Ended
December 31, 2011
Average Daily Production
Natural Gas (Mcf/d) - 901 972 1,392
Natural Gas Liquids (bbls/d) - 14 13 23
Light & Medium Oil (bbls/d) - - - -
Heavy Oil (bbls/d) 1,253 1,543 2,522 3,513
Combined (boe/d) 1,253 1,707 2,697 3,768
Natural Gas Netbacks ($/Mcf)
Revenue $ -
$ 4.31 $ 3.87
$
3.38
Royalties $ -
$ 0.63 $ 0.43
$
0.34
Production Costs $ -
$ 0.86 $ 1.18
$
1.48
Netback $ 2.82 $ 2.26
$
1.56
\
Light & Medium Oil Netbacks ($/bbl)
Revenue $ -
$ -
$ -
$
-
Royalties $ -
$ -
$ -
$
-
Production Costs $ -
$ -
$ -
$
-
Netback $ -
$ -
$ -
$
-
Heavy Oil Netbacks ($/bbl)
Revenue $ 58.67 $ 71.53 $ 61.49
$
75.83
Royalties $ (14.73) $ (17.71) $ (14.81) $
(19.44)
Production Costs $ (20.46) $ (17.06) $ (18.11) $
(15.80)
Netback $ 23.48 $ 36.76 $ 28.57
$
40.59
Natural Gas Liquids Netbacks ($/bbl)
Revenue $ -
$ 71.30 $ 69.11
$
83.09
Royalties $ -
$ 10.48 $ 7.74
$
8.39
Production Costs $ -
$ -
$ -
$
-
Netback $ -
$ 60.82 $ 61.37
$
74.70
- 21 -

Production by Important Field
The following table sets forth the average daily production in 2011, by product type, for each of the Company’s
important fields and in total:
Waseca
Tangleflags/Greenstreet
Golden Lake
Edam/Celtic
Light and Medium
Heavy Oil Crude Oil Natural Gas NGL Total
bbls/d bbls/d Mcf/d bbls/d boe/d
1,105 - - - -
650 - - - -
223 - - - -
Other
236 - - - -
Waseca Total
2,214 - - - -
One Earth Oil & Gas
Wetaskiw in
- - 738 11 134
Other - - 82 1 15
One Earth Oil & Gas Total
- - 820 12 149
Company Total
2,214 - 820 12 149
- 22 -

APPENDIX “B”
REPORT ON RESERVES BY MCDANIEL & ASSOCIATES CONSULTANTS LTD. – WASECA
(FORM 51-101F2)
[SEE NEXT PAGE]

March 15, 2012
Sprott Resource Corp.
Suite 2750, Royal Bank Plaza, South Tower
200 Bay Street, PO Box 90
Toronto, Ontario
M5J 2J2
Attention:
The Board of Directors of Sprott Resource Corp.
Re: Form 51-101F2
Report on Reserves Data by an Independent Qualified Reserves Evaluator
of Sprott Resource Corp. (the “Company”)
To the Board of Directors of Sprott Resource Corp. (the “Company”):
1. We have evaluated the Company’s reserves data as at December 31, 2011. The reserves data
are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2011 estimated using forecast prices and costs.
2. The reserves data are the responsibility of the Company’s management. Our responsibility is
to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and
Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of
Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining,
Metallurgy & Petroleum (Petroleum Society).
3. Those standards require that we plan and perform an evaluation to obtain reasonable
assurance as to whether the reserves data are free of material misstatement. An evaluation
also includes assessing whether the reserves data are in accordance with principles and
definitions presented in the COGE Handbook.
4. The following table sets forth the estimated future net revenue (before deduction of income
taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs
and calculated using a discount rate of 10 percent, included in the reserves data of the
Company evaluated by us, for the year ended December 31, 2011, and identifies the
respective portions thereof that we have evaluated and reported on to the Company’s
management:
2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6 Tel: (403) 262-5506 Fax: (403) 233-2744 www.mcdan.com

Sprott Resource Corp. – Waseca Energy Inc. (Cold Flow Plus SAGD Consolidation) Page 2
Forecast Prices and Costs March 15, 2012
Net Present Value of Future Net Revenue $M
(before income taxes, 10% discount rate)
Preparation Date of
Evaluation Report Location of Reserves Audited Evaluated Reviewed Total
March 15, 2012 Canada - 361,430 - 361,430
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects,
been determined and are in accordance with the COGE Handbook, consistently applied. We
express no opinion on the reserves data that we reviewed but did not audit or evaluate.
6. We have no responsibility to update our report referred to in paragraph 4 for events and
circumstances occurring after the preparation date.
7. Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material.
Executed as to our report referred to above:
MCDANIEL & ASSOCIATES CONSULTANTS LTD.
_________________________
C. B. Kowalski, P. Eng.
Vice President
Calgary, Alberta
March 15, 2012

APPENDIX “C”
REPORT ON RESERVES BY MCDANIEL & ASSOCIATES CONSULTANTS LTD. – OEOG
(FORM 51-101F2)
[SEE NEXT PAGE]

March 14, 2012
Sprott Resource Corp.
Suite 2750, Royal Bank Plaza, South Tower
200 Bay Street, PO Box 90
Toronto, Ontario
M5J 2J2
Attention:
The Board of Directors of Sprott Resource Corp.
Re: Form 51-101F2
Report on Reserves Data by an Independent Qualified Reserves Evaluator
of Sprott Resource Corp. (the “Company”)
To the Board of Directors of Sprott Resource Corp. (the “Company”):
1. We have evaluated the Company’s reserves data as at December 31, 2011. The reserves data
are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2011 estimated using forecast prices and costs.
2. The reserves data are the responsibility of the Company’s management. Our responsibility is
to express an opinion on the reserves data based on our evaluation.
We carried out our evaluation in accordance with standards set out in the Canadian Oil and
Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of
Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining,
Metallurgy & Petroleum (Petroleum Society).
3. Those standards require that we plan and perform an evaluation to obtain reasonable
assurance as to whether the reserves data are free of material misstatement. An evaluation
also includes assessing whether the reserves data are in accordance with principles and
definitions presented in the COGE Handbook.
4. The following table sets forth the estimated future net revenue (before deduction of income
taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs
and calculated using a discount rate of 10 percent, included in the reserves data of the
Company evaluated by us, for the year ended December 31, 2011, and identifies the
respective portions thereof that we have evaluated and reported on to the Company’s
management:
2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6 Tel: (403) 262-5506 Fax: (403) 233-2744 www.mcdan.com

Sprott Resource Corp. – Evaluation of One Earth Oil & Gas Inc. Page 2
Forecast Prices and Costs March 14, 2012
Net Present Value of Future Net Revenue $M
(before income taxes, 10% discount rate)
Preparation Date of
Evaluation Report Location of Reserves Audited Evaluated Reviewed Total
March 14, 2012 Canada - 11,524 - 11,524
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects,
been determined and are in accordance with the COGE Handbook, consistently applied. We
express no opinion on the reserves data that we reviewed but did not audit or evaluate.
6. We have no responsibility to update our report referred to in paragraph 4 for events and
circumstances occurring after the preparation date.
7. Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material.
Executed as to our report referred to above:
MCDANIEL & ASSOCIATES CONSULTANTS LTD.
_________________________
B. J. Wurster, P. Eng.
Vice President
Calgary, Alberta
March 14, 2012

APPENDIX “D”
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE (FORM 51-101F3)
[SEE NEXT PAGE]

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
(FORM 51-101F3)
Management of Sprott Resource Corp. (the “Company”) is responsible for the preparation and
disclosure of information with respect to the Company’s oil and gas activities in accordance with
securities regulatory requirements. This information includes reserves data which are estimates
of proved reserves and probable reserves and related future net revenue as at December 31,
2011, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The
reports of the independent qualified reserves evaluator are presented in Appendices B and C to
the AIF and will be filed with securities regulatory authorities concurrently with this report.
The board of directors of the Company has
(a) reviewed the Company’s procedures for providing information to the independent
qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to determine whether any
restrictions affected the ability of the independent qualified reserves evaluator to report
without reservation; and
(c) reviewed the reserves data with management and the independent qualified reserves
evaluator.
The board of directors has reviewed the Company’s procedures for assembling and reporting
other information associated with oil and gas activities and has reviewed that information with
management.
The board of directors has approved
(a) the content and filing with securities regulatory authorities of Form 51-101F1
containing reserves data and other oil and gas information;
(b) the filing of Forms 51-101F2 which are the reports of the independent qualified
reserves evaluator on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material.
(signed) Kevin Bambrough
Kevin Bambrough
President and Chief Executive Officer
(signed) Paul Dimitriadis
Paul Dimitriadis
Chief Operating Officer
(signed) Michael Winn
Michael Winn
Director
(signed) Terrence Lyons
Terrence Lyons
Director
March 29, 2012

APPENDIX “E”
MANTARO TECHNICAL REPORT SUMMARY
[SEE NEXT PAGE]

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
1 SUMMARY
EXECUTIVE SUMMARY
Stonegate Agricom Ltd. (“Stonegate” or “the Company”) engaged Hains Technology
Associates (“HTA”) and Caracle Creek International Consulting Inc. (CCIC) to prepare
an independent Technical Report on the Mantaro phosphate project (the “Project”),
located near Sincos, Junin Department, Peru.
Sprott Resource Corp (“Sprott”) owns 66,221,000 common shares of Stone gate which
represents approximately 73% of the outstanding shares on an undiluted basis, and
approximately 62% on a fully diluted basis.
The Project is located within a regionally significant geological structure known as the
Mancaspico Syncline. This Technical Report is based on the results of exploration work
conducted by Stonegate since acquisition of the Property in 2008. This Technical Report
conforms to NI 43-101 Standards of Disclosure for Mineral Projects.
Stonegate is engaged in the business of the acquisition, exploration and development of
mineral properties with a focus on agricultural nutrients. The Company owns, through its
wholly-owned subsidiary, Mantaro Peru SAC (“Mantaro Peru” or “MPS”), a 100%
interest in the Mantaro Property. Stonegate was formed from the merger between
Stonegate’s predecessor, Stonegate Minerals Ltd., with a subsidiary of Sprott.
The Mantaro Project is an exploration project located near Sincos, Peru, in the central
Andes (Figures 4-1 and 4-2). Previous exploration work on the Project in the 1980s and
1990s had identified an extensive zone of phosphate mineralization amenable to
beneficiation and production of phosphate rock concentrate. In this report, references to
historical work on “the Property” refer to the Philip concession and the adjacent Sincosa
concession, which is owned by others.
The major asset associated with the Project, and the subject of this Technical Report, is a
mineralized zone of phosphatic rock currently defined by surface outcrops, trenches and
drilling extending over a strike length of more than 30 km and a width of more than 5 km
on the west side of the Mantaro River. The total area covered by the concessions
comprising the Property is 12,800 ha. This area is known as the Mantaro deposit in this
report. Mineralization is exposed as three roughly parallel exposures (manto) trending in
a NW-SE direction noted as the West, East and Far East zones in this report (Figure 1-1).
Hains Technology Associates 1

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
Figure 1-1
Mantaro Property (partial plan)
MPS also holds an additional 7,000 ha of mineral concessions on the east side of the
Mantaro River (Puerta de Piedras 9-16 concessions, known as the Mantaro East deposit)
and 1,700 ha of mineral concessions (Alora 1-7 concessions) approximately 60 km
northwest of the Mantaro Property.
The Property is located near a major rail line connecting Huancayo with Lima and the
port of Callao. High tension electric transmission lines cross the Property on its western
side. The Property is accessible from the national highway connecting Huancayo to Lima
via gravel roads from the towns of Sincos, Aco, Mitu and several other communities.
Doe Run (Peru) Corporation (“Doe Run”) operates a base metal smelter at La Oroya,
approximately 60 km west of the Property. The Doe Run smelter is a potential source of
sulphuric acid for use in fertilizer manufacture.
The Mancaspico Syncline region has been the subject of extensive exploration work over
several decades, beginning in the early 1960s. Work by Cerro de Pasco Corporation
(“CDP”) in the 1960s outlined a regional historical geological resource estimated to
contain over 300 million tonnes. Later work involving Zublin Mining of Chile (“Zublin
Mining” or “Zublin”) and Doe Run provided additional information on the extent and
quality of the phosphate resource on the Property and the potential for phosphate fertilizer
production based on trenching and channel sampling within the area currently defined by
the Philip concession and the adjacent Sincosa concession. Bulk sample material from
widely spaced trenches was used by Bateman Phosphate Technologies (“Bateman”) in
2000/2001 in beneficiation studies and to prepare a scoping study. The 2001 Bateman
Hains Technology Associates 2

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
prefeasibility study concluded that a 30% P 2 O 5 concentrate could be economically
produced.
Companhia Vale do Rio Doce (“Vale”) conducted a site inspection of the Property and
completed mineralogical examination of the rock and laboratory scale beneficiation
studies in 2006. Vale was successful in producing a concentrate grading in excess of 30%
P 2 O 5 and in producing a market specification single superphosphate (SSP) fertilizer from
the concentrate.
Since acquisition of the Property by Stonegate in 2008, the Company has initiated a
program of detailed geological mapping, trenching, drilling, sampling; metallurgical and
mineralogical test work, and community studies in support of advancing the Project to the
prefeasibility stage.
CONCLUSIONS
The deposit is of a marine sedimentary type of syngenetic origin. The deposit lies within
the Mancaspico syncline and is exposed in surface outcroppings as three parallel
mineralized zones extending over a distance of approximately 30 km. Detailed
exploration work on the Philip concession indicates the phosphate mineralization extends
to depths of at least 200 m below surface. Review of available data and the results of the
2009 exploration program indicate the potential for a commercially significant phosphate
deposit.
Trenching and drilling over an approximately 8 km strike length on the Philip concession
demonstrates excellent stratigraphic correlation within the phosphatic sandstone and
mudstone member of the Aramachay Formation. True thickness ranges from +9 m to 35
m. There is a generalized thickening of the deposit towards the southeast. Phosphate
mineralization is in the form of francolite and collophane pellets. Variations in true
thickness of the phosphatic member are due to sedimentological parameters prevalent
during the deposition of the unit. No structural complications or faulted-out portions of
the member are observed.
A program of mineralogical and metallurgical test work conducted by SGS Mineral
Services (Lakefield) and Bateman Advanced Technologies has confirmed the historical
beneficiation work. Laboratory scale tests produced phosphate concentrates ranging from
28.8% (drill core samples) to 32.5% (trench samples) with acceptable phosphate grade
and mass recoveries and quality suitable in the marketplace. The projected phosphate
concentrate grades are suitable for production of merchant grade phosphate rock
concentrate and production of concentrate for use in phosphate fertilizers such as single
superphosphate (SSP) and potentially the ammonium-based phosphate fertilizers DAP
and MAP. Additional test work to improve phosphate concentrate grade, recovery and
quality is planned.
An independent market study conducted by British Sulphur Consultants (“BCS”) for
Stonegate confirms that the Mantaro Project is strategically located to supply phosphate
Hains Technology Associates 3

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
rock and/or upgraded phosphate fertilizer products to regional and international markets
and that the projected grade of phosphate concentrate will be competitive with current
major producers. Slight improvements in beneficiation performance to reduce iron and
alumina levels could yield a premium product. More detailed market analyses are planned
following completion of beneficiation studies.
BCS estimated demand for phosphate concentrate will increase at a rate of 2.9% per
annum during the 2010 – 2020 time period to reach approximately 222 MM tonnes. The
market for internationally traded phosphate concentrate is projected by BCS to increase
from 23 MM tonnes in 2010 to approximately 30 MM tonnes in 2020. Prices for
phosphate concentrate are projected to remain above $100/tonne in real terms during the
forecast period. BCS concluded in its report that the Mantaro Project is strategically
located with respect to existing and emerging demand for phosphate rock and phosphate
fertilizer derivatives; the projected quality of the concentrate is acceptable in the
marketplace; there is considerable merit in examining the potential for SSP production;
and that the Mantaro Project can be expected to be cost competitive.
Current mineral resources on the West zone of the Mantaro Property are estimated as
detailed in Table 1-1 (effective date February 21 st , 2010).
Table 1-1
Estimated Mineral Resources
West zone, Mantaro Property
Resource Class 1 Tonnes 2 P 2 O 5 (%)
Measured 2 5,548,000 10.8
Indicated 2 33,975,000 9.9
Measured + Indicated 2 39,523,000 10.0
Inferred 3 376,265,000 9.0
1 Measured and Indicated are reported using a 4% P 2 O 5 cut-off.
2 Tonnes have been rounded to the nearest 1,000 and the phosphate grade to 1 decimal place.
3 Inferred is reported with no cut-off as an assumed grade of 9% is assumed.
The total estimated Measured plus Indicated and Inferred resources and the grade are
comparable to the large Bayovar phosphate deposit currently under development by Vale
SA in northern Peru.
Insufficient work has been undertaken to estimate mineral resources on the East and Far
East sections of the Mantaro Property. However, these areas have been delineated by
geological mapping and exhibit surface mineralization widths similar to the West zone.
Given that the deposit is of marine sedimentary origin, there is every reason to believe
that comparable grades and depth of mineralization are present within these zones. Based
on this assumption, potential mineral deposits within the East and Far East zones are
estimated to be approximately:
Hains Technology Associates 4

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
East 425-435 MM tonnes @ 9% P 2 O 5
Far East
280-290 MM tonnes @ 9% P 2 O5
These potential quantities and grade are conceptual in nature, there has been insufficient
exploration to define a mineral resource and it is uncertain if further exploration will
result in these targets being delineated as a mineral resource. However, should such
conceptual resources be confirmed by trenching and drilling, the Mantaro Property would
rank as one of the most significant phosphate deposits in the world.
The Property is located in an area of intensive subsistence agriculture. Extensive
community consultations have been conducted during the current exploration work and
are continuing. Community relations discussions are lengthy and impose constraints on
the pace of exploration work. The success of the community relations program in
securing approval for exploration and development activity is key to advancement of the
Project to production.
Availability of sufficient water for mineral processing may be a significant issue. This
aspect will require detailed analysis as the Project advances.
RECOMMENDATIONS
The recommendations follow a phased approach to exploration, metallurgical, market
research and social science work necessary to advance the Project through to the
prefeasibility stage.
Exploration efforts should focus on upgrading the classification of the resource base
within the West zone, and enabling classification of the mineral potential in the East and
Far East zones to at least the Inferred Resource category. This will require a program of
surface mapping, trenching and drilling.
Metallurgical work should focus on enhancements to the beneficiation process to improve
phosphate concentrate grade and recovery and develop preliminary engineering data for
design and costing of a process flow sheet to ±30%.
The geological block model should be enhanced to permit development of preliminary
mine plans and estimation of mining costs to ± 30%.
Market research work should focus on better establishing the potential for sale of
phosphate rock concentrate in the regional market (Peru, Brazil, Chile, Argentina,
Ecuador, Colombia, Mexico) and the international market (Asia/Pacific region, especially
New Zealand). Market research work should also examine the potential for production of
Hains Technology Associates 5

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
SSP and potentially other value added products such as phosphoric acid, DAP and MAP.
Market research work must include an analysis of available transportation options,
including shipments to Brazil using the Amazon river system.
An expanded program of community consultations, archaeological research and
community development designed to cover those areas not covered by the current
program, and deepening of social development activity within the current area of focus
should be implemented.
Assuming positive results from this work in the form of a prefeasibility study, efforts
should then be directed to completing a bankable feasibility study leading to a production
decision.
The following recommendations are made:
PHASE 1
1. Conduct detailed topographic and outcrop surveying of the area north of the
Sincosa concession in the West zone of the deposit. Mapping should be at
1:10 000 scale or better.
2. Relog/resample the existing drill core at 1 m intervals to better define high
grade intersections within lower grade intervals and the nature of the
mineralization.
3. Undertake an enhanced program of community consultations and execute
community agreements prior to initiating any new exploration and
development work.
4. Conduct trenching and drilling at a minimum of 1 km spacing (or closer) on
the West zone between the Sincosa concession and Quicha Grande and
southeast from Quicha Chico to the limits of the Property to upgrade the
resource category.
5. Complete an enhanced program for collection of specific gravity samples to
better categorize the mineralization.
6. Conduct a surface sampling program (and as possible, complemented by
trenching) on the Quicha Chico and Puerta de Piedras concessions (East and
Far East zones) to permit categorization of resources in these areas to at least
the Inferred Resource level. Sampling/trenching work should be on section
with corresponding work in the West zone and spaced at 1 km intervals.
7. Undertake a more extensive program of metallurgical research to enhance
recovery and grade of phosphate concentrate. The focus of the work should be
on improvements to recovery and grade of unoxidized material. Metallurgical
test work should also include test work to determine the reactivity of the
concentrates and the potential for production of SSP, phosphoric acid, DAP
and MAP.
8. Conduct product and market specific analysis of the regional and international
markets for phosphate concentrates, phosphoric acid and phosphate fertilizers.
9. Prepare a NI 43-101 report based on the results of the exploration program.
10. Initiate the process to convert claims to non-metallic claims.
11. Complete a prefeasibility study for the Project.
Hains Technology Associates 6

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
Assuming a successful conclusion to the Prefeasibility Study, proceed to Phase 2.
PHASE 2
Phase 2 is designed as a bankable feasibility study. The work to be conducted in Phase 2
consists of:
1. Complete an EIA for the Property south of the Sincosa concession. This
must include extensive community consultations and securing agreements
from the affected communities for the detailed exploration program.
2. Conduct a program of diamond drilling, sampling and assaying on 250 m
spacing in the West, East and Far East zones south of the Sincosa
concession to the south end of Puerta de Piedras 7. Drilling should be HQ
size. Sampling should be at 1 m intervals within the mineralized zones.
Drilling should target resources down to the 3,400m elevation level. The
indicated drilling is approximately 26,000m, assuming 2 holes per station
and average hole depth of 150m.
3. Construct additional trenches to provide bulk sample material sufficient
for a minimum of 60 tonnes of concentrate. This work to include
necessary sampling and assaying.
4. Collect and process a representative bulk sample from drill core and
trenches sufficient to yield a minimum of 40 tonnes of concentrate.
5. Process trench and drill material to produce representative phosphate
concentrates based on the calculated run-of-mine ore grade. The bulk
sample to be used for market testing and evaluation of the suitability of the
concentrate for SSP, phosphoric acid and DP/MAP production
6. Undertake necessary mine and process plant engineering, transport
logistics and market analyses to develop capital and operating costs to ±10
%.
7. Complete as necessary land purchase agreements for proposed plant site
and mine.
8. Complete a bankable feasibility study for the Project, including full
environmental impact study and agreed community benefits agreement.
BUDGET
The estimated budget for the work outlined above is detailed below:
Hains Technology Associates 7

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
PHASE 1
Item Cost (US$ ‘000)
1. Geological mapping, north of Sincosa 10
2. Relog/resample drill core 5
3. Community consultations program 500
4. West zone trenching/drilling (6,000 m) 1,500
5. Specific gravity sample analysis 5
6a. Surface sampling, QC & PP concessions 40
6b. Trenching/drilling, QC/PP concessions 750
7. Large scale beneficiation studies 300
8. Market analysis 150
9. NI 43-101 report 150
10. Claim conversion/property payments 200
11. Prefeasibility study 1,750
Sub-total 5,360
20 % Contingency 1,00
TOTAL to Completion of Phase 1 6,360
The estimated budget for the work outlined for Phase 2 is detailed below:
Item Cost (US$ ‘000)
1. EIA and community consultation 400
2. Drilling (26,000m @ $175/m) (incl. assays) 4,550
3. Trenching and bulk sampling (incl. assays) 200
4. Bulk sample process test work (to concentrate) 1,500
5. Bulk sample process test work (acid, DAP/
750
MAP, SSP)
6. Mine and process engineering design work,
2,500
logistics analysis, market analysis
7. Land purchase (1,000 ha @ $1,000/ha) 1,000
8. Bankable feasibility study 450
Sub-Total Phase 2 11,350
20 % Contingency $2,250
Total Phase 2 $13,600
TOTAL BUDGET, PHASE 1 AND PHASE 2 $19,960
======
Hains Technology Associates 8

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
TECHNICAL SUMMARY
PROPERTY DESCRIPTION AND LOCATION
Stonegate Agricom (“Stonegate”), through its wholly owned subsidiary, Mantaro Peru
SAC (“MPS”), holds three significant land packages in Peru. The primary property
holding and the focus of this technical report is located northwest of Huancayo on the
west side of the Mantaro River. This property is termed the Mantaro deposit in this
report. It comprises 12,800 ha. (see Figures 4-1 and 4-2 for property location). Additional
mineral claims totaling 7,000 ha, termed the Mantaro East claims in this report, are held
on the east side of the Mantaro River. MPS also holds mineral concessions comprising
1,700 ha known as the Alora concession located approximately 60 km to the north of the
Mantaro Property. Neither the Mantaro East nor Alora properties have been subject to
detailed exploration.
The Mantaro deposit is located approximately 250 km east of Lima, Peru in the Andean
altiplano near the city of Huancayo, Junin District. A paved highway and railway
connects Huancayo with Lima. Access to the Property is primarily from the towns of
Sincos, Aco and Mito via gravel roads and rough tracks to a number of small villages.
Phosphate mineralization on the Property is observed in surface outcrops exposed in three
roughly parallel zones (mantos) extending the length of the Property and a series of
trenches and drill holes in the central portion of the Property extending over a distance of
approximately 12 km. The phosphate mineralization is of marine sedimentary syngenetic
origin and ranges from highly oxidized phosphatic sandstone to phosphatic limestones
and mudstones. The phosphatic zone trends northwest-southeast and dips at 39 0 - 55 0
(typically 45 0 - 48 0 ) to the northeast on the western side. Dips are generally steeper on the
eastern side and oriented to the southwest. Surface exposures average approximately 25
m apparent width (21 m true width).
SITE INFRASTRUCTURE
Regional infrastructure is generally excellent. High tension and local electrical
distribution lines cross the Property. The Doe Run smelter at La Oroya, approximately 60
km to the northwest, is a potential source of sulphuric acid for fertilizer manufacture.
Huancayo is a major regional centre with a population of approximately 300,000 people
and offers excellent services. Huancayo is connected to Lima and the port of Callao by a
major national highway and a railway.
HISTORY
The exploration history of the Property has been described in Hains (2008) and is not
repeated here, except as discussed in Section 6 of this Technical Report.
GEOLOGY
The Mantaro region is located within the Mesozoic fault and fold belt of the Central
Peruvian altiplano. The area is dominated by Jurassic-aged sandstone, shale and
carbonate rocks of the Pucará Group, which occur regionally in a northwest-striking belt
Hains Technology Associates 9

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
extending from north of Cero de Pasco, south to beyond Huancayo, a distance of over
250 km. The sequence has been folded into a series of generally broad, open anticlines
and synclines also of regional extent and up to 25 km wide. Locally intense isoclinal
folding, and various generations of fault development are observed.
The phosphate mineralization is hosted in the Aramachay Formation, an early Jurassic
sequence of shales, sandstones and cherts. They occur as an integral part of the regional
stratigraphic sequence, cropping out around the perimeter of the large Mantaro syncline
extending over 150 km in a SE-NW direction and up to 20 km in a SW-NE direction. The
Aramachay Formation is overlain by the limestones, shales and cherts of the Middle-to-
Late Jurassic Condorsinga Formation and underlain by the Chambara Formation shales
and cherts of Triassic age.
The phosphatic member varies in thickness between 50 – 90 metres. The phosphate is
present as francolite (Ca 5 PO 4 CO 3 ) and collophane (Ca 3 P 2 O 8 H 2 0) pellets and, less
commonly, as fluorapatite (CaF)Ca 2 (PO 4 ) 3 . Lateral facies changes are observed. Within
the member, two fairly persistent phosphatic zones, separated by a chert and cherty
limestone unit, are recognized:
1) A lower blanket zone, 10 m – 15 m thick, which usually occurs below a 10 m
to 30 m thick massive bedded chert and above thick shale and thin shaley
limestone. The zone contains phosphatic bituminous limestone, dark
phosphatic limestone and thin-bedded black chert.
2) The upper phosphatic zone, which is most prominent in the SE part of the
Mantaro deposit. It is up to 50 metres thick and occurs immediately below the
Condorsinga limestones and above the cherty limestone or bedded chert,
which separates it from the lower zone. It is calcareous, sandy and silty, and
lighter in colour than the lower zone due to paucity of the carbonaceous
material. The entire resource in question (Mancaspico deposit) is hosted in
this zone, which is called the phosphatic sandstone and mudstone (PSM). The
Upper zone can be further subdivided into three units characterized by high
silica and medium carbonate (upper zone), low silica and high carbonate
(middle zone) and low phosphate, high silica (lower zone). The Upper zone is
classified as a calcareous phosphate, the Middle zone as a sandy, siliceous
phosphate and the Lower zone as a sandy chert.
EXPLORATION
Stonegate conducted a program of exploration consisting of surface geological mapping,
trenching and drilling in 2009. The surface mapping program covered most of the
Property area and was successful in identifying three roughly parallel zones of
mineralization trending in a NW-SE direction over a strike length exceeding 30 km.
These zones have been termed the West, East and Far East zones of the Mantaro deposit.
Trenching and drilling work was concentrated in the Philip concession portion of the
West zone. Nine new trenches were dug and sampled and two historical trenches also
Hains Technology Associates 10

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
cleaned and sampled. Twenty-three HQ size diamond drill holes totalling 3,414.48 m
tested mineralization at depth across dip and down dip (2 holes). All holes intersected the
full width of the mineralized zone within the Aramachay formation. Surface enrichment
of the mineralization is noted. Oxidized material typically carries 3% - 4% more P 2 O 5
than deeper lying unoxidized material. The depth of oxidation varies but can reach up to
approximately 40 m below surface.
MINERAL RESOURCES AND MINERAL RESERVES
Estimated mineral resources contained in the West zone of the Property (4% P 2 O 5 cutoff)
as of February 21, 2010, are:
Measured 5.548 MM tonnes 1 @ 10.8% P 2 O 5
Indicated 33.975 MM tonnes 1 @ 9.9% P 2 O 5
Measured + Indicated 39.523 MM tonnes 1 @ 10.0 % P 2 O 5
Inferred 2 376.265 MM tonnes 1 @ 9.0% P 2 O 5
1 Tonnes rounded to the nearest 1,000 and grade to 1 decimal place.
2 Inferred material reported with no cut-off and an assumed grade.
There is considerable potential to expand the resource base. The East and Far East zones
of the deposit have been geologically mapped and exhibit surface mineralization widths
similar to the West zone. Given that the deposit is of marine sedimentary origin, there is
every reason to believe that comparable grades and depth of mineralization are present
within the East and Far East zones. Based on this assumption, the potential mineral
deposits within the East and Far East zones are estimated to be approximately:
East zone 425-435 MM tonnes @ 9% P 2 O 5
Far East zone 280-290 MM tonnes @ 9 % P 2 O 5
These potential quantities and grade are conceptual in nature, there has been insufficient
exploration to define a mineral resource and it is uncertain if further exploration will
result in these targets being delineated as a mineral resource. However, should such
conceptual resources be confirmed by trenching and drilling, the Mantaro Property would
rank as one of the most significant phosphate deposits in the world.
ENVIRONMENTAL AND PERMITTING CONSIDERATIONS
The concessions comprising the Property are currently classified as “metallic”, except for
Mantaro 7. Reclassification of the concessions to “non-metallic” will be required if the
Property is to be developed. In addition, some of the concessions comprising the Property
overlap with agricultural lands. The lands designated as agricultural lands will have to be
re-designated as mineral lands. This is part of the process of acquiring an interest in the
lands and reclassifying them as non-metallic for purposes of exploration and development
of the Property.
Hains Technology Associates 11

MANTARO PHOSPHATE DEPOSIT
SPROTT RESOURCE CORP.
Exploration and development activity on the Property is subject to obtaining community
agreement. MPS is actively engaged in an extensive programme of community relations
to ensure its planned exploration activities can be conducted in a timely and cost-effective
manner. This work also includes archaeological research in advance of any intrusive
exploration activity. The success of the community relations program in securing
approval for exploration and development work will be key to advancing the Project to
production.
No surface water is available on the Property. Design provisions to ensure adequate water
supply for process operations will be required if the Property is to be placed in
production.
Hains Technology Associates 12

APPENDIX “F”
PARIS HILLS TECHNICAL REPORT SUMMARY
[SEE NEXT PAGE]

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 1
1.0 SUMMARY
Sprott Resource Corp. (Sprott) is a Toronto, Ontario, Canada, based company that invests
and operates through its subsidiaries in the natural resource sector. Sprott is listed on the
Toronto Stock Exchange under the stock symbol TSX:SCP. Agapito Associates, Inc. (AAI) was
commissioned by Sprott to provide an independent Qualified Person’s (QP) review and National
Instrument (NI) 43-101 Technical Report (TR) on the Paris Hills Phosphate Project (the
Property) located near the town of Bloomington in Bear Lake County, Idaho, United States of
America (USA). Sprott has interests in the Property through their share ownership of Stonegate
Agricom Inc. (Stonegate) which, in turn, has rights to the Property through their wholly owned
subsidiary Paris Hills Agricom Inc. (PHA). Stonegate is a Toronto, Ontario, Canada, based
mining development company (stock symbol TSX:ST) in the business of acquiring, exploring,
and developing mineral resource properties to production in Canada, the USA, and
internationally.
This report incorporates information from a maiden NI 43-101 report prepared for Rocky
Mountain Resources Corp. (RMP), and two subsequent NI 43-101 reports prepared for Stonegate
(AMEC Americas Limited [AMEC] 2010; AAI 2011).
PHA acquired rights to the Property from RMP on 04 November 2009. Stonegate has
since acquired additional mineral leases which are described in Item 4.1—Mineral Surface and
Land Tenure.
1.1 Location, Access, and Infrastructure
The Property is located in Bear Lake County, Idaho, 3.2 kilometers (km) west of the
towns of Paris and Bloomington.
Adequate surface rights have been obtained to support mining operations on the Property,
but additional rights may be required for processing facilities, waste management, and
infrastructure. Sources for water and electric power have been locally developed, but rights or
agreements will need to be secured. The Union Pacific Railroad (UP) provides freight services
to Bear Lake County from an office located in Montpelier. The track through Montpelier
connects into the UP system at Pocatello, Idaho and Green River, Wyoming.
Paris Hills is located in the state of Idaho, United States of America, a state with a
reputation of being a “business friendly” jurisdiction. Idaho was ranked 33 rd out of 79
jurisdictions evaluated in the 2010/2011 Fraser Institute report on ranking of political policy
towards mining, suggesting that new mining projects can be built in Idaho.
All costs are expressed in fourth quarter 2011 United States Dollars (USD or $) unless
otherwise noted.
1.2 Tenure and Surface Rights
The Property encompasses an area of approximately 1,008 hectares (ha). Property
holdings consist of 3 patented lode mining claims and 18 contiguous fee parcels (some with
federal mineral reservations) covering portions of Sections 8, 9, 10, 15, 16, 17, 21 and 22 of
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 2
Township 14 South, Range 43 East (T14S, R43E) in Bear Lake County. The Property comprises
federal, state, and private land holdings with various property rights and royalty agreements in
place.
PHA has secured the rights to conduct exploration for phosphate and metalliferous
minerals on all parcels comprising the Property through federal and state exploration permits and
private agreements. Reasonable prospects exist for PHA to obtain the required permits and
approvals to conduct mine operations.
1.3 Geology
Phosphate and vanadium beds of the Western Phosphate Field occur within the Permian
Phosphoria Formation. Permian rocks in and adjacent to the Western Phosphate Field consist of
a chert-mudstone-phosphorite facies in eastern Idaho and southwestern Montana. These beds
intertongue with a sandstone facies toward the northeast and a carbonate facies toward the east
and south. Further east and south the interval is represented by red bed facies dominant in
eastern Wyoming and northwestern Colorado.
The phosphate and vanadium-rich mineralized beds occur in the horizontal and upturned
to overturned limb of the Paris Syncline. The mineralized beds plunge northwest between 12
and 20 degrees (°) along the west-dipping, north-plunging horizontal limb of the syncline. The
horizontal limb contains the principal resource target. A significant portion of the mineralization
is contained in the steeply dipping, upturned to overturned limb of the syncline. The
mineralization is hosted in the Meade Peak Member of the Permian Phosphoria Formation which
is currently mined in open pits 50 km to the north near Soda Springs by the three major Idaho
phosphate producers. The PHA phosphate is of similar character to that being mined at Soda
Springs.
The target phosphate mineralization is contained in two zones (beds) termed the Upper
and Lower Phosphate Zones (UPZ and LPZ), which range in depth from outcrop to more than
1,000 meters (m) deep. Vanadium is contained in the Vanadium Zone (VZ) located immediately
below the UPZ. Mineralization in the overturned limb has a strike length of over 3 km on the
Property.
1.4 History
Historical work on the Property area began with location of a claim in Little Canyon in
1903 at the future site of the Consolidated Mine. The property changed ownership several times
before being acquired by Solar Development Company, Ltd. Solar in 1930. Solar sunk a 61-m
decline and ran two lateral drifts totaling 1,066 m of underground development. A total of 3,175
tonnes (t) of phosphate ore were shipped. The Property was optioned to Wyodak Coal
Manufacturing Company (Wyodak) in 1942, after which little activity occurred until Earth
Sciences, Inc. (ESI) acquired the holdings from the remaining landowners in 1973.
The Paris Canyon Mine was formed by two homestead patents granted by the United
States General Land Office (GLO) in 1901 and 1913. Up to 54,000 t of phosphate was produced
by 1919. By 1925, the total underground workings comprised 915 m of tunnels, drifts, winzes,
and crosscuts.
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 3
Early work in the Consolidated and Paris Canyon Mines noted the presence of vanadium
along with the phosphate. Vanadium became an important strategic material during World
War II. The United States Geological Survey (USGS) began exploration work in the Paris-
Bloomington area in 1942 focusing in Paris, Bloomington, and Little Canyons.
During the 1970s, ESI assembled a project area of approximately 1,660 ha which
included the old Consolidated Mine, the Paris Canyon Mine, the Bloomington Mine, and the
Bear Lake Mine. From 1973 through 1977, ESI conducted exploration and development work,
consisting of rotary and core drill holes, surface trenches, and two test mines.
In 1972, ESI drove a test drift 45 m on an outcrop in Bloomington Canyon. In 1973, the
drift was extended to the west and north until a major fault was encountered at approximately
215 m from the portal. An offset drift was driven 60 m east to intercept the VZ. In 1975, 825 m
of workings were developed in the UPZ for bulk metallurgical testing. Approximately 38,000 t
of phosphate ore and waste were mined. ESI activity continued through the late-1970s. ESI held
much of the property package until it was relinquished in the early 1990s.
In August 2008, RMP assembled a property position comprising 856 ha which included
the sites of the former Consolidated, Bloomington Canyon, and Paris Canyon Mines. RMP
completed six reverse circulation (RC) drill holes on the southern end of the Property. The
purpose of the drilling was to confirm the results reported by ESI to form the basis for an NI
43-101 TR.
A total of 53 historical exploration holes were drilled by ESI and RMP, comprising 15
RC holes (3,594 m), 15 core holes (3,031 m), 10 undefined holes (1,888 m), and 13 holes with
no records.
PHA and RMP executed an agreement on 24 September 2009 where PHA acquired the
collective interests of RMP, including all federal, state, and private agreements. The agreement
was executed on 04 November 2009 granting PHA control of the core Property. PHA
subsequently expanded the Property to include additional federal leases and private properties.
Vanadium mineral reserves on the Property were reported as early as 1944 by Wyodak in
conjunction with the USGS and United States Bureau of Mines (USBM). ESI reported
vanadium and phosphate reserves in 1976–77 following their exploration drilling program. The
historical reserves, while technically important, are not compliant with NI 43-101 standards.
1.5 Exploration
PHA acquired the holdings from RMP in September 2009 which included the interests to
all Mineral Lease Agreements, rights to the State of Idaho exploration permits, a federal lease,
and rights to a federal prospecting permit application. Since acquiring these holdings, PHA has
secured the transfer of the Mineral Lease Agreements and reissued the State of Idaho exploration
permits. PHA applied for approval to drill on the federal phosphate lease and was granted
permission in September 2011. PHA applied for and was granted approval for a federal
prospecting permit and a federal exploration license in October 2011. Also, PHA entered into
five mineral lease agreements expanding the original RMP property boundary in 2011 and 2012.
See Item 3.0—Property Tenure and Permits for details.
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 4
PHA commenced a drilling program in September 2010 and continued to drill and assay
through 10 November 2011 for reporting in AAI (2011). This report includes drilling and assay
data to 10 February 2012.
To estimate a Measured and Indicated (M&I) NI 43-101 compliant resource, PHA is
drilling to delineate the phosphate mineralization within the property boundary. AAI’s
recommended drilling density was 0.4 km for Measured and 0.8 km for Indicated Resources in
areas of the eastern horizontal limb. Closer-spaced drilling was recommended in the vicinity of
faults, the overturned (upturned) limb, and at the southern boundary of the property, which is
required for local structural definition. PHA’s current exploration plans are to target the LPZ in
the horizontal limb first and then the UPZ and overturned limb. The latter is identified in the
AAI (2011) TR as an exploration target.
Drilling was contracted to Major Drilling Group International Inc. (Major) who were
mobilized out of Salt Lake City, Utah, for both RC and core drilling activities. Exploration
drilling on the federally controlled (United States Bureau of Land Management [BLM]) portion
of the Property occurred in October and November 2011, following approval by BLM and
issuance of exploration permits.
A combined total of 19,688 m have been drilled in 73 holes, approximately 6,514 m of
which were cored. Thirty-three holes were used in the current resource estimate; these include
12 holes in addition to the 21 included in AAI (2011). The criteria for holes used in the resource
estimate are (1) greater than 90% core recovery in the LPZ and (2) assays completed by one of
the two reliable, independent, and industry-recognized laboratories. Two exceptions to the
stipulated 90% core recovery are from PA070 with 88.9% and PA Sub3 Adit with 86.8%
recovery; the latter is acceptable as it is an area of high drill density. Fourteen drill holes were
lost due to difficult ground conditions.
The early drilling campaign achieved poor core recovery and produced incomplete data
sets. This was later addressed with the introduction of a strict protocol and procedure. If core
recovery was less than targeted, holes were re-drilled. All holes were re-logged, re-measured,
and depth-corrected to gamma geophysical logs. Where previous sampling made reconstruction
difficult or impossible, photographic records were reviewed to determine core recovery.
Initial testing by ALS (ALS) Chemex’s Vancouver laboratory revealed bias in the
phosphorus pentoxide (P 2 O 5 ) assays and erratic results in some secondary quality parameters,
prompting the decision to switch laboratories in June 2011. A detailed sample protocol was
designed for the retesting and ongoing testing. IAS EnviroChem (EnviroChem) of Pocatello,
Idaho, and Thornton Laboratories Testing & Inspection Services (Thornton) of Tampa, Florida,
were selected for re-assaying pulp samples and samples from new holes with greater than 90%
core recovery. Both laboratories have phosphate testing experience. Results of the two
laboratories showed strong agreement. Standards and blank reference material confirmed
reliability and showed good accuracy and precision at both laboratories.
Based on a review of the exploration program, the QPs are confident that early problems
of core recovery, sampling, and assay bias have been resolved and that the exploration dataset
used in this resource estimate meets the criteria for use under NI 43-101. PHA’s quality
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 5
assurance/quality control (QA/QC) program is designed with aggressive duplication and
insertion. Procedures are well documented and have been followed accordingly.
Five trade seismic lines were acquired for reprocessing to assist in interpretation of
regional structure. RPS Boyd PetroSearch (Boyd) reprocessed two-dimensional (2D) seismic
trade lines, one on a north-south line and four on east-west lines. Structure on top of the Rex
Chert Member, LPZ, and the Wells Formation was mapped and tied into historical fault trends.
The preliminary analysis confirms the structural dip of the strata previously identified from the
drill holes and shows various faults crossing the property, including major normal faults which
bound the deposit near the eastern property line. The age and the quality of the raw data
precluded detailed depth or structural mapping.
1.6 Metallurgical and Processing
Preliminary metallurgical testing was conducted by Jacobs Engineering S.A. (Jacobs) in
2011 and 2012, an independent, industry-recognized Florida-based process engineering firm.
Tests were conducted on composite core samples from the LPZ and UPZ. Jacobs’ phosphoric
acid pilot plant demonstrated that merchant grade phosphoric acid (MGA) and granular
fertilizers could be produced from the LPZ material without beneficiation, supporting the
potential for producing direct ship phosphate ore (DSO) from the LPZ if targeted grades can be
achieved during mining. Both monoammonium phosphate (MAP) and diammonium phosphate
(DAP) granular fertilizers were produced from concentrated phosphoric acid. Testing of the
UPZ determined that some beneficiation would be required to produce marketable phosphate
rock. No testing was completed for the VZ. Additional ore characterization and fertilizer test
work is in process.
1.7 Mineral Resource and Mineral Reserve Estimates
The mineral resource for the Paris Hills Property comprises the UPZ, VZ, and LPZ,
which together cover a plan area of 778 ha of the 1,008-ha Property. The Mineral Resource
estimate for the principal mineralized target, the LPZ, is based on 3,918 m of core drilling and
chemical analyses on core from 33 exploration holes drilled by PHA in 2011-2012. The UPZ
and VZ are considered Exploration Targets, for which estimates of mineralization are based on
historical, NI 43-101 non-compliant exploration data collected prior to PHA’s exploration
program.
The mineral resource estimate was prepared by Leo J. Gilbride, P.E., Senior Consultant
with AAI, member of the Society for Mining, Metallurgy, and Exploration, Inc., and a QP for
this TR. The mineral resource estimate has an effective date of 26 March 2012.
1.7.1 Mineral Resources
Mineral Resources were estimated using a kriged gridded-seam computer geologic model
constructed with Carlson Mining 2011 Software. Mineral Resource classifications based on
the technical methodology of the Sedimentary Phosphate Resource Classification System of the
USBM and the USGS (Geological Survey Circular 882, 1982). The Mineral Resource
calculations are compliant with Canadian Institute of Mining, Metallurgy and Petroleum (CIM)
Best Practice Guidelines for Industrial Minerals.
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 6
Table 1-1 summarizes the LPZ phosphate Mineral Resource for the Property. The
Mineral Resource assumes a minimum LPZ composite cutoff grade of 24.0% P 2 O 5 and a
minimum bed thickness of 1.0 m, targeting a DSO concentrate in excess of 29.5% P 2 O 5 . In 33
core holes, the LPZ thickness ranged from 1.1 to 2.9 m with composite grades ranging from
24.5% to 34.3% P 2 O 5 . The LPZ averages 1.8 m thick across the Property. Phosphate tonnages
are based on an average dry bulk density of 2.6 tonnes per cubic meter (t/m 3 ) derived from 36
laboratory bulk density tests on representative LPZ core.
1.7.2 Mineral Reserves
Mineral Reserves were estimated via a Preliminary Feasibility Study (PFS)
commissioned by PHA that established economic viability for the Property. A gridded-seambased
geologic model was used with a room-and-pillar mine projection layout to develop timing
maps, tonnage, and ore grade estimates for the eastern flat limb of the Property. Table 1-2
summarizes the LPZ phosphate Mineral Reserves.
Approximately 10 million tonnes (Mt) of crushed phosphate rock concentrate averaging
29.4% P 2 O 5 are projected to be mined and direct shipped without further processing. The QP’s
have reviewed the PFS and consider it to be reasonable in its methodology and conclusions.
1.7.3 Exploration Targets
Table 1-3 summarizes the Exploration Targets for the Property.
Insufficient exploration information is available to support the estimation of an NI 43-101
Mineral Resource in the upturned limb of the Paris Syncline, although it is expected to contain
significant mineralization. Historical trenching along outcrop and historical test mining confirm
the persistence of mineralization in the upturned limb; however, no exploration drill holes
penetrate the upturned limb and no information is available at depth.
While copious historic data exist for demonstrating the presence of mineralization in the
UPZ and VZ in the horizontal limb of the Paris Syncline, the quality of those data is substandard
for application to NI 43-101 compliant Mineral Resource estimation and all estimates of
mineralization are classified as Exploration Targets until compliant data can be acquired.
The Exploration Targets, as stated, are conceptual in nature and there has been
insufficient exploration to define them as Mineral Resources, and it is uncertain if further
exploration will result in the determination of a Mineral Resource under NI 43-101. The
Exploration Targets are not being reported as part of any Mineral Resource or Mineral
Reserve.
1.8 Conclusions
The Paris Hills Property contains significant phosphate mineralization in sufficient
quantities and of sufficient grade to be attractive for mining under current market conditions,
notwithstanding the risk inherent to proving and developing any mining property. Vanadium
represents upside mining potential. Geologic continuity in the mineralized beds is strong
throughout the Property.
Agapito Associates, Inc.

Agapito Associates, Inc.
Average
Thickness
(m)
Table 1-1. Mineral Resource of the Lower Phosphate Zone—Horizontal Limb (effective date 26 March 2012)
Resource
Area
(sq km)
In-Place
Tonnes †,‡
(millions)
P 2O 5
(wt %)
Fe 2O 3
(wt %)
Al 2O 3
(wt %)
MgO
(wt %)
MER
Na 2O
(wt %)
K 2O
(wt %)
CaO
(wt %)
CaO:P 2O 5
Acid
Insoluble
(wt %)
Measured 1.8 2.58 12.2 30.5 0.51 0.99 0.27 0.059 0.98 0.31 45.8 1.50 7.3 2.14
Indicated 1.7 2.25 10.1 29.7 0.51 0.89 0.29 0.056 0.99 0.28 45.5 1.52 6.1 2.69
Total M&I 1.8 4.82 22.3 30.1 0.51 0.94 0.28 0.057 0.98 0.29 45.7 1.51 6.8 2.39
Inferred 1.7 1.85 8.1 29.3 0.51 0.86 0.29 0.055 0.98 0.28 45.3 1.52 5.7 2.81
† Average in-situ bulk dry density of 2.6 t/m 3 .
‡ Zone thickness cutoff 1.0 m, composite grade cutoff 24.0% P 2O 5, excludes out-of-seam dilution.
Table 1-2. Mineral Reserve of the Lower Phosphate Zone—Horizontal Limb (effective date 26 March 2012)
P₂O₅ Fe₂O₃ Al₂O₃ MgO Na₂O K₂O CaO CaO/P₂O₅ Acid Organic
Tonnes †, ‡ Thickness Grade Grade Grade Grade MER Grade Grade Grade Ratio Insoluble Carbon
(m) (wt %) (wt %) (wt %) (wt %) (wt %) (wt %) (wt %) (wt %) (wt %)
Proven 5,167,101 1.8 30.0 0.56 1.07 0.44 0.069 0.95 0.32 45.22 1.51 8.30 2.07
Probable 4,848,361 1.7 28.8 0.54 0.93 0.58 0.071 0.96 0.29 44.95 1.56 6.59 2.71
Reserves 10,015,462 1.8 29.4 0.55 1.00 0.50 0.070 0.96 0.31 45.09 1.53 7.47 2.38
† Average in-situ bulk dry density of 2.6 t/m 3 .
‡ Minimum mining height of 1.5 m + 0.15 m dilution.
Organic
Carbon
(wt %)
NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 7

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 8
Bed Location Cutoff
(wt %)
In-Place
Tonnes
(millions)
V 2O 5
(wt %)
P 2O 5
(wt %)
20.0% P 2 O 5 60 to 80 — 21.0 to 25.0
Upper Phosphate
Zone
Vanadium Phosphate
Zone
Lower Phosphate
Zone
Table 1-3. Paris Hills Exploration Targets
Horizontal and upturned
limbs of Paris Syncline
Horizontal and upturned
limbs of Paris Syncline
Upturned limb of Paris
Syncline
0.50% V 2 O 5 32 to 44 0.70 to 0.80 8.0 to 11.0
24.0% P 2 O 5 7 to 10 — 28.0 to 32.0
The Property is suited to underground mining because of the depth to mineralization.
Limited mineralization near outcrop has potential to be surface mined. Room-and-pillar and/or
longwall mining are considered the best prospective methods for mining the beds in the
relatively flat-lying horizontal limb. The upturned limb of the syncline is likely best suited to
cut-and-fill mining, shrinkage stoping, or another similar method, considering its high-angle
geometry and provided that geomechanical conditions prove favorable for economic extraction.
PHA has developed a PFS that concludes that underground mining the east limb of the
Property is economic. Table 1-4 summarizes the economic analysis for the project.
Table 1-4. Net Present Value, Internal Rate of Return and Payback
Discount rate 8 %
NPV pre-tax
$241.7 million
NPV after-tax
$179.4 million
IRR pre-tax 31 %
IRR after-tax 27 %
Payback pre-tax from start of production
4.6 years
Payback after-tax from start of production
4.7 years
Notes:
Start of production begins in Project Year +1
Initial Project Capital = Project Years –2 through +3
Principal risks associated with developing the Property are geologic and market-side risk.
Ground conditions during mining are anticipated to be similar to coal mining, which can vary
considerably. The phosphate material and surrounding strata are comprised of phosphorite,
mudstones, shales, and limestones of varying strength and weatherability. Potential exists for
weak roof, rib, and/or floor conditions. This can be exacerbated by groundwater. Groundwater
exists throughout the mining horizon and over much of the Property, and will be addressed
through a series of dewatering wells. While weak and wet conditions are not necessarily outside
the range of ordinary bedded deposit mining conditions, risk arises from the potential for out-of-
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 9
seam rock diluting the LPZ DSO product. Depending upon degree, dilution can result in lower
product prices and exclusion from some markets.
Current assessment of the deposit shows characteristics well within market specifications
for P 2 O 5 , minor element ratio (MER) and CaO/P 2 O 5 . Fertilizer testing confirmed the ability to
make DAP and MAP. Blending to control quality parameters will likely be necessary to control
specifications for a consistent product to the market. Parameters such as uranium (U), selenium
(Se) and cadmium (Cd) were not reviewed for the possibility of affecting marketability and cost
of mitigation.
1.9 Recommendations
The LPZ warrants evaluation of the base case, direct ship, room-and-pillar mining
scenario and associated tradeoffs at the Feasibility Study (FS)/test mine level to advance the
Paris Hills underground mine (the Project) to development.
PHA should proceed with a FS for the Project. The FS should include additional work in
the following areas:
Geology/Exploration—Continue infill drilling, expand drilling to the north, conduct
additional mapping to improve understanding of faults and fracture zones. Estimated
cost is $2 million to $3 million.
Seismic Surveying—Conduct a high resolution 2D or 3D seismic survey. Needed for
final mine design. Estimated cost is $1.5 million to $2.0 million.
Geotechnical—Conduct additional geotechnical analysis of the LPZ. Two- or threedimensional
numerical modeling is advised for final mine design. Estimated cost is
$50,000.
Mining Design and Equipment—Refine room-and-pillar mine plans. Develop minespecific
equipment requirements/modifications with manufacturers. Conduct methane
desorption test, reevaluate Sigra (horizontal stress) testing. Estimated cost is $300,000 to
$500,000.
Processing—Conduct a second phase of fertilizer testing. Estimated cost is up to
$250,000.
Project Permitting and Regulatory Agencies—Proceed with environmental and other
regulatory requirements, collect baseline data, consult with key agencies. Estimated cost
is $1.5 million to $3.0 million.
Utilities—Establish rates for the FS.
Hydrogeologic/Groundwater Analysis (geochemistry)—Continue groundwater data
collection, conduct pumping tests, install monitoring wells, develop a water well injection
plan, and refine the surface and groundwater balance. Conduct whole rock elemental
analysis. Estimated cost is $2 million to $3 million.
Marketing—Continue marketing development to refine and pinpoint marketing
alternatives. Estimated cost is $50,000 to $100,000.
Agapito Associates, Inc.

NI 43-101 Technical Report, Paris Hills Phosphate Project, Bloomington, Idaho, USA
Prepared for Sprott Resource Corp.
26 March 2012 Page 10
Community Relations—Continue to foster stakeholder support.
Risk Assessment / Risk Management—Develop a risk management plan and conduct risk
matrix analysis. Estimated cost is $30,000 to $50,000.
Total estimated cost for the FS is $7.7 million to $12.0 million.
Some additional recommendations for exploration and development are listed below.
Completion of these expenditures will not be required for the FS.
Upper Phosphate Zone—Expand data collection and conduct a NI 43-101 TR resource
estimate and preliminary economic assessment. Estimated cost is $200,000 to $400,000.
Upturned Limb Phosphate Resource Estimate—Conduct an exploration program on the
upturned limb for a NI 43-101 TR resource estimate. Estimated cost is $1 million.
Land—Continue to acquire control of key properties needed for the surface facilities and
infrastructure. Estimated cost is $2.5 million to $3 million.
Agapito Associates, Inc.

APPENDIX “G”
AUDIT COMMITTEE CHARTER
[SEE NEXT PAGE]

SPROTT RESOURCE CORP.
AUDIT COMMITTEE CHARTER
(Adopted by the Board on December 19, 2008)
I. Mandate and Purpose of the Committee
The Audit Committee (the “Committee”) of the board of directors (the “Board”) of Sprott
Resource Corp. (the “Company”) is a standing committee of the Board whose primary function
is to assist the Board in fulfilling its oversight responsibilities relating to:
(a)
(b)
(c)
(d)
(e)
(f)
the integrity of the Company’s financial statements;
the Company’s compliance with legal and regulatory requirements, as they relate
to the Company’s financial statements;
the qualifications, independence and performance of the Company’s auditor;
internal controls and disclosure controls;
the performance of the Company’s internal audit function; and
performing the additional duties set out in this Charter or otherwise delegated to
the Committee by the Board.
II.
Authority
The Committee has the authority to:
(a)
(b)
engage and compensate independent counsel and other advisors as it
determines necessary or advisable to carry out its duties; and
communicate directly with the Company’s auditor.
The Committee has the authority to delegate to individual members or subcommittees of the
Committee.
III.
Composition and Expertise
The Committee shall be composed of a minimum of three members, each whom is a director of
the Company. Each Committee member must be “independent” and “financially literate” as
such terms are defined in applicable securities legislation.
Committee members shall be appointed annually by the Board at the first meeting of the Board
following each annual meeting of shareholders. Committee members hold office until the next
annual meeting of shareholders or until they are removed by the Board or cease to be directors
of the Company.
The Board shall appoint one member of the Committee to act as Chair of the Committee. If the
Chair of the Committee is absent from any meeting, the Committee shall select one of the other
members of the Committee to preside at that meeting.

2
IV.
Meetings
The Committee shall meet at least four times per year and as many additional times as the
Committee deems necessary to carry out its duties. The Chair shall develop and set the
Committee’s agenda, in consultation with other members of the Committee, the Board and
senior management.
Notice of the time and place of every meeting shall be given in writing to each member of the
Committee, at least 24 hours (excluding holidays) prior to the time fixed for such meeting. The
Company’s auditor shall be given notice of every meeting of the Committee and, at the expense
of the Company, shall be entitled to attend and be heard thereat. If requested by a member of
the Committee, the Company’s auditor shall attend every meeting of the Committee held during
the term of office of the Company’s auditor.
A majority of the Committee shall constitute a quorum. No business may be transacted by the
Committee except at a meeting of its members at which a quorum of the Committee is present
in person or by means of such telephonic, electronic or other communications facilities as permit
all persons participating in the meeting to communicate with each other simultaneously and
instantaneously.
The Committee may invite such directors, officers and employees of the Company and advisors
as it sees fit from time to time to attend meetings of the Committee.
The Committee shall meet without management present whenever the Committee deems it
appropriate.
The Committee shall appoint a Secretary who need not be a director or officer of the Company.
Minutes of the meetings of the Committee shall be recorded and maintained by the Secretary
and shall be subsequently presented to the Committee for review and approval.
V. Committee and Charter Review
The Committee shall conduct an annual review and assessment of its performance,
effectiveness and contribution, including a review of its compliance with this Charter. The
Committee shall conduct such review and assessment in such manner as it deems appropriate
and report the results thereof to the Board.
The Committee shall also review and assess the adequacy of this Charter on an annual basis,
taking into account all legislative and regulatory requirements applicable to the Committee, as
well as any guidelines recommended by regulators or the Toronto Stock Exchange and shall
recommend changes to the Board thereon.
VI.
Reporting to the Board
The Committee shall report to the Board in a timely manner with respect to each of its meetings
held. This report may take the form of circulating copies of the minutes of each meeting held.
VII.
Duties and Responsibilities
(a)
Financial Reporting

3
The Committee is responsible for reviewing and recommending approval to the
Board of the Company’s annual and interim financial statements, MD&A and
related news releases, before they are released.
The Committee is also responsible for:
(i)
(ii)
(iii)
(iv)
(v)
being satisfied that adequate procedures are in place for the review of
the Company’s public disclosure of financial information extracted or
derived from the Company’s financial statements, other than the public
disclosure referred to in the preceding paragraph, and for periodically
assessing the adequacy of those procedures;
engaging the Company’s auditor to perform a review of the interim
financial statements and receiving from the Company’s auditor a formal
report on the auditor’s review of such interim financial statements;
discussing with management and the Company’s auditor the quality of
generally accepted accounting principles (“GAAP”), not just acceptability
of GAAP;
discussing with management any significant variances between
comparative reporting periods; and
in the course of discussion with management and the Company’s
auditor, identifying problems or areas of concern and ensuring such
matters are satisfactorily resolved.
(b)
Auditor
The Committee is responsible for recommending to the Board:
(i)
(ii)
the auditor 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 Company’s auditor.
The Company’s auditor reports directly to the Committee. The Committee is
directly responsible for overseeing the work of the Company’s auditor engaged
for the purpose of preparing or issuing an auditor’s report or performing other
audit, review or attest services for the Company, including the resolution of
disagreements between management and the Company’s auditor regarding
financial reporting.
(c)
Relationship with the Auditor
The Committee is responsible for reviewing the proposed audit plan and
proposed audit fees. The Committee is also responsible for:
(i)
establishing effective communication processes with management and
the Company’s auditor so that it can objectively monitor the quality and

4
effectiveness of the auditor’s relationship with management and the
Committee;
(ii)
(iii)
(iv)
receiving and reviewing regular feedback from the auditor on the
progress against the approved audit plan, important findings,
recommendations for improvements and the auditor’s final report;
reviewing, at least annually, a report from the auditor on all relationships
and engagements for non-audit services that may be reasonably thought
to bear on the independence of the auditor; and
meeting in camera with the auditor whenever the Committee deems it
appropriate.
(d)
Accounting Policies
The Committee is responsible for:
(i)
(ii)
(iii)
(iv)
reviewing the Company’s accounting policy note to ensure completeness
and acceptability with GAAP as part of the approval of the financial
statements;
discussing and reviewing the impact of proposed changes in accounting
standards or securities policies or regulations;
reviewing with management and the auditor any proposed changes in
major accounting policies and key estimates and judgments that may be
material to financial reporting;
discussing with management and the auditor the acceptability, degree of
aggressiveness/conservatism and quality of underlying accounting
policies and key estimates and judgments; and
(v) discussing with management and the auditor the clarity and
completeness of the Company’s financial disclosures.
(e)
Risk and Uncertainty
The Committee is responsible for reviewing, as part of its approval of the
financial statements:
(i)
(ii)
uncertainty notes and disclosures; and
MD&A disclosures.
The Committee, in consultation with management, will identify the principal
business risks and decide on the Company’s “appetite” for risk. The Committee
is responsible for reviewing related risk management policies and recommending
such policies for approval by the Board. The Committee is then responsible for
communicating and assigning to the applicable Board committee such policies
for implementation and ongoing monitoring.

5
The Committee is responsible for requesting the auditor’s opinion of
management’s assessment of significant risks facing the Company and how
effectively they are managed or controlled.
(f)
Controls and Control Deviations
The Committee is responsible for reviewing:
(i)
(ii)
the plan and scope of the annual audit with respect to planned reliance
and testing of controls; and
major points contained in the auditor’s management letter resulting from
control evaluation and testing.
The Committee is also responsible for receiving reports from management when
significant control deviations occur.
(g)
Compliance with Laws and Regulations
The Committee is responsible for reviewing regular reports from management
and others (e.g. auditors) concerning the Company’s compliance with financial
related laws and regulations, such as:
(i)
(ii)
(iii)
(iv)
tax and financial reporting laws and regulations;
legal withholdings requirements;
environmental protection laws; and
other matters for which directors face liability exposure.
VIII.
Non-Audit Services
All non-audit services to be provided to the Company or its subsidiary entities by the Company’s
auditor must be pre-approved by the Committee.
IX.
Submission Systems and Treatment of Complaints
The Committee is responsible for establishing procedures for:
(a)
(b)
the receipt, retention and treatment of complaints received by the Company
regarding accounting, internal accounting controls, or auditing matters; and
the confidential, anonymous submission by employees of the Company of
concerns regarding questionable accounting or auditing matters.
X. Hiring Policies
The Committee is responsible for reviewing and approving the Company’s hiring policies
regarding partners, employees and former partners and employees of the present and former
auditor of the Company.