1. business and industrial
2. energy
3. natural gas

SPROTT RESOURCE CORP.
Annual Information Form
March 3, 2015
TABLE OF CONTENTS
Page
ABBREVIATIONS
1
CONVERSIONS
1
GENERAL INFORMATION
2
FORWARD-LOOKING INFORMATION AND STATEMENTS
2
PUBLIC DISCLOSURE BY INVESTMENTS
3
COMPANY OVERVIEW
4
Investment Strategy
5
Investment Process
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Competitive Advantage
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CORPORATE STRUCTURE
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Name, Address and Incorporation
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Intercorporate Relationships
6
CAPITAL STRUCTURE
7
EMPLOYEES
7
GENERAL DEVELOPMENT OF THE BUSINESS
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Three-Year History
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ENERGY SECTOR
10
Long Run Exploration Ltd.
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Independence Contract Drilling, Inc.
11
InPlay Oil Corp.
12
One Earth Oil and Gas Inc.
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Energy Sector Overview
13
MINING SECTOR
17
Corsa Coal Corp.
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Potash Ridge Corporation
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Stonegate Agricom Ltd.
17
Mining Sector Overview
18
AGRICULTURE SECTOR
20
Union Agriculture Group
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One Earth Farms Corp.
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Agriculture Sector Overview
21
RISK FACTORS
23
Risks Relating to the Company Generally
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Risks Relating to the Energy Sector
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Risks Relating to the Mining Sector
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Risks Relating to the Agriculture Sector
40
ENVIRONMENTAL POLICY
46
DIVIDENDS
46
MARKET FOR SECURITIES
47
DIRECTORS AND OFFICERS
48
Name, Occupation and Security Holdings
48
Cease Trade Orders, Bankruptcies, Penalties or Sanctions
49
Conflicts of Interest
50
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TABLE OF CONTENTS
(continued)
Page
AUDIT COMMITTEE INFORMATION
50
The Audit Committee's Charter
50
Composition of the Audit Committee
50
Relevant Education and Experience
51
Pre-Approval Policies and Procedures
51
External Auditor Service Fees (By Category)
52
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
52
TRANSFER AGENT AND REGISTRAR
52
MATERIAL CONTRACTS
52
Amended and Restated MSA
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Partnership Agreement
53
INTERESTS OF EXPERTS
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Names and Interests of Experts
54
ADDITIONAL INFORMATION
54
APPENDIX "A"
Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1)
APPENDIX "B"
Report on Reserves by McDaniel & Associates Consultants Ltd. (Form 51-101F2)
APPENDIX "C"
Report of Management and Directors on Oil and Gas Disclosure (Form 51-101F3)
APPENDIX "D"
Audit Committee Charter
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ABBREVIATIONS
Oil and Natural Gas Liquids
Natural Gas
bbl
bbls
Mbbls
bbls/d
NGL
Mcf
MMcf
Mcf/d
MMcf/d
MMbtu
barrel
barrels
thousand barrels
barrels per day
natural gas liquids
thousand cubic feet
million cubic feet
thousand cubic feet per day
million cubic feet per day
millions of British thermal units
Other
AECO
API
°API
Boe
Boe/d
Btu
LT
MBoe
MM$
MMboe
WTI
$
$000s
Alberta Energy Company (Canada), a storage and exchange point for Canadian natural gas located within Alberta, Canada for
which the reference price paid for Alberta, Canada natural gas is set.
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
British thermal unit
long ton
thousand barrels of oil equivalent
millions of dollars
million barrels of oil equivalent
West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for crude oil of standard grade
Canadian dollars
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 Boe
is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency
at the wellhead. Given that the value ratio of oil compared to natural gas based on current prevailing prices is significantly different than
the energy equivalency conversion ratio of 6 Mcf:1 Boe, utilizing such a conversion ratio may be misleading as an indication of value.
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
Tons
Pounds
2,000
Pounds
Tons
0.0005
Metric tonnes
Pounds
2,205
Pounds
Metric tonnes
0.000454
1
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. All references to tones are to short tons (2,000 pounds per ton), unless otherwise
indicated. The information in this AIF is presented as at December 31, 2014 unless otherwise indicated.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This AIF contains certain forward-looking information and statements (collectively referred to herein as the “Forward-Looking Statements”) within
the meaning of applicable securities laws. In some cases, words such as "plans", "expect", "project", "intends", "believe", "anticipate", "estimate",
"may", "will", "should", "continue", "potential", "proposed" and other similar words, or statements that certain events or conditions "should", "may"
or "will" occur, are intended to identify Forward-Looking Statements. The Forward-Looking Statements herein are based upon the internal expectations,
estimates, projections, assumptions and beliefs of the Company as of the date of such information or statements (or with respect to Forward-Looking
Statements herein concerning Investments (defined below) that are public companies, are based upon the publicly disclosed internal expectations,
estimates, projections, assumptions and beliefs of the Investment as of the date of such disclosure by the Investment), including, among other things,
assumptions with respect to production, future capital expenditures and cash flows. The reader is cautioned that the expectations, estimates, projections,
assumptions and/or beliefs used in the preparation of such information may prove to be incorrect. The Forward-Looking Statements included in
this AIF are not guarantees of future performance and should not be unduly relied upon. Such information and statements, including the assumptions
made in respect thereof, involve known and unknown risks, uncertainties and other factors, which may cause actual results or events to differ materially
from those anticipated in the Forward-Looking Statements. In addition, this AIF may contain Forward-Looking Statements attributed to third-party
industry sources. The Forward-Looking Statements contained 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 contained in this AIF are expressly qualified by the cautionary statements provided for herein. The Company does
not assume any obligation to publicly update or revise any of the included Forward-Looking Statements after the date of this AIF, whether as a result
of new information, future events or otherwise, except as may be expressly required by applicable securities laws.
Forward-Looking Statements contained in this AIF include, but are not limited to, statements with respect to:
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the Company's goals with respect to returns on capital, risk management and wealth preservation;
the Company's investment strategy, investment process and competitive advantage;
valuations in the natural resource sector;
growth expectations and opportunities;
the tax horizon of the Company and its subsidiaries and treatment under tax laws;
supply and demand for commodities and commodity prices;
compliance with, treatment under and expectations regarding governmental regulatory regimes and legislation;
expectations regarding trends and compliance with environmental legislation and regulations, including associated costs;
conflicts of interest;
realization of the anticipated benefits of acquisitions and dispositions;
drill manufacturing and servicing;
drilling programs and activities;
expectations relating to oil and gas exploration and development;
expectations regarding development costs and development drilling related to reserves;
the performance and characteristics of oil and gas properties;
productive capacity of wells, anticipated or expected production rates/levels and anticipated dates of commencement of production;
oil and gas reserves;
abandonment and reclamation costs;
the Company's expectations regarding significant economic factors or significant uncertainties that will affect reserve data;
expectations regarding the Long Run Reserve Supplement (as defined below) and the InPlay Reserve Supplement (as defined below);
expected levels of royalty rates, operating costs, general and administrative costs, costs of services and other costs and expenses;
mineral resource and reserve quantities;
expectations regarding the development of mineral resources and the increase or decrease in demand for mineral resources, including
coal, in 2015 onwards;
expectations regarding permitting, approvals and mine production;
expectations regarding the coal industry;
Corsa's (as defined below) goal to focus on niche coal markets which command premium pricing and have a delivered cost advantage to
customers, while maintaining low-cost operations and sufficient infrastructure to achieve sustainable growth;
Potash Ridge's (as defined below) expectations regarding completion of a feasibility study for the Blawn Mountain Project (as defined
below);
Stonegate Agricom's (as defined below) expectations regarding the Stonegate Private Placement (as defined below) and the intended use
of the net proceeds raised through such financing;
The Company's expectations regarding its participation in, and support of, the Stonegate Private Placement;
UAG's (as defined below) intention to continue its expansion of operations and land holdings (through acquisitions or leases) in
Uruguay, while improving operational efficiencies in order to continue its evolution into a low-cost, global food exporter;
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UAG's expectations regarding obtaining governmental authorizations with respect to its lands;
OEF's (as defined below) strategy to increase the level of vertical integration of its business model in order to control cost and strategic
advantage through the supply chain;
OEF's ability to expand its business in the export market;
expectations regarding crop and livestock operations; and
expectations regarding food manufacturing.
Although the Company believes the expectations, estimates, projections, assumptions and beliefs reflected in the Forward-Looking Statements are
reasonable, undue reliance should not be placed on Forward-Looking Statements because the Company can give no assurance that such expectations,
estimates, projections, assumptions and beliefs 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. 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 contained in this AIF, include, but are not limited to:
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general economic conditions in Canada, the United States, Uruguay and globally;
industry conditions, including fluctuations in the price of oil and gas, coal and other natural resources;
liabilities inherent in oil and gas operations, mineral exploration and development, mining operations, farming operations and the food
industry;
governmental regulation of the oil and gas industry, the mining industry, the farming industry and the food 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;
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;
geological, technical, drilling and processing problems and other difficulties relating to the exploration and development of mineral reserves;
food safety;
fluctuations in weather conditions or climate change;
livestock disease or a decline in livestock fertility rates;
fluctuations in foreign exchange or interest rates;
failure to realize anticipated benefits of acquisitions;
stock market volatility and market valuations;
the availability of capital on acceptable terms;
the need to obtain required approvals from regulatory authorities; and
the other "risk factors" disclosed in, or incorporated by reference into, this AIF.
With respect to Forward-Looking Statements contained in this AIF, the Company has made the following assumptions, amongst others: future
exchange rates will be consistent with current rates; energy markets and the price of oil, NGL and natural gas will be higher in the future; the market
and services rates for land-based contract drilling services will be consistent with the current environment; the phosphate market and the price of
phosphate rock will be higher in the future; the potash market and the price of potash will be higher in the future; the price of uranium will be higher
in the future; coal, iron and steel markets and the price of coal, iron and steel will be consistent with the current environment; the demand for coal,
iron and steel will grow in the future; the cattle market and the price of beef will be consistent with the current environment; the natural and organic
meat market and the price of natural and organic meat will be consistent with the current environment; the soybean and wheat market and the prices
of soybeans and wheat will be consistent with the current environment; the impact of increasing competition in each business in which the Company's
subsidiaries operate will not materially change; conditions in general economic and financial markets will be consistent with the current environment;
the continued availability of quality management; the continued availability of drilling and related equipment and skilled labour in a cost-efficient
manner; the continued availability of qualified farming personnel; the effects of regulation and tax laws of governmental agencies will not materially
change; future operating costs will be consistent with the current environment; the ability to obtain financing on acceptable terms will be available;
Corsa’s ability to generate sufficient cash flow from operations and access capital markets to meet its future obligations; the regulatory framework
representing royalties, tax and environmental matters in the countries in which Corsa conducts business remains favorable; and Corsa being able to
execute its program of operational improvement and initiatives to realize cost synergies following the PBS Transaction (as defined below).
The above summary of assumptions and risks related to Forward-Looking Statements 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 such Forward-Looking
Statements may not be appropriate for other purposes.
PUBLIC DISCLOSURE BY INVESTMENTS
Disclosure included in this AIF regarding the Company's publicly-traded Investments (as defined below) has been derived from documents filed with
the Canadian securities regulatory authorities or the United States Securities and Exchange Commission by or on behalf of such Investments (see
"Company Overview" for a list of such Investments). We encourage you to consult our publicly-traded Investments’ disclosure documents, which are
available under their respective profiles on SEDAR at www.sedar.com or EDGAR at www.sec.gov, as applicable, but no such documents or their
contents, however, shall be deemed to be incorporated by reference into this AIF unless specifically otherwise noted in this AIF. While the Company
has no reason to believe that any such documents contain a misrepresentation, the Company does not assume liability for any disclosure incorporated
by reference herein or included herein which has been derived from such disclosure by Investments.
3
COMPANY OVERVIEW
The Company invests through Sprott Resource Partnership ("SRP") in the natural resource sector and provides active oversight, strategic, financial
and operational guidance to the companies in which it invests in order to maximize the value of the Company's investments therein. As at December
31, 2014, the Company had one reportable segment that invested in three industry sectors: (i) oil and gas exploration, production and services (the
"Energy Sector"); (ii) mining (the "Mining Sector"); and (iii) agriculture (the "Agriculture Sector").
As at December 31, 2014, the Company's investment portfolio was valued at $237.2 million (December 31, 2013: $346.5 million). Since September
2008, the Company has returned $119.3 million to its shareholders.
The Company's investment portfolio consists of unlisted (private) investments and listed (public) investments (each an "Investment" and collectively,
the "Investments"). As at December 31, 2014, only one Investment, One Earth Oil & Gas Inc. ("OEOG"), was a subsidiary of the Company. A
summary of the Company's Investments at December 31, 2014 is presented below (in thousands).
Industry Sector
Energy
% of Public/
NAV 1 Private
Public
(TSX)
49.7%
23.9%
11.9%
27,400
18.6%
24,342
19.9%
16,639
97.1%
Other, includes a private oil services company (18.6%) and a royalty interest in
producing oil wells.
10,128
n/a
Public Corsa Coal Corp. ("Corsa") is a Canadian company in the business of mining,
(TSX-V) processing and selling metallurgical and thermal coal, as well as actively exploring,
acquiring and developing U.S. resource properties that are consistent with its
existing coal business.
43,838
19.9%
Public
(TSX)
Potash Ridge Corporation ("Potash Ridge") is a Canadian company in the
exploration and development stage of developing a mine and processing facility
to produce sulfate of potash and an alumina-rich material on Blawn Mountain
in Utah, U.S.
3,604
24.4%
Public
(TSX)
Stonegate Agricom Ltd. ("Stonegate Agricom") is a Canadian company
engaged in the business of acquiring, exploring and developing agricultural
nutrient projects, which is currently focused on the development of the Paris
Hills phosphate deposit (the "Paris Hills Project") in Southeast Idaho, U.S.
3,318
36.5%
Public Other, includes a public company that owns a uranium deposit in southern
(TSX; Virginia, U.S.; a public mining company with interests in nickel, zinc, copper and
TSX-V; other minerals; and a public gold development company.
ASX)
3,752
n/a
38,677
6.6%
31,000
49.9%
Public Independence Contract Drilling, Inc. ("ICD") is a U.S. oil services company
(NYSE) specializing in the manufacture and operation of oil and natural gas directional
drilling rigs.
Private InPlay Oil Corp. ("InPlay") is a Calgary based company developing a low
decline, liquids-focused asset base.
Private OEOG is a Canadian company engaged in the development of oil and gas
opportunities on and adjacent to aboriginal lands in Alberta, Canada.
Private
Agriculture
30.6%
Companies
Long Run Exploration Ltd. ("Long Run") is a Calgary based intermediate
producer focused on light oil, NGL, and natural gas development in western $
Canada.
SRC
Ownership
(undiluted)
34,500
Private
Mining
Fair Value
Dec. 31,
2014
Private
Union Agriculture Group ("UAG") is an agriculture business operating in
Uruguay with agricultural operations in soybeans, wheat, rice, dairy, cattle and
sheep.
One Earth Farms Corp. and its subsidiaries ("OEF") are a Canadian vertically
integrated food business focused on Natural (as defined below) and Organic (as
defined below) protein-based food production and retail.
237,198
Notes:
(1) Cash and other assets less liabilities represent approximately (4.2)% of Net Asset Value ("NAV").
4
Investment Strategy
The Company's management team looks for investment opportunities where the Company can effectively deploy its capital to generate maximum
returns on its investments at acceptable levels of risk. The Company has a proven track record of partnering with experienced management teams
and co-investment partners, and is committed to the successful growth of the companies in which it invests.
The Company's investment decisions are guided by a set of core beliefs including: (i) enhanced returns come from patience and commitment; (ii)
successful investing requires contrarian behaviour; and (iii) an alignment of interests between management and shareholders is crucial. Applying its
set of core believes, the Company currently seeks investment opportunities between $25 million and $50 million in sectors and companies where,
amongst other things:
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a potential exists for reasonable returns at current commodity prices and significant returns upon recovery of the pertinent sector;
top quality, experienced management teams are also equity investors in the business themselves thereby aligning interests;
operations are in politically and economically stable jurisdictions that have good investment climates and enforceable contracts;
scalable assets and opportunities to finance on an accretive basis with development capital in place are present; and
realistic exit strategies exist.
Management of the Company is dedicated to generating superior returns on capital, risk management and real wealth preservation. Upon making
an investment, the Company takes an active approach with the goal of generating value for its shareholders, including, where necessary:
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active involvement with management and the business;
active and experienced board participation;
strategy development, implementation and long-term growth planning;
acquisition and disposition analysis;
executive recruitment;
management mentoring and guidance;
systems and process development;
contract negotiation support;
investor relations support;
fund-raising guidance and assistance;
creative financing alternatives; and
development of strategic connections.
Investment Process
The Company employs a four pillared investment process. The steps in this process are as follows:
1.
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Identify high-quality assets in stable political jurisdictions;
Secure compelling valuations;
Partner with high-quality management teams; and
Ensure there is adequate capital in place to continue the growth of the business.
Competitive Advantage
The Company is managed by an experienced team of private equity professionals with substantial expertise in natural resource investing. The
Company's management team is well positioned to draw upon the considerable expertise and resources of both its board of directors (the "Board")
and the Sprott group of companies. Pursuant to a management services agreement between the Company and Sprott Consulting Limited Partnership
("SCLP"), of which Sprott Inc. is the sole limited partner, SCLP provides day-to-day business management for the Company as well as other
management and administrative service (see "Material Contracts - Amended and Restated MSA"). Such arrangement provides the Company with access
to the proprietary deal network and relationships of the wider Sprott group of companies, along with in-house technical support and expertise.
The Company's management team is a widely recognized manager of third party capital, with core capabilities that include:
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knowledge and contacts in the resource space;
systematic due diligence processes;
fiduciary investment decision-making procedures;
hands on support of investee companies;
administration and corporate governance; and
risk management and compliance.
5
CORPORATE STRUCTURE
Name, Address and Incorporation
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 855-2nd Street, S.W., Suite 3500, Calgary, Alberta, T2P 4J8. The head office is located at Royal Bank Plaza, South
Tower, 200 Bay Street, Suite 2750, Toronto, Ontario, M5J 2J2.
Intercorporate Relationships
Included below is a diagram of the intercorporate relationships among the Company and its subsidiaries, SRP and OEOG, as at December 31, 2014,
indicating the percentage of votes attaching to all voting securities of such entities beneficially owned, controlled or directed by the Company and
where such entities were incorporated or continued.
Notes:
(1)
SRP is a partnership between Sprott Resource Consulting Limited Partnership ("SRCLP"), an affiliate of SCLP, and the Company (see "Material Contracts Partnership Agreement"). The Company's Investments are held through SRP.
(2)
As at December 31, 2014, OEOG had 964,190 warrants ("OEOG Warrants") outstanding, of which 60,000 are beneficially held by the Company. None
of the OEOG Warrants outstanding were issued during the year ended December 31, 2014. 590,000 of the 964,190 OEOG Warrants outstanding (which include the
60,000 OEOG Warrants beneficially held by the Company) have a term of five years, expire on December 23, 2018 and are convertible to common shares of OEOG
("OEOG Shares") at $0.65 per OEOG 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 OEOG Shares on the liquidity event or public transaction must meet or exceed a set price. One-quarter of such OEOG Warrants vest at a transaction
value of at least $0.75 per OEOG Share. An additional one-quarter vest at a transaction value of at least $1.00 per OEOG Share. An additional one-quarter vest at a
transaction value of at least $1.30 per OEOG Share. The final one-quarter vest at a transaction value of at least $1.60 per OEOG Share.
The remaining 374,190 of the 964,190 OEOG Warrants outstanding have a term of five years and will expire on October 18, 2015. Such OEOG Warrants are convertible
to OEOG Shares at $1.00 per OEOG 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 OEOG Shares on the liquidity event or public transaction must meet or exceed a set price. One-quarter vest at a transaction value of at least
$1.15 per OEOG Share. An additional one-quarter vest at a transaction value of at least $1.50 per OEOG Share. An additional one-quarter vest at a transaction value
of at least $2.00 per OEOG Share. The final one-quarter vest at a transaction value of at least $2.50 per OEOG Share.
As at December 31, 2014, OEOG had 2,132,410 stock options ("OEOG Options") outstanding, of which 120,000 are beneficially held by the Company. The term,
vesting period and exercise price of the OEOG Options are determined at the discretion of OEOG's board of directors. During the year ended December 31, 2014,
no OEOG Options were granted to officers, employees or consultants of OEOG. As at December 31, 2014, 1,160,191 OEOG Options had vested and were exercisable
as follows: 433,333 at $0.65 per OEOG Share, 52,776 at $0.75 per OEOG Share and 674,082 at $1.00 per OEOG Share. The remaining OEOG Options have not
vested, but could be exercisable as follows: 866,667 at $0.65 per OEOG Share and 105,552 at $0.75 per OEOG Share. The average remaining life of the outstanding
OEOG Options is approximately 3.14 years.
6
CAPITAL STRUCTURE
The authorized capital of the Company consists of an unlimited number of common shares.
As at December 31, 2014, the Company had 97,874,503 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.
EMPLOYEES
At December 31, 2014, the Company had 11 employees and OEOG had 2 employees. OEOG also engaged a variable number of consultants as
required for its operations.
GENERAL DEVELOPMENT OF THE BUSINESS
Until 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 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 and it now invests and operates 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 SRP, a partnership formed pursuant to an amended and restated partnership agreement between SRCLP and the Company (the "Partnership
Agreement"). Substantially all of the holdings of the Company were transferred to SRP in 2011.
In connection with the Reorganization, the Board 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. 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:
2012
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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 of ICD were 31.6% and 25.3%,
respectively.
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On March 26, 2012, the Board approved an additional investment into OEOG of up to $13 million conditional upon OEOG entering
into an agreement with the Gift Lake Métis Settlement ("Gift Lake"). The Company’s interest in OEOG increased to 94.7% on an undiluted
basis after giving effect to the investment.
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On April 1, 2012, OEOG entered into a joint venture agreement with Gift Energy Limited ("Gift Energy"), an entity established by Gift
Lake, to explore and develop Gift Lake lands for heavy oil. Gift Lake is located in the Peace River region of Northwest Alberta, an area
of existing heavy oil production. The Gift Lake lands are situated southeast of major Bluesky oilsands production fields in the Seal and
Cliffdale regions operated by several established Canadian energy producers.
•
On August 21, 2012, the Company provided a $7.5 million loan facility to Stonegate Agricom (the "Stonegate Facility"). The funds were
advanced in order to further the advancement of the Paris Hills Project and were drawn down by Stonegate Agricom from time to time
for development work, including environmental permitting activities, related to such project. The Stonegate Facility was non-callable,
carried an annual interest rate of five percent payable monthly in arrears and was due to be repaid within 18 months of its advance. There
were no standby fees, commitment fees or warrants associated with the transaction.
•
On September 27, 2012, Anthem Resources Inc. (formerly Virginia Energy Resources Inc. ("VAE")) and Virginia Energy Resources Inc.
("Virginia Energy") (formed pursuant to the amalgamation of VA Uranium Holdings Inc. ("VAUH") and Virginia Uranium Ltd. pursuant
to the Virginia Arrangement (as defined below) completed an arrangement under the Business Corporations Act (British Columbia) (the
"Virginia Arrangement"). Pursuant to the Virginia Arrangement, the Company exchanged its 32,906,842 non-voting common shares of
VAUH for 5,979,173 common shares of Virginia Energy ("Virginia Energy Shares") and exchanged its 6,084,999 common shares of
7
VAE for 608,499 Virginia Energy Shares, for net holdings of 6,587,672 Virginia Energy Shares, representing approximately 19.9% of the
then-issued and outstanding Virginia Energy Shares.
•
On October 23, 2012, a business combination of Guide Exploration Ltd. ("Guide") and WestFire Energy Ltd. ("WestFire") pursuant to
a plan of arrangement was completed, resulting in the formation of Long Run (the "Long Run Arrangement"). As a result of the Long
Run Arrangement, previous shareholders of Guide received 0.4167 common shares of Long Run ("Long Run Shares") for each outstanding
Guide Share previously held, while shares of WestFire continued to represent shares of Long Run on a one-for-one basis.
Pursuant to the Long Run Arrangement, on October 23, 2012, the Company exchanged its 16,769,477 common shares of Guide for
6,987,841 Long Run Shares and converted its 13,153,936 common shares of WestFire for 13,153,936 Long Run Shares, for net holdings
of 20,141,777 Long Run Shares. Based on information contained in documents publicly filed by Long Run, these net holdings represented
approximately 18.3% of the then-issued and outstanding Long Run Shares. In addition, the Company’s 15,512,858 non-listed, non-voting
convertible shares of WestFire continued to represent non-listed, non-voting convertible shares of Long Run (the "Long Run NonVoting Shares") on a one-for-one basis, being approximately 100% of the outstanding Long Run Non-Voting Shares. The Long Run
Non-Voting Shares were convertible into Long Run Shares on a one-for-one basis in certain circumstances and represented approximately
12.4% of the then outstanding Long Run Shares.
•
On November 1, 2012, the Company completed the sale of Waseca Energy Inc. ("Waseca") to Twin Butte Energy Ltd. (the "Twin Butte
Arrangement"). The consideration received by the Company upon the sale was comprised of $55.1 million of cash and approximately
19.9 million common shares of Twin Butte Energy Ltd. ("TB Shares"). Immediately subsequent to the completion of the Twin Butte
Arrangement, the Company sold all of the TB Shares for approximately $56.6 million of cash, resulting in total cash consideration of
approximately $111.7 million for the sale of Waseca. The Company originally invested approximately $44.2 million into Waseca in two
investment tranches. Proceeds from the Twin Butte Arrangement were partially used to repay the Company’s margin facility granted by a
Schedule 1 Bank, which was previously used, in part, to fund the ICD investment.
•
On December 5, 2012, Potash Ridge completed an initial public offering (the "Potash Offering") of its common shares ("Potash Shares").
The Company acquired ownership of 2,944,746 Potash Shares at a purchase price of $1.00 per Potash Share (the "Potash Offering Price")
pursuant to the Potash Offering. Prior to this acquisition, the Company owned 13,200,000 Potash Shares at an average purchase price of
$0.52 per Potash Share. Following completion of the Potash Offering, the Company owns 16,144,746 Potash Shares, which represented
approximately 19.9% of the then-issued and outstanding Potash Shares. Concurrent with the closing of the Potash Offering, the Company
purchased 5,055,254 units of Potash Ridge at a price of $1.00 per unit. Each unit consisted of one non-voting share in the capital of
Potash Ridge ("Potash Non-Voting Shares") and one warrant ("Potash Warrants") to acquire one Potash Non-Voting Share exercisable
at a price equal to the Potash Offering Price for a period of two years following the closing of the Potash Offering. The Potash NonVoting Shares are convertible into Potash Shares on a one-for-one basis under certain circumstances, however the terms of the Potash
Non-Voting Shares do not allow the Company to own more than 19.9% of the Potash Shares upon conversion. The Potash Non-Voting
Shares and Potash Warrants acquired by the Company represent 100% of such issued and outstanding securities.
•
On December 12, 2012, the Company approved a policy (the "Dividend Policy") pursuant to which the Company intended to pay a
monthly dividend at least equal to 0.833% of the Company’s total equity attributable to shareholders ("Book Value") based on the most
recently filed financial statements of the Company at the time the dividend was declared. The amount of future monthly dividends were
to fluctuate quarterly with the Company’s Book Value. On the same date, the Company declared an initial monthly dividend of $0.038 per
common share (the "Initial Dividend"), which was based on the Company’s Book Value as at September 30, 2012, adjusted to take into
consideration the increase in the Company’s Book Value due to its disposition of Waseca. See "Dividends" for details of the Initial Dividend
and subsequently declared dividends.
•
During 2012, the Company repurchased and canceled 10.2 million common shares under a normal course issuer bid at an average cost of
$3.79 per common share for a total cost of approximately $38.9 million.
2013
•
In January 2013, an oilsands lease for 12 sections (3,072 hectares) of land at Gift Lake was finalized with the Alberta government and an
option on a further 10.5 sections (2,688 hectares) of land at Gift Lake was subsequently exercised by OEOG. As a precursor to further
development activity, OEOG and Gift Energy completed an initial 3D seismic program and initiated a drilling program in March 2013.
The initial drilling and seismic program was completed in August 2013.
•
On January 25, 2013, the Company acquired ownership of a further 2,857,143 Virginia Energy Shares at a purchase price of $0.42 per
share in a private placement completed by Virginia Energy, for total holdings of 9,444,815 Virginia Energy Shares. Based on information
contained in documents publicly filed by Virginia Energy, such holdings represent approximately 16.5% of the issued and outstanding
Virginia Energy Shares.
•
On February 19, 2013, OEF acquired Toronto based Beretta Farms Inc. ("Beretta Farms"), a purveyor of hormone free and antibiotic
free Natural and Organic branded meat products. After giving effect to the consideration of cash and common shares in OEF ("OEF
Shares") paid to the vendors of Beretta Farms, the Company's ownership in OEF was reduced to approximately 54.3% on an undiluted
basis.
•
On February 25, 2013, the Company established a Dividend Reinvestment Plan (the "DRIP") for Canadian resident shareholders of
common shares of the Company. The DRIP provided a convenient and cost-effective method for eligible holders in Canada to maximize
their investment in the Company by reinvesting their monthly cash dividends to acquire additional common shares. A discount in the
purchase price of up to 5% applied on dividend reinvestment shares purchased from the Company.
8
•
On May 1, 2013, Stonegate Agricom acquired the Company's fully drawn Stonegate Facility for 11.5 million common shares of Stonegate
Agricom ("Stonegate Shares"). After giving effect to the transaction, the Company owned 58.5 million Stonegate Shares, which based
on information contained in documents publicly filed by Stonegate Agricom, represented approximately 37.5% of the then-issued and
outstanding Stonegate Shares.
•
On July 24, 2013, Stonegate Agricom completed a prospectus offering (the "Stonegate Offering") of 33,333,333 units ("Stonegate
Units"). The Company acquired beneficial ownership of 12.5 million Stonegate Units for a purchase price of $0.30 per Stonegate Unit
pursuant to the Stonegate Offering. Each Stonegate Unit consisted of one Stonegate Share and one Stonegate Share purchase warrant (a
"Stonegate Warrant"). Each Stonegate Warrant entitled the holder thereof to purchase one Stonegate Share at an exercise price of $0.40
per Stonegate Share for a period of 24 months following the closing of the Stonegate Offering. On August 8, 2013, the underwriters
exercised their over-allotment option in full, resulting in the issuance and sale of an additional 5 million Stonegate Units at a price of $0.30
per Stonegate Unit for additional aggregate gross proceeds to Stonegate Agricom of $1.5 million.
Following completion of the Stonegate Offering, the Company beneficially owned 71.0 million Stonegate Shares, which based on information
contained in documents publicly filed by Stonegate Agricom, represents approximately 36.5% of the issued and outstanding Stonegate
Shares on an undiluted basis. Based on information contained in documents publicly filed by Stonegate Agricom, the Company's 12.5
million Stonegate Warrants represent approximately 32.6% of the then-issued and outstanding Stonegate Warrants.
•
In July 2013, OEF acquired Sweet Pea Baby Foods Ltd., a company that markets frozen organic meal options for babies and toddlers across
Canada.
•
On August 13, 2013, the Board elected to terminate the DRIP and to cease paying monthly dividends pursuant to the Company's Dividend
Policy in order to preserve capital and protect the Company's ability to continue effectively executing its business plan.
•
On August 30, 2013, the Company sold 14,142 ounces of its gold bullion for approximately $21.1 million dollars ($1,494 per ounce).
•
On October 21, 2013, Kevin Bambrough (former Chairman of the Board and President and Chief Executive Officer ("CEO") of the
Company) left the Company to pursue other opportunities. On the same date, Terrence A. Lyons was appointed Chairman of the Board
and Stephen Yuzpe was named President and CEO of the Company. Mr. Yuzpe continued as the interim Chief Financial Officer ("CFO")
of the Company until Michael Staresinic was appointed into such position on December 4, 2013.
•
On November 15, 2013, the Company completed the disposition of its remaining 59,829 ounces of gold bullion for gross proceeds of
approximately $79.5 million ($1,328 per ounce).
•
In November 2013, the Board approved an additional investment in OEOG for up to $11.0 million to allow OEOG to further its 3D
seismic and drilling program in winter 2013/14 at Gift Lake. The Company completed the investment in two tranches; one in December
2013 and the other in February 2014. Subsequent to December 31, 2013, and as part of the $11.0 million investment by the Company,
OEOG acquired additional rights to 22.25 sections of land, taking the total lands in the joint venture with Gift Energy to approximately
45 sections (28,800 acres). The Company’s interest in OEOG increased to 96.0% on an undiluted basis after giving effect to the investment.
•
In December 2013, the Company committed $5 million for a royalty interest in a number of wells to be drilled by Delphi Energy Corp.
("Delphi"), a Calgary-based company that explores, develops and produces oil and natural gas in Northwestern Alberta and, as at December
31, 2014, the Company had invested the full $5 million commitment. The royalty on the wells, which the Company began to receive in
April 2014, will be received until an agreed upon rate of return is achieved, at which time the royalty will be extinguished on all wells. In
November 2014, the Company committed a further $2.1 million for a royalty interest in three additional wells drilled by Delphi and, as at
the date hereof, the Company has invested the full $2.1 million commitment.
•
During 2013, the Company repurchased and canceled 942,328 common shares under a normal course issuer bid at an average cost of $2.43
per common share for a total cost of approximately $2.3 million.
2014
•
On January 31, 2014, Long Run initiated a monthly dividend of $0.0335 per Long Run Share and Long Run Non-Voting Share. Commencing
in June 2014, Long Run increased its monthly dividend to $0.035 per Long Run Share.
•
On May 21, 2014, the Company completed a secondary offering on a bought deal basis of 12,654,635 Long Run Shares at a price of $5.35
per Long Run Share, for gross proceeds of $67,702,297 to the Company (the "Long Run Offering"). Immediately following completion
of the Long Run Offering, the Company exercised its right to convert all of its Long Run Non-Voting Shares into 15,512,858 Long Run
Shares (the "Long Run Conversion"). After giving effect to the Long Run Offering and the Long Run Conversion, the Company's
ownership interest in Long Run was approximately 18.3% and comprised of a total of 23 million Long Run Shares. Following the Deep
Basin Acquisition (as defined below) and the Crocotta Acquisition (as defined below), the Company owns 11.9% of the issued and
outstanding Long Run Shares.
•
On June 12, 2014, the Company invested $19.5 million in InPlay, a private exploration and development company based in Calgary, Alberta,
in exchange for 19.9% of the then-issued and outstanding common shares of InPlay ("InPlay Shares"). Mr. Stephen Yuzpe, CEO and
President of the Company, was subsequently appointed to the board of directors of InPlay.
•
On August 11, 2014, the Company completed a follow-on equity investment in OEOG through a private placement in the amount of $2.7
million. The proceeds from the investment were predominately used by OEOG to progress drilling activity on the Gift Lake property.
The Company's interest in OEOG increased to 96.1% on an undiluted basis after giving effect to the investment.
9
•
On August 13, 2014, ICD completed its US$115 million initial public offering (the "IPO") on the New York Stock Exchange ("NYSE").
The Company participated in the IPO, purchasing 600,000 common shares of ICD (the "ICD Shares") at US$11.00 per ICD Share and
after giving effect to the IPO and the underwriters' exercise of their option to purchase additional ICD Shares, the Company owns 18.6%
of the issued and outstanding ICD Shares.
•
On August 19, 2014, Corsa completed its acquisition of all of the outstanding shares of PBS Coals Limited, a wholly owned subsidiary of
OAO Severstal, in an all-cash transaction for consideration of US$60 million, subject to customary adjustments for working capital and
debt (the "PBS Transaction"). As part of the PBS Transaction, the Company invested US$33.4 million to purchase 236,963,302 common
shares of Corsa (the "Corsa Shares"), at a price of C$0.15 per Corsa Share. Upon completion of the PBS Transaction, the Company
owns 19.9% of the issued and outstanding Corsa Shares. SRP obtained certain ongoing rights including the right to nominate one member
of the board of directors of Corsa; such right will terminate if SRP, together with its affiliates, ceases to hold at least 10% or more of the
outstanding Corsa Shares for a continuous period of 30 days. Mr. Arthur Einav, General Counsel, Corporate Secretary and Managing
Director of the Company, was appointed to the board of directors of Corsa. SRP also entered into a registration rights agreement with
Corsa which provides SRP with rights to twice demand registration in Canada for as long as it holds at least 10% of the outstanding Corsa
Shares.
•
On September 19, 2014, OEF completed a private placement to existing shareholders that resulted in a total offering of $11.1 million. The
Company participated in the amount of $3.4 million and as a result of the financing the Company's proportionate ownership interest in
OEF was reduced to 50.1% on an undiluted basis. A portion of the proceeds from the financing was used to complete the acquisition of
a federally and European Union (the "EU") certified abattoir and the assets of an existing beef brand with significant distribution in Canada
and the EU.
•
In November 2014, the Company secured a $20 million credit facility from Sprott Resource Lending Corp., a subsidiary of Sprott Inc.
•
On December 17, 2014, the Company invested a further $4.5 million in InPlay alongside management, company directors and other
significant private equity investors, including JOG Capital. The Company's interest in InPlay remained at 19.9% on an undiluted basis after
giving effect to the investment.
•
On December 30, 2014, the Company completed a follow-on equity investment in OEOG through a private placement in the amount of
$4.5 million. The proceeds from the investment were used to acquire the Pekisko Play (as defined below) in the Peace River area of
Northern Alberta and for further Gift Lake joint venture activities. The Company's interest in OEOG increased to 97.1% on an undiluted
basis after giving effect to the investment.
•
Effective December 31, 2014, OEF completed a small transaction involving non-controlling interests and, as a result, the Company's
ownership in OEF was reduced to 49.9% on an undiluted basis.
•
During 2014, the Company repurchased and canceled 0.9 million common shares under a normal course issuer bid at an average cost of
$2.43 per common share for a total cost of approximately $2.3 million.
2015
•
On January 1, 2015, OEOG acquired 65% of the heavy oil reserves and production in a Pekisko heavy oil play (the "Pekisko Play")
adjacent to OEOG's existing land interests at Gift Lake. The remaining 35% of the Pekisko Play was acquired by an industry partner with
operational experience in the area and Gift Energy.
•
On February 9, 2015, Long Run announced that it had reduced its 2015 capital budget to $100 million and suspended its monthly dividend.
ENERGY SECTOR
The Investments held by the Company in the Energy Sector as at December 31, 2014 include investments in Long Run, InPlay and OEOG (collectively,
the "E&P Companies"), ICD, a Canadian private oil services company, and a royalty interest in producing oil wells drilled by Delphi. The Company
was materially impacted by the decline in global oil prices which triggered significant declines in the valuations of its energy sector Investments during
the fourth quarter of 2014. This decline continued in the first quarter of 2015 and the current oil and gas price environment caused Long Run to
suspend its monthly dividend and adjust their capital budget for 2015 and has also significantly affected the Company's other energy-related Investments.
Long Run Exploration Ltd.
Long Run is a Canadian public company (TSX:LRE) that was formed in October 2012 through the merger of WestFire and Guide. Long Run is
engaged in the acquisition, exploration, development and production of light oil, NGL and natural gas in Western Canada. The company is guided
by a management team with a proven track record of delivering organic growth; growth through acquisition and optimization; and implementing
new technology in resource plays and utilizing enhanced recovery techniques.
On January 31, 2014, Long Run initiated a monthly dividend of $0.033 per Long Run Share and Long Run Non-Voting Share. Commencing in June
2014, Long Run increased its monthly dividend to $0.035 per Long Run Share. As discussed below, in February 2015, Long Run suspended its monthly
dividend.
On May 30, 2014, Long Run completed its acquisition of certain strategic oil and liquids-rich natural gas assets focused on the Cardium in the Deep
Basin and Pine Creek areas of Alberta (the "Deep Basin Acquisition"). Long Run publicly announced that total consideration for the Deep Basin
Acquisition, after closing adjustments, was approximately $225 million. The Deep Basin Acquisition was funded from Long Run's $120 million bought
10
deal equity financing in which the Company did not participate, the disposition of 400 boe/d of heavy oil from Long Run's Lloydminster property
and Long Run's credit facilities.
On August 6, 2014, Long Run publicly announced that it had successfully completed its acquisition (the "Crocotta Acquisition") of all of the issued
and outstanding common shares of Crocotta Energy Inc. ("Crocotta") pursuant to a plan of arrangement. Crocotta's assets in northeast British
Columbia and northwest Alberta were excluded from Long Run's acquisition and were transferred to another company in connection with the
transaction. Pursuant to the plan of arrangement, Long Run issued approximately 44 million Long Run Shares and assumed $115 million of Crocotta's
net debt, inclusive of transaction costs. The Crocotta Acquisition gives Long Run a major presence in the strategic oil and liquids-rich natural gas
Deep Basin fairway at Pine Creek, focusing on the Cardium and Bluesky formations. Long Run publicly announced that this acquisition, in concert
with the Deep Basin Acquisition, creates a new core area which will provide exploration and development opportunities and adds strategic ownership
in gathering and processing infrastructure.
As at December 31, 2014, Long Run had more than 1.8 million acres of land, 36,502 boe/d of production (49% oil/51% gas) for the fourth quarter,
a large inventory of exploration and development opportunities and $1.85 billion in available tax pools. Long Run's average production for the year
ended December 31, 2014 was 31,168 boe/d (50% oil/50% gas) and for the year ended December 31, 2013 was 25,094 boe/d (53% oil/47% gas).
On February 9, 2015, Long Run announced that, as a result of a volatile and uncertain commodity price environment, and current oil and natural
gas prices significantly below its previously forecast 2015 assumptions, Long Run's board of directors and management had prudently decided to
reduce its capital budget to $100 million and suspend its monthly dividend. Long Run publicly announced that its business plan will focus on
strengthening the balance sheet, actively managing its property portfolio and targeting a development program of its highest quality assets. Long
Run's revised drilling program is estimated by Long Run to support average production of 32,000 to 33,000 (boe/d) (43% liquids) for 2015. For
further information, see Long Run's press release dated February 9, 2015, which is available under Long Run's profile on SEDAR at www.sedar.com
and, for greater certainty, is not incorporated by reference into this AIF.
During 2014, the Company received cash dividends from Long Run totaling $10.4 million and disposed of 12.7 million Long Run Shares at $5.35
per share for gross proceeds of $67.7 million. The Company realized a gain of $12.8 million relating to the disposition, or a gain of $1.01 per Long
Run Share, based on its average cost of the investment. As at December 31, 2014, the Company owned 23.0 million Long Run Shares valued at $1.50
per share for an aggregate investment value totaling $34.5 million. As at December 31, 2013, the Company owned 35.7 million Long Run Shares
valued at $5.31 per share for an aggregate investment value totaling $189.3 million. During 2014, the percentage decrease in the value of the Company's
year-end holdings in Long Run was approximately 72.1% (approximately a 9.6% increase during 2013).
Reserve Supplement
Effective January 1, 2014, the Company adopted the investment entity amendments of International Financial Reporting Standards 10, Consolidated
Financial Statements. In determining its status as an investment entity, the most significant judgments made include the determination by the Company
that its investment-related activities with subsidiaries, other than SRP, do not represent a separate substantial business activity and that fair value is
the primary measurement attribute used to monitor and evaluate substantially all of its Investments. Accordingly, the Company's investment in Long
Run is carried at fair value. The Company intends to file a supplement to this AIF disclosing information concerning Long Run's oil and gas reserves
and future net revenue as at December 31, 2014 and certain costs incurred by Long Run during 2014, based on the Company's equity interest in Long
Run (the "Long Run Reserve Supplement"). The Long Run Reserve Supplement will be filed under the Company's profile on SEDAR at
www.sedar.com on or prior to March 31, 2015, and will be incorporated by reference into this AIF.
Readers are cautioned that the Company does not have any direct or indirect interest in, or right to, the reserves or future net revenue of
Long Run to be disclosed in the Long Run Reserve Supplement nor does the Company have any direct or indirect obligation in respect
of, or liability for, the costs incurred by Long Run to be disclosed in the Long Run Reserve Supplement. The Company is a shareholder
of Long Run just like any other shareholder of Long Run, and accordingly, the value of the Company's investment in Long Run is based
on the trading price of the Long Run Shares on the Toronto Stock Exchange (the "TSX").
The Long Run Reserve Supplement will be prepared based solely on publicly disclosed information contained in Long Run's annual information
form for the year-ended December 31, 2014 (the "2014 Long Run AIF"), when available. For additional information regarding Long Run's reserves,
properties and costs incurred on such properties, reference should be made to the 2014 Long Run AIF and other disclosure documents filed under
Long Run's profile on SEDAR at www.sedar.com, none of which documents are incorporated by reference into this AIF unless specifically otherwise
noted in this AIF.
Independence Contract Drilling, Inc.
ICD, which is based in Houston, Texas, is a vertically integrated premium onshore drilling services provider founded in March 2012. On August 8,
2014, ICD became a public company (NYSE:ICD).
ICD's custom designed and company built ShaleDriller™ series rigs are designed for unconventional resource plays, incorporating the newest
technologies fielded in land drilling operations. ShaleDrillers are land rigs targeted for the development of U.S. exploration and production clients'
exploration and development programs. The ShaleDriller series rigs are alternating current ("AC"), programmable, energy efficient and offer BiFuel
capabilities. Unlike skidding rigs, ShaleDriller’s true multi-directional "walking" systems are not slowed down by misaligned well bores and can walk
over existing wellheads.
As of December 31, 2014, ICD had 11 rigs constructed and 3 rigs in construction.
As at December 31, 2014, the Company owned 4.5 million ICD Shares valued at $6.06 per share for an aggregate investment value totaling $27.4
million. As at December 31, 2013, the Company owned 2.5 million ICD Shares valued at $20.10 per share for an aggregate investment value totaling
$50.3 million. Pursuant to the IPO, on August 8, 2014, 2.5 million ICD Shares held by the Company were converted to 3.9 million ICD Shares and
11
the Company purchased an additional 0.6 million ICD Shares at a price of US$11.00 per share. The investment in ICD has had a value decrease from
its IPO date of approximately 52.2% (approximately a 10.8% increase during 2013).
InPlay Oil Corp.
Founded in the fourth quarter of 2012, InPlay is a Canadian private energy exploration and development company based in Calgary, Alberta. InPlay
management has begun the process of acquiring high-quality, light oil growth assets in Alberta as they work to advance their strategy of building a
large, low-decline, liquids-focused asset base in an attractive area for exploration and development. The company experienced significant growth
during 2014, acquiring assets in east Pembina and Eastern Alberta, focused on the Belly River, Cardium, Manville and Banff zones.
InPlay first acquired material oil producing operations in June 2014. InPlay's average production for December 2014 was 1,770 boe/d (87% oil &
liquids/13% gas). InPlay's average production for the year ended December 31, 2014 was 658 boe/d (87% oil & liquids/13% gas) and for the year
ended December 31, 2013 was 2.0 boe/d (80% oil & liquids/20% gas).
The Company's initial investment in InPlay was made in the second quarter of 2014 for $19.5 million or $1.25 per InPlay Share. A subsequent
investment in InPlay was made by the Company in the fourth quarter of 2014 for $4.5 million or $1.65 per InPlay Share. As at December 31, 2014,
the Company owned 18.3 million InPlay Shares with a fair value of $24.3 million or $1.33 per share (approximately a 6.4% increase since the initial
investment in June 2014).
Reserve Supplement
The Company's investment in InPlay is carried at fair value. The Company intends to file a supplement to this AIF disclosing information concerning
InPlay's oil and gas reserves and future net revenue as at December 31, 2014 and certain costs incurred by InPlay during 2014, based on the Company's
equity interest in InPlay (the "InPlay Reserve Supplement"). The InPlay Reserve Supplement will be filed under the Company's profile on SEDAR
at www.sedar.com on or prior to March 31, 2015, and will be incorporated by reference into this AIF.
Readers are cautioned that the Company does not have any direct or indirect interest in, or right to, the reserves or future net revenue of
InPlay to be disclosed in the InPlay Reserve Supplement nor does the Company have any direct or indirect obligation in respect of, or
liability for, the costs incurred by InPlay to be disclosed in the InPlay Reserve Supplement. The Company is a shareholder of InPlay
just like any other shareholder of InPlay, and accordingly, the value of the Company's investment in InPlay is based on the fair value of
the InPlay Shares. For information regarding how the Company calculates the fair value of its investment in InPlay, see the financial
statements for the Company's most recently completed financial year.
The InPlay Reserve Supplement will be prepared based solely on information provided to the Company by InPlay and its qualified reserves evaluator
or auditor.
One Earth Oil & Gas Inc.
OEOG was incorporated on April 25, 2008 with the business purpose to develop natural resources on or around aboriginal communities in Western
Canada. While there has been significant evolution in OEOG's business strategy and opportunities since that time, OEOG's core focus has always
been partnering with aboriginal communities and accessing potential unexplored resource wealth.
Since 2010, OEOG has focused its efforts on developing oil and gas properties. OEOG's current operated producing properties are situated in the
Wetaskiwin and Campbell areas that are just south and east of Edmonton as well as the Peace River area in northwest Alberta. OEOG commenced
production operations in April 2011 and, as at December 31, 2014, OEOG had 56 boe/d of production (41% oil/59% gas). OEOG's average
production for the year ended December 31, 2014 was 156 boe/d (17% oil/83% gas) and for the year ended December 31, 2013 was 267 boe/d
(14% oil/86% gas).
During 2014, the Company had three follow-on investments in OEOG: $4.5 million in February 2014, $2.7 million in August 2014 and $4.5 million
in December 2014. As at December 31, 2014, the Company owned 72.3 million OEOG Shares valued at $0.23 per share for an aggregate investment
value totaling $16.6 million. As at December 31, 2013, the Company owned 40.3 million OEOG Shares valued at $0.58 per share for an aggregate
investment value totaling $23.4 million. The percentage decrease in the value of the Company's holdings in OEOG as at December 31, 2014 was
approximately 60.3% (approximately a 38.1% increase during 2013).
In early 2015, OEOG and two strategic partners acquired the Pekisko Play in the Peace River area of Alberta. Following the acquisition, OEOG
holds approximately 137 gross sections of land in the Peace River area with gross production of approximately 300 bbls/d. OEOG intends to continue
development of its heavy oil opportunities in the Pekisko, Upper Gething and Bluesky formations in the Peace River area, with consideration given
to the current oil price environment. OEOG continues to have operations in Central Alberta that provide a base level of production and cash flow.
Attached as Appendices A to C are the following items:
APPENDIX "A"
Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1)
APPENDIX "B"
Report on Reserves by McDaniel & Associates Consultants Ltd. (Form 51-101F2)
APPENDIX "C"
Report of Management and Directors on Oil and Gas Disclosure (Form 51-101F3)
12
Energy Sector Overview
The oil and natural gas industry is subject to extensive controls and regulation 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,
regulations or agreements will affect the E&P Companies' 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. The discussion below focuses on the Canadian oil and natural gas industry and particularly in the Province of Alberta, which
accounts for all material production of the E&P Companies in 2014.
The Province of Alberta has instituted the Responsible Energy Development Act (Alberta) wherein a new, single regulatory body for upstream oil and gas
was established. This single regulator, the Alberta Energy Regulator ("AER"), was formed by merger of the Energy Resources Conservation Board
and portions of the Alberta Environment and Sustainable Resource Development. The AER now has responsibility over the Oil and Gas Conservation
Act (Alberta) ("OGCA"), the Public Lands Act (Alberta), the Mines and Minerals Act (Alberta), the Water Act (Alberta)("Water Act") and the Environmental
Protection and Enhancement Act (Alberta)("EPEA") to the extent such legislation applies to oil and gas operations. The AER's responsibilities exclude
the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The
intention of the transformation of the regulatory regime was to provide a comprehensive streamlined regulatory process that is efficient, attractive
to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights
of landowners.
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 and access 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. 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 government of Alberta regulates the volume of natural gas which may be removed from the province for consumption elsewhere based on such
factors as reserve availability, transportation arrangements and market considerations.
Pricing and Marketing - Oil
The producers of oil 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 type and quality, prices of competing fuels, distance and
access to the market, the value of refined products, the supply/demand balance, and other contractual terms as well as the world price of oil. Crude
oil exported from Canada is subject to regulations by the NEB and the Government of Canada. Oil exports may be made pursuant to export contracts
with terms not exceeding one year in the case of light crude oil and not exceeding two years in the case of heavy crude oil, provided that an order
approving any such export has been obtained from the NEB. Any oil export to be made pursuant to a contract of longer 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 not exceeding the approval of
the Governor in Council.
The North American Free Trade Agreement
The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States 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 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 importprice 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 in Canada has legislation and regulations which govern land tenure, royalties, production rates,
environmental protection and other matters. In all Canadian jurisdictions, producers of oil and natural gas are required to pay annual rental payments
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in respect of Crown leases, and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands,
respectively. 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 freehold lands, which are 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.
Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and
make monthly royalty payments in respect of oil and natural gas produced.
Royalties payable for production of oil and natural gas from Crown lands in Alberta are currently paid pursuant to "The New Royalty
Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amended Act, 2008) and the "Alberta Royalty Framework", which was
implemented in 2010. Royalty rates for conventional oil are set by a single sliding rate formula, which is applied monthly and incorporates separate
variables to account for production rates and market prices. The maximum royalty payable under the royalty regime is 40%. Royalty rates for natural
gas under the royalty regime are similarly determined using a single sliding rate formula with the maximum royalty payable under the royalty regime
set at 36%.
Producers of oil and natural gas from freehold lands in Alberta are required to pay freehold mineral tax, in addition to privately negotiated royalties
payable to the freehold owners. The freehold mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production
from non-Crown lands and is derived from the Freehold Mineral Rights Tax Act (Alberta). The freehold mineral tax is levied on an annual basis on
calendar year production using a tax formula that takes in consideration, among other things, the amount of production, the hours of production,
the value of each unit of production, the tax rate and the percentages that the owners hold in the title. The basic formula for the assessment of
freehold mineral tax is: revenue less allocable costs equals net revenue dived by wellhead production equals the value based upon unit of production.
If payors do not wish to file individual unit values, a default price is supplied by the Crown. On average, the tax levied is 4% of revenues reported
from fee simple mineral title properties.
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, 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 owned by private freehold mineral rights holders 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, subject to regulatory oversight by the Provincial government regulators.
Liability Management Programs
In Alberta, the AER implemented the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management
program governing most conventional upstream oil and gas wells, facilities and pipelines. The OGCA establishes an orphan fund (the "Orphan
Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or
working interest participant ("WIP") becomes defunct or otherwise unable to cover such costs. The Orphan Fund is funded by licensees in the AB
LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by
unfunded liability of licences and prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities
or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed its deemed assets to provide the AER with a security deposit.
The ratio of deemed liabilities to deemed assets is assessed once each month and failure to post the required security deposit may result in the initiation
of enforcement action by the AER.
Effective May 1, 2013, the AER implemented important changes to the AB LLR Program that resulted in a significant increase in the number of oil
and gas companies in Alberta that are required to post security. Some of the important changes include:
• 25% increase to the prescribed average reclamation cost for each individual well or facility (which will increase a license's deemed liabilities);
• $7,000 increase to facility abandonment cost parameters for each well equivalent (which will increase a licensee's deemed liabilities);
• A decrease in the industry average netback from a five-year to a three-year average (which will affect the calculation of a licensee's deemed
assets, as the reduction from five to three years means the average will be more sensitive to price changes); and
• A change to the present value and salvage factor, increasing to 1.0 for all active facilities form the current 0.75 for active wells and 0.50 for
active facilities (which will increase a licensee's deemed liabilities).
The changes will be implemented over a three-year period, ending May 2015. The changes to the AB LLR Program stem from concern that the
previous regime significantly underestimated the environmental liabilities of licensees.
As of January 3, 2015, as published on the AER website, none of the E&P Companies had deemed liabilities which exceeded their deemed assets
and thus are not currently required to provide the AER with a security deposit pursuant to the AB LLR Program.
Environmental Regulation
Environmental Legislation in the Province of Alberta pertaining to oil and gas activities has been primarily consolidated into the EPEA, the OGCA
and the Water Act. Together the EPEA, OGCA and Water Act, which are under the jurisdiction of the AER to the extent they relate to oil and gas
operations, impose certain environmental standards, reporting and monitoring obligations, water use and disposal restrictions, responsibilities and
penalties which may be significant for violations.
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The operations of the E&P Companies may become subject to certain Federal and Provincial government proposals and legislative initiatives regarding
climate change and greenhouse gas emissions. On January 24, 2008, the Alberta Government announced a new climate change action plan that aims
to cut Alberta's projected 400 million tonnes of emissions in half by 2050. 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
Specified Gas Emitters Regulation ("SGER") enacted under the Climate Change and Emissions Management Act came into effect on July 1, 2007. Under the
SGER, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 percent. Industries
have four options to choose from in order to meet the reduction requirement outlined in this legislation: (i) make improvements to operations that
result in reductions; (ii) purchase emission performance credits from other regulated facilities that have reduced their emissions intensity by more
than 12 percent; (iii) purchase emissions offset credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and have
voluntarily reduced their emissions; (iv) contribute to the Climate Change Emissions Management Fund (the "Fund"). Industry can choose one of
these options or a combination thereof. The current contribution price to the Fund is $15 per tonne of CO2 emitted
The Company believes that the E&P Companies are, and expects that the E&P Companies will continue to be, in material compliance with applicable
environmental legislation and regulations and is committed to ensuring the E&P Companies meet their responsibilities to protect the environment
wherever they 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.
The Land Contract Drilling Industry
The land contract drilling industry provides the drilling rigs, rig labor and technical expertise necessary for exploration and production companies to
develop their significant investments in oil and natural gas resources. Over the last decade, technological advancements in hydraulic fracturing,
stimulation and other areas have allowed exploration and production companies to extract hydrocarbons from both conventional and unconventional
resource plays that were previously thought to be uneconomic.
Land Rig Replacement Cycle
The increase in horizontal drilling in North America over the past ten years has resulted in an ongoing land-rig replacement cycle in which the contract
drilling industry is systematically upgrading its legacy fleets of SCR and mechanical rigs with modern AC rigs that are specifically designed to optimize
this type of drilling activity.
Mechanical Rigs. Mechanical rigs were not designed and are not well suited for the demanding requirements of drilling horizontal wells. A mechanical
rig powers its systems through a combination of belts, chains and transmissions. This arrangement requires the rig to be rigged up with precise
alignment of the belts and chains, which requires substantial time during a rig move. In addition, mechanical power loading of key rig systems,
including drawworks, pumps and rotating equipment results in very imprecise control of system parameters, causing lower drill bit life, lower rate of
penetration and difficulty maintaining wellbore trajectory.
SCR Rigs. In contrast to mechanical rigs, SCR rigs rely on direct current ("DC") to power the key rig systems. Load is changed by adjusting the
amperage supplied to electric motors powering key rig systems. While a substantial improvement over mechanical belts and chains, SCR control is
imprecise, and DC power levels normally drift resulting in fluctuations in pump speed and pressure, bit rotation speed, and weight on bit. These
fluctuations are the major causes of wellbore deviation, shorter bit life and less optimal rates of penetration. In addition, SCR equipment is heavy
and energy inefficient.
AC Rigs. Compared to SCR and mechanical rigs, AC rigs are ideally suited for drilling horizontal wells. The first AC rigs were introduced into the U.S.
land market in the early 2000s, and since that time their use has grown significantly as the use of horizontal drilling has increased. AC rigs use a
computer-controlled variable frequency drive to precisely adjust key rig operating parameters and systems allowing for optimization of the rate of
penetration, extending bit life as vibration and torqueing is dramatically reduced and improving control of wellbore trajectory. These factors reduce
the amount of time a wellbore is "open hole," or uncased. Shorter open hole times dramatically reduce adjacent formation damage through shale
hydration or drilling fluid filtrate invasion and enhance the operator's ability to optimally run and cement casing to complete the drilled well. In
addition, when compared to SCR and mechanical rigs, AC rigs are electrically more efficient, produce more torque, utilize regenerative braking, and
have digital controls. AC motors are also smaller, lighter and require less maintenance than DC motors.
Developmental Drilling
Cost effective development drilling requires more complex well designs, shorter cycle times and the use of innovative technology in order to reduce
an exploration and production company's overall field development costs. Drilling rigs that are designed to maximize drilling efficiency, reduce cycle
times, maximize energy efficiency, increase penetration rates while drilling, and drill longer-reach horizontal wells will reduce an exploration and
production company's overall field development costs and provide them with greater optionality when designing their field development program.
ICD's ShaleDriller™ rigs include the following equipment and design features:
•
Pad Capable: Pad capable rigs increase efficiency by permitting the drilling rig to move quickly between well sites on a well pad while drill
pipe remains in the derrick, thus greatly reducing move times and costs for the operator. Pad capable rigs move from well to well on a pad
by using either a skidding system, where the rig skids in a single direction on rails across the pad, or a walking system, where the rig moves
via hydraulic feet. The most advanced walking systems are multi-directional, having independent hydraulic feet that are capable of moving
in any direction, not just along an X or Y axis. This feature allows them to maximize flexibility when moving rapidly on crowded and
complex pads and to efficiently address misaligned wellbores and variations in pad levels.
•
Fast-Moving: Fast-moving rigs are specifically designed to reduce cycle times by reducing rig-move time between drilling locations. Fastmoving rigs can be moved in fewer truck loads than standard rigs and, in many cases, can rig up and down more rapidly without the use
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of cranes. By minimizing the time in transit and rig up and rig down time, fast moving rigs help speed up development drilling programs
and maximize the economics of exploration and production companies' fields.
•
Bi-Fuel Capable: Bi-fuel capable rigs can operate on diesel fuel, natural gas, or a blend of the two, which can offer a reduction in carbon
emissions and provide significant fuel cost savings for the operator.
•
Top Drive Systems: Rigs equipped with a top drive system have the equipment which rotates the drill pipe located in the top of the derrick.
The top drive has a passageway for drilling mud to enter the drill pipe, and it has a heavy-duty electric motor connected to a threaded drive
shaft which connects to and rotates the drill pipe. Top drives provide high torque and rotational control, improved well control and better
hole conditioning. In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional
rotary drilling
•
High Horsepower Drawworks: Rigs powered by 1500-hp drawworks are well suited for the development of the vast majority of unconventional
resource assets. Compared to a 1000-hp or smaller rig, a 1500-hp rig has superior capability handle the extended drill lengths required to
drill horizontal wells, which are becoming more common in ICD's target markets.
•
Blowout Preventer ("BOP") Handling System: BOP handling systems allow precise control and positioning of the BOP stack via remote control
and removes the handling of the BOP stack from the critical path of well operations. BOP handling systems also enable drilling rigs with
walking capability to walk from well to well by suspending the BOP stack from the substructure. BOP handling systems provide a safer
and more efficient BOP handling operation when compared to conventional methods, which require lifting of the BOP by third party
rental equipment or through use of the rig's traveling block.
•
High Pressure Mud Pumps: High pressure mud pumps allow mud to be pumped through extended horizontal distances while maintaining the
pressure necessary to power the mud motors utilized to rotate the drill bit. In addition, high pressure mud pumps provide sufficient pressure
necessary to remove drilling debris away from the drill bit while drilling extended length horizontal wells.
•
Advanced Tubular Handling Equipment: Advanced tubular handling systems, such as iron roughnecks and hydraulic catwalks, significantly
increase safety at the well site and provide costs savings to the operator through added efficiency. An iron roughneck is a remotely operated
pipe handling system on the rig floor used in lieu of manual pipe handling by the rig's crew. This equipment enhances safety and decreases
the time required to move many lengths of drill pipe into and out of the well. A hydraulic catwalk is a drill pipe handling system used to
raise drill pipe, drill collars, casing, and other necessary items from the drilling rig floor. Its function significantly improves safety performance
and reduces drilling downtime, thereby decreasing operator costs for handling casing.
Increased Use of Pad Drilling
Pad drilling involves the drilling of multiple wells from a single location, which provide benefits to the exploration and production company in the
form of per well cost savings and accelerated cash flows as compared to non-pad developments. These cost savings result from reduced time required
to move the rig between wells, centralized hydraulic fracturing operations and the efficient installation of central production facilities and pipelines.
In addition, by performing drilling operations on one well with simultaneous completion operations on a second well, operators do not have to wait
until the entire pad is drilled to begin earning a return on their investment. Pad drilling promotes "manufacturing" efficiencies by enabling "batch"
drilling, whereby an operator drills all of the wells' surface holes as a batch, then drills all of the intermediate sections, and concludes with the drilling
all of the laterals. Efficiencies are created because hole sizes change less often and operators use the same mud system and tools repeatedly.
In order to maximize the efficiencies gained from pad drilling, a rig must be capable of moving quickly from one well to another and address the
complexities associated with the growing number of wells per pad. In addition to quickly moving from well to well, multi-directional walking systems
are ideally suited to optimizing pad drilling because they are capable of efficiently addressing situations on a pad in which wellbores are not precisely
aligned or when level variations exist on the pad, which becomes increasingly likely as pads become larger and more complex.
Shift to Longer Lateral Lengths
Operators in ICD's target areas have continued to increase the lateral length of their horizontal wells. Longer laterals provide greater production
zones as the portion of the wellbore that passes through the target formation increases, optimizing the impact of hydraulic fracturing and stimulation.
ICD's rigs have drilled some of the longest horizontal wells to date in the Permian Basin, including a well with a lateral section in excess of 13,980
feet. The drilling of longer laterals necessitates the use of increased horsepower drawworks and top drive systems, which provide maximum torque
and rotational control and allows the operator to maintain the integrity of its drilling plan throughout the wellbore. Additionally, higher pressure mud
pumps are required to pump fluids through significantly longer wellbores. The competitive advantage of higher pressure mud pumps grows as the
lateral length gets longer, as only high pressure pumps can effectively address the severe pressure drop while providing the required hydraulic horsepower
at the bit face and sufficient flow to remove drill cuttings and keep the hole clean.
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MINING SECTOR
The Investments held by the Company in the Mining Sector as at December 31, 2014 include investments in Corsa, Potash Ridge, Stonegate Agricom,
a public company that owns a uranium deposit in southern Virginia, U.S., a public mining company with interests in nickel, zinc, copper and other
minerals and a public gold development company.
Corsa Coal Corp.
Corsa is a Canadian public company (TSX-V:CSO) engaged in the mining, processing and selling of metallurgical and thermal coal, as well as the
active exploration, acquisition and development of resource properties that are consistent with its existing coal business. Corsa's goal is to focus on
niche coal markets which command premium pricing and have a delivered cost advantage to customers, while maintaining low-cost operations and
sufficient infrastructure to achieve sustainable growth.
Corsa's coal operations are conducted through two divisions: (i) the Northern Appalachia Division ("NAPP"); and (ii) the Central Appalachia Division
("CAPP"). NAAP consists of the Wilson Creek and PBS Coals metallurgical coal mines in Somerset, Pennsylvania, U.S., and is focused on lowvolatile metallurgical coal production and sales in the Northern Appalachia of the United States. CAPP is based in Knoxville, Tennessee, U.S., and
is focused on thermal coal production and sales in the Southern Appalachia coal region of the United States.
The principal market for Corsa’s metallurgical coal is domestic and international steel producers and the principal market for Corsa’s thermal and
industrial coals is domestic electric utilities and industries. The primary distribution method for Corsa’s coal is by rail from a preparation plant to the
customer; however, distribution by truck or by truck and barge to the customer is also utilized.
The Company's initial investment in Corsa was made in the third quarter of 2014 for $36.4 million or $0.15 per Corsa Share. As at December 31,
2014, the Company owned 237 million Corsa Shares valued at $0.19 per share for an aggregate investment value totaling $43.8 million (approximately
a 20.5% increase since the initial investment in August 2014).
Potash Ridge Corporation
Potash Ridge is a Canadian based public company (TSX:PRK) that engages in the exploration and development of mineral resources. The company's
principal mineral project is the Blawn Mountain project (the "Blawn Mountain Project") in Utah, U.S. Potash Ridge intends to mine surface alunite
deposits on the Blawn Mountain Project to extract and produce sulfate of potash ("SOP"), co-product sulphuric acid and, potentially, an alumina
rich material.
Alunite is a naturally occurring volcanic mineral containing potassium, sulphur and alumina. SOP is primarily used as a specialty fertilizer providing
essential potassium to high-value, chloride-sensitive crops, including nuts, fruit, vegetables, tea, tobacco and turf grass. It is most widely used in China,
Europe and the United States and typically sells at a premium over traditional muriate of potash ("MOP") because of its favourable impact on crop
yield and quality and its superior performance over MOP.
Potash Ridge is managed by a seasoned team with senior leadership experience at one of the world's leading mining companies. The company has
publicly disclosed that it intends to complete a feasibility study for the Blawn Mountain Project, subject to successfully raising additional financing.
As at December 31, 2014, the Company owned 21.2 million Potash Shares valued at $0.17 per share for an aggregate investment value totaling $3.6
million. As at December 31, 2013, the Company owned 21.2 million Potash Shares valued at $0.21 per share for an aggregate investment value
totaling $4.5 million. During 2014, the percentage decrease in the value of the Company's year-end holdings in Potash Ridge was approximately
19.0% (approximately a 68.7% decrease during 2013).
Stonegate Agricom Ltd.
Stonegate Agricom is a Canadian public company (TSX:ST) engaged in the development of its Paris Hills Project in Southeast Idaho, U.S.
In early January 2015, Stonegate Agricom announced that it has temporarily suspended permitting activities at its Paris Hills Project due to financial
constraints. On February 27, 2015, Stonegate Agricom announced a proposed private placement equity financing (the "Stonegate Private
Placement") that will be open to participation by existing shareholders in proportion to their ownership holdings as of the record date of February
26, 2015. The Stonegate Private Placement consists of the sale of a minimum 100,000,000 units ("Stonegate PP Unit") and a maximum 145,680,000
Stonegate PP Units at a price of $0.015 per Stonegate PP Unit, for gross proceeds of between $1,500,000 and $2,185,200. Each Stonegate PP Unit
consists of one Stonegate Share and a third of a common share purchase warrant ("Stonegate PP Warrant"). Each whole Stonegate PP Warrant
will entitle the holder to acquire one Stonegate Share at an exercise price of $0.02 per share for a period of 24 months following the Closing Date
(as defined below). The Stonegate Private Placement is subject to the acceptance of the TSX and is also subject to shareholder approval, which
Stonegate Agricom expects to obtain as a result of a shareholder vote at its annual and special meeting expected to be held on April 24, 2015. Stonegate
Agricom anticipates that the closing of the transaction will occur immediately after shareholder approval is obtained (the "Closing Date"). The
Company has informed Stonegate Agricom that it will not participate in the Stonegate Private Placement but that it will vote in favour of such
financing.
Stonegate Agricom has publicly disclosed that it intends to use the net proceeds raised in the Stonegate Private Placement as follows: (i) if the
minimum gross proceeds are raised, approximately US$500,000 will be used to conduct additional groundwater flow testing required for permitting
the Paris Hills Project, approximately US$450,000 will be used to cover property payments and overhead at the project, and the remainder will be
used for general corporate purposes; (ii) if the maximum gross proceeds are raised, the Company intends to also initiate a feasibility study on the
Upper Zone at the Paris Hills Project.
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Stonegate Agricom also owns the Mantaro phosphate project (the "Mantaro Project"), an exploration stage fertilizer project in Peru. The management
of Stonegate Agricom does not consider the Mantaro Project to be a material mineral property and no work is planned on such project at this time.
As at December 31, 2014, the Company owned 71.0 million Stonegate Shares and 12.5 million Stonegate Warrants valued at $0.05 per share and $0.01
per warrant, respectively, for an aggregate investment value totaling $3.3 million. As at December 31, 2013, the Company owned 71.0 million Stonegate
Shares and 12.5 million Stonegate Warrants valued at $0.18 per share and $0.02 per warrant, respectively, for an aggregate investment value totaling
$12.7 million. During 2014, the percentage decrease in the value of the Company's year-end holdings in Stonegate Agricom was approximately 73.7%
(approximately a 67.8% decrease during 2013).
Mining Sector Overview
Based on various factors including the fair value of the Company's Investments in the Mining Sector as of December 31, 2014, management of the
Company considers the coal industry the only mining sector material to the Company at this time.
The Coal Industry
The most significant uses of coal are in electricity generation and steel production. According to the World Coal Association ("WCA"), since 2000,
global coal consumption has grown faster than any other fuel. According to the U.S. Energy Information Administration, the five largest coal
consumption countries are China, the United States, India, Russia and Germany. These five countries account for approximately 75% of global coal
consumption.
According to the WCA, it has been estimated that there are over 861 billion tons of proven coal reserves worldwide, which is enough coal to last
approximately 112 years at current rates of consumption. The largest coal reserves are in the United States, Russia, China and India. Coal's appeal
is that it is readily available from a wide variety of sources; its prices have been lower and more stable than oil and gas prices over the long-term; and
it is likely to remain the most affordable fuel available for power generation in many developing and industrialized nations for several decades to
come. The U.S. is the second largest coal producer in the world.
Coal is traded all over the world, with coal shipped significant distances by sea to reach certain markets. According to the WCA, over the last 20 years,
seaborne trade of thermal coal has increased on average by approximately 7% each year and seaborne coking coal trade has increased by 1.6% per
year. The largest exporters of coal in 2013 were Indonesia, Australia, Russia and the United States. Per the WCA, the leading exporters of metallurgical
coal for steel making were Australia, the United States and Canada.
Coal and Steel
Steel is one of the most efficient modern construction materials. Steel offers the highest strength-to-weight ratio of any commonly-used material
and is exceptionally durable. Steel is an essential material used in the construction sector and is used to build high-rise buildings, bridges, tunnels and
viaducts. It is also a key material for building energy infrastructure such as electricity pylons, offshore oil platforms, hydroelectric power stations and
wind turbines. Coal is also used in the transport sector to build railroads, trains, airplanes, ships and cars.
Global steel production is dependent on coal. According to the World Steel Association ("WSA"), steel use increased worldwide between 2003 and
2013 by approximately 68%. Approximately 15% of total coal production is currently used by the steel industry and around 70% of global steel
production relies directly on inputs of metallurgical coal. The top five steel producing countries were China, Japan, the United States, India and
Russia. In 2013, approximately 1.6 billion metric tons of steel was produced globally, compared to 1.5 billion metric tons in 2012. The two main
steel production processes are via (i) a blast furnace and basic oxygen furnace, and (ii) an electric arc furnace.
The integrated steel making process is dependent on high quality metallurgical coal to produce coke. Metallurgical coal is converted to coke by driving
off impurities to leave almost pure carbon. The physical properties of coking coal cause the coal to soften, liquefy and then re-solidify into hard but
porous lumps when heated in the absence of air. The coking process consists of heating coking coal to around 1,000 to 1,100 degrees Celsius in the
absence of oxygen to drive off volatile compounds. This process results in a hard porous material, called coke, which is used in the production of
iron and steel. During the iron-making process, a blast furnace is fed with iron ore, coke, other minerals and air, which causes the coke to burn,
melting the iron. The iron is then combined with varying amounts of steel scrap in a basic oxygen furnace, which uses carbon content of coke to
make liquid steel. The steel industry uses coking coal which is distinguishable from other types of coal by its characteristics of lower volatility, lower
sulfur and ash content, higher Btu value and favorable coking characteristics (higher coke strength). According to the WCA, on average this process
uses 770 kilograms of coal to produce 1 ton of steel and approximately 70% of global steel is produced using the integrated steel making process
via a blast furnace-basic oxygen furnace.
The electric arc furnace process, or mini-mill, does not involve iron-making. It reuses existing steel, avoiding the need for raw materials and their
processing. The furnace is charged with steel scrap, it can also include some direct reduced iron ("DRI") or pig iron for chemical balance. Electric
arc furnaces do not use coal as a raw material, but many are reliant on the electricity generated by coal-fired power plants elsewhere in the grid.
According to the WCA, on average, this process takes 880 kilograms of recycled steel and 150 kilograms of coal to produce 1 ton of crude steel.
Approximately 29% of global steel is produced in electric arc furnaces.
Coal Characteristics
Coal is a combustible, sedimentary, organic rock, which is composed mainly of carbon, hydrogen and oxygen. It is formed from vegetation, which
has been consolidated between other rock strata and altered by the combined effects of pressure and heat over millions of years to form coal seams.
Coal is generally classified as either metallurgical coal or thermal coal (also known as steam and industrial coal). Sulfur, ash and moisture content as
well as coking characteristics are key attributes in grading metallurgical coal while heat value, ash and sulfur content are important variables in rating
thermal coal.
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Heat Value: The heating value of coal is supplied by its carbon content and volatile matter and commonly measured in Btus. Coal deposits are generally
classified into four categories, ranging from lignite, subbituminous, bituminous and anthracite, reflecting their response to increasing heat and pressure.
Sulfur Content: Sulfur content can differ from coal seam to coal seam. Low sulfur coals have a sulfur content of 1.5% or less. Coal produces undesirable
sulfur dioxide when it burns, the amount of which depends on the concentration of sulfur in the coal as well as the chemical composition of the
coal itself.
Ash and Moisture Content: Ash is the residue that remains after the combustion of coal. Low ash is desirable because businesses must dispose of ash
after the coal is used. High moisture content decreases the heat value of the coal and increases the coal's weight, both of which are undesirable.
Coking Characteristics (metallurgical coal only): Two important coking characteristics are coke strength and volatility. Volatility of coking coal is used to
determine the percentage of coke that a given type of coal would produce. This measure is known as coke yield. A low volatility results in a higher
coke yield.
Types of Coal
Metallurgical coal is classified into three major categories: hard coking coal ("HCC"); semi-soft coking coal; and pulverized coal injection coal ("PCI").
Coking coals are the basic ingredients for manufacture of metallurgical coke. PCI coal is not used in coke making but is rather injected directly into
the lower region of blast furnaces to supply both energy and carbon for iron reduction. The use of PCI can be a substitute for some of the metallurgical
coke that would otherwise have been used.
Thermal and industrial coal is the most abundant form of coal and is commonly referred to as steam coal. Such coal has a relatively high heat value
and has long been used for steam generation in electric power and industrial boiler plants.
Coal Mining Methods
Coal is mined using both underground and surface mining methods. The mining methods employed are determined by the geological characteristics
of coal reserves.
Underground Mining
Underground mining methods are employed when coal reserves cannot be mined using surface mining methods. The two different underground
mining techniques are long wall mining and room-and-pillar mining.
In long-wall mining, mechanized shearers are used to cut and remove the coal from long rectangular blocks of medium to thick coal seams called
panels. Continuous miners are used to develop access to these coal blocks. After the coal is removed, it drops onto a conveyor system that takes the
coal to production shafts or slopes where it is hoisted to the surface. In long-wall mining, mobile hydraulic powered roof supports, called shields,
hold up the roof throughout the extraction process.
In room-and-pillar mining, a network of rooms is cut into the coal seam by continuous miners, while also leaving a series of coal pillars to support
the mine roof. Shuttle cars and continuous haulage systems transport the coal to the surface.
Surface Mining
Surface mining methods are employed when coal reserves are located close to the surface.
Contour surface mining involves removing the topsoil followed by a process of drilling and blasting the overburden covering the coal seam with
explosives. The overburden is then removed with earth-moving equipment such as draglines, power shovels, excavators and loaders exposing the
coal seam. Once exposed, the coal seam is extracted and loaded into haul trucks for transportation to preparation plants or load-out facilities. After
the coal is removed, reclamation activities use the topsoil and overburden removed at the beginning of the process to backfill the excavated coal pits
and disturbed areas. After the overburden and topsoil are replaced, vegetation is re-established into the reclaimed area. Ultimate seam recovery for
surface mining typically exceeds 80% and is dependent on overburden, coal thickness, geological factors, and equipment used.
High-wall surface mining involves using a high-wall mining machine to mine coal seams exposed during the contour surface mining process that the
earth moving equipment used for contour surface mining cannot access.
Coal Markets
Coal prices differ substantially by region and are impacted by many factors including the overall economy, demand for steel, demand for electricity,
location, market, quality and type of coal, mine operation costs and the cost of customer alternatives.
Metallurgical Coal
Current metallurgical coal prices are at a level where a significant amount of global production is uneconomic. Based on information contained in
documents publicly filed by Corsa, prices in the domestic metallurgical coal markets for 2014 have fallen from 2013 levels by approximately 10%
and prices for export shipments in 2014 have declined approximately 21% from 2013 levels. As a result, a significant portion of the global seaborne
coal production is being produced at a loss, a situation that many view as unsustainable. As publicly disclosed by Corsa, producers have responded
to these conditions and have increasingly shown supply discipline, announcing production cuts of approximately 20 million metric tonnes of
production so far this year.
Settlements on 2015 domestic metallurgical coal sales are starting to take place. Export pricing has been very competitive due to oversupply, particularly
from Australian mines, and a weaker Australian dollar.
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Thermal Coal
According to information contained in documents publicly filed by Corsa, the current thermal coal pricing in the Southeastern United States utility
market has declined 5% over the course of 2014. As a result, much of the Central Appalachia coal production is below the marginal supply curve.
Corsa expects that utility coal demand for Central Appalachia production will decrease in 2015. Conversely, Corsa has publicly disclosed that industrial
thermal coal demand grew 4% year over year for 2014 and is expected to grow 1% in 2015.
Environmental and Other Regulatory Matters
Corsa's business is subject to numerous federal, state, provincial and local laws and regulations with respect to matters such as permitting and licensing,
employee health and safety, reclamation and restoration of property and protection of the environment. In the United States, environmental laws
and regulations include, but are not limited to, the federal Clean Air Act and its state and local counterparts with respect to air emissions; the federal
Clean Water Act and its state counterparts with respect to water discharges; the Resource Conservation and Recovery Act and its state counterparts
with respect to solid and hazardous waste generation, treatment, storage and disposal, as well as the regulation of underground storage tanks; and
the federal Comprehensive Environmental Response, Compensation and Liability Act and its state counterparts with respect to releases, threatened
releases, and remediation of hazardous substances. Other environmental laws and regulations require reporting, even though the impact of that
reporting is unknown. Corsa's compliance with these laws and regulations may be costly and time-consuming and may delay commencement,
continuation or expansion of exploration or production at its operations. These laws are constantly evolving and becoming increasingly stringent.
The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that certain
implementing regulations for these environmental laws have not yet been promulgated and in certain instances are undergoing revision.
AGRICULTURE SECTOR
The Investments held by the Company in the Agriculture Sector as at December 31, 2014 include investments in UAG and OEF.
Union Agriculture Group
UAG is the single largest corporate agricultural landholder and operator in Uruguay and a leading producer of agricultural products for global export,
including soybeans, wheat, corn, sorghum, rice, cattle, sheep and dairy.
Due to its soil quality, water supply and compelling land prices, Uruguay possesses unique competitive advantages for agriculture production. UAG
is focused on acquiring high-quality, under-utilized agricultural land and developing it in an efficient and sustainable manner. Consistent with this
mandate, in February 2014, UAG completed the acquisition of all of the Uruguayan assets of El Tejar-Uruguay, the second largest agribusiness in
Uruguay. UAG has publicly disclosed that it manages 181,000 hectares of farmland in Uruguay, or just over one per cent of the country’s land surface.
The Company understands that UAG intends to continue its expansion of operations and land holdings in Uruguay, while improving operational
efficiencies in order to continue its evolution into a low-cost, global food exporter.
As at December 31, 2014, the Company owned 3.4 million common shares of UAG ("UAG Shares") with a fair value of $38.7 million or $11.41 per
share. As at December 31, 2013, the Company owned 3.4 million UAG Shares with a fair value of $34.2 million or $10.09 per share. During 2014,
the percentage increase in the value of the Company's year-end holdings in UAG was approximately 13.1% (approximately a 11.7% decrease during
2013).
One Earth Farms Corp.
OEF was founded in 2009 and is now headquartered in Toronto, Canada and is a vertically integrated branded food products business focused on
meat-based proteins sourced from animals raised in humane conditions without antibiotics, added hormones or steroids under a Natural or Organic
protocol. OEF's products are available to consumers through select national grocery chains, leading natural and organic food retailers, direct home
delivery, and a specialty catering operation that provides meals to corporate and other clients based around the Beretta Farms product line. "Natural"
protocols refer to animals raised without the use of antibiotics, added hormones or steroids. "Organic" protocols refer to animals raised under CAN/
CGSB-32.310, Organic Production Systems General Principles and Management Standards issued by the Canadian General Standards Board, and that are
certified Organic.
OEF's restructuring efforts, which began in 2013, were substantially completed in 2014. In 2014, OEF completed its exit from its remaining crop
operations, reflecting the historical financial performance of the company in crop farming operations, the limited fit with OEF's strategic direction,
the significant capital required to undertake crop operations, and the current and expected future market conditions and commodity price volatility.
In 2014, OEF also completed the restructuring of its business model with respect to its cattle operations, which as at December 31, 2014 included
a total of approximately 17,400 head of cattle across its cow/calf and feeder operations. OEF's cow/calf operations are now custom managed
under OEF's protocols by third parties in twelve ranches located in the provinces of Saskatchewan, Alberta and Ontario. The cow/calf operations
are subject to inspection and monitoring by OEF personnel as well as third party independent auditors. OEF's feeder operations are conducted by
five custom operators in Alberta, Saskatchewan and Ontario.
As part of its strategy and restructuring, OEF has continued to examine acquisition opportunities across the supply chain. In October 2014, OEF
completed the acquisition of Canadian Premium Meats Inc. ("CPM"), a federally regulated and EU-certified slaughter and processing facility located
in Lacombe, Alberta. The acquisition of CPM represents a further step in OEF’s strategy to increase the level of vertical integration of its business
model in order to control cost and strategic advantage through the supply chain. CPM is one of only four EU-certified plants in Canada, adding a
critical element to OEF's ability to expand its business in the export market. Subsequently, OEF also acquired the assets of an existing beef brand
with significant distribution in Canada and the EU and another existing beef brand with significant distribution in Western Canada. OEF's food
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products are currently sold under the Beretta Farms, Beretta Kitchen, Heritage Angus, Diamond Willow Organics, Chinook Organics and Sweetpea
Baby Food brands in five Canadian provinces along with select EU markets, China and the Middle East.
In the third quarter of 2014, the Company made a follow-on investment in OEF for $3.4 million. As at December 31, 2014, the Company owned
66.8 million OEF Shares with a fair value of $31.0 million or $0.46 per share. As at December 31, 2013, the Company owned 60.0 million OEF
Shares with a fair value of $26.5 million or $0.44 per share. During 2014, the percentage increase in the value of the Company's year-end holdings
in OEF was approximately 4.5% (approximately a 41.3% decrease during 2013).
Agriculture Sector Overview
Uruguayan Agriculture Industry Overview
Uruguay's territory consists primarily of plains, which, combined with its temperate climate, make the country well-suited for agriculture and livestock.
The Soybean Sector
Global oilseed trade consists of numerous commodities that are closely substitutable, and includes soybeans, canola, sunflowerseed and cottonseed.
In addition to the seed, oil and meal obtained from crushing oilseeds are traded in certain countries. The import demand in a particular country is
dependent on the difference between the country's domestic oilseed output and its consumption. Divergent demand for protein meal and vegetable
oil, as well as limits on domestic processing capacity, determines the ratio of oilseeds to oilseed products that a particular country imports. The
volume and source of foreign imports depend on seasonal availability and relative prices, credit and delivery terms, local preferences, and quality. The
policies of specific countries, such as tariffs and domestic subsidies, also can affect prices and the availability of competing products.
Soybean meal accounts for 50% to 75% of the value obtained from processing soybeans, depending on relative prices of soybean meal and oil.
Livestock (including poultry) feeds account for the large majority of soybean meal consumption, with the remainder used in human foods such as
bakery ingredients and meat substitutes.
Soybean oil generally has a smaller contribution to the value obtained from processing soybeans, as oil constitutes approximately 18% to 19% of a
soybean's weight. Soybean oil is mainly used in salad and cooking oil, bakery shortening and margarine, as well as in a number of industrial applications.
Soybeans are one of the most important crops in Uruguay, with substantial growth in production occurring since approximately 2002. A key driver
of this growth has been the introduction of new technologies, allowing the farming of land previously suitable only for cattle-grazing. Furthermore,
attractive soil conditions, moderate temperatures and ample water availability allow for double cropping.
The Wheat Sector
Historically, in most years the United States, Canada, Australia, the EU, the former Soviet Union (including three major wheat exporters: Russia,
Ukraine and Kazakhstan), and Argentina together account for about 90% of world wheat exports.
Similar to soybeans, wheat has become an increasingly important crop in Uruguay and has benefited from new technology that allows the conversion
of land from cattle-grazing to grain-farming. Furthermore, attractive soil conditions, moderate temperatures and ample water availability allow for
double cropping.
The Rice Sector
Rice is the primary staple crop for the majority of the world's population. Consumers in developing countries depend on the versatility and high
caloric value of rice. Rice is produced worldwide and is the world's third-largest staple crop, trailing corn (maize) and wheat. Although rice is produced
in many countries, rice fields are limited to certain areas due to the physical requirements for growing rice, such as available water and soil types.
Economically viable production typically requires high average temperatures during the growing season, a plentiful supply of water applied in a timely
fashion, a smooth land area to facilitate uniform flooding and drainage, and a subsoil hardpan that inhibits the percolation of water.
Although now surpassed by soybeans and wheat as the most important crop in Uruguay, rice has historically been a staple of the Uruguayan agricultural
industry. Farming conditions in Uruguay meet the requirements for rice production outlined above. The favourable conditions in Uruguay allow for
irrigation. As a result, Uruguay is one of the largest rice exporters in Latin America and the world.
The Beef and Sheep Sector
Beef production is the most important agricultural activity in Uruguay, using the majority of the country's productive land. Furthermore, Uruguay
has one of the highest annual per capita consumptions of beef in the world, according to the United States Department of Agriculture. Several
factors have enabled Uruguay to become a major player in the global beef trade, including access to key export markets, above-average sanitary
conditions and the ability to react quickly to consumer demand.
Sheep production is also an important economic activity within the agriculture business in Uruguay. There are approximately 7.5 million heads of
sheep in Uruguay, mostly located in the northern and eastern part of the country.
The Dairy Sector
Dairy farming is an important and established agricultural activity in Uruguay. The use of state-of-the-art production technologies has caused
productivity to increase, making it possible for Uruguay's total milk production to increase. In addition, Uruguay has important competitive advantages
compared to other milk producing countries due to lower production costs.
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Land Usage and Pricing
Uruguay offers a very attractive arable land profile with potential for growth. Uruguay's soil resources are of high quality and are well preserved.
Within the past 20 years, agricultural activity in Uruguay expanded to land that were previously considered not usable for agriculture. The expansion
of agricultural activity on new land is still taking place in Uruguay and is related to the introduction of new farming technology, such as no-till farming,
which does not disturb the soil through tillage. No-till farming practices allow Uruguay to increase its grain production by farming in new areas while
maintaining high yields and preserving the soil.
Farmland prices are based on local markets and hence prices differ between countries due to specific country-related factors. Such specific factors
may include the fertility of the land, the state of the land due to previous management, current yield levels, current and expected crop prices, availability
and cost of financing, agricultural support, geographic proximity to infrastructure such as seaports and railroads, and climatic conditions.
Canadian Food Industry Overview
The modern food industry in Canada is large and well established, serving end consumers with a diverse range of products. OEF operates within a
niche of the food industry focused on the development, preparation, distribution and sale of Natural and Organic food products.
Product Development
Based on market and consumer research, food products companies undertake the development of products that they believe will be appealing to end
consumers. Ingredients, preparation techniques, taste and nutritional content are among the attributes that are important differentiators of products
and influence the cost to produce, product pricing and the ultimate competitive position of products in the marketplace.
Procurement of Inputs
Many food product companies establish relationships with specialized suppliers for the various ingredients required for their products, while in other
cases vertical integration to control the production of key inputs is pursued.
Processing and Packaging
This stage includes the preparation of ingredients into a final food product, including, where appropriate, cooking. This work may be performed in
facilities operated by the food products company or outsourced to contract manufacturers.
Distribution, Sales and Marketing
Manufacturers of food products can reach markets and customers through several different channels including, but not limited to, (i) on a wholesale
basis to food retailers that range from small players to large national chains; (ii) on a private label basis, where the manufacture of a product is provided
for offer under another company's brand; and (iii) directly to end consumers through mediums such as the internet and company owned retail outlets.
Food products companies seek to establish and improve the sales and margins of their products by increasing customer loyalty through marketing
and branding, and establishing and maintaining ongoing relationships with food retailers through its sales staff. Maintaining an effective supply chain
and managing inventory to respond to customer and consumer demands is important for success.
Canadian Beef Industry Overview
The Canadian beef industry 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, management capabilities, animal health management and a high level of investment in
working capital.
The term 'cattle' broadly refers to cows (mature females who have given birth to at least 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 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 sections chronologically set out the events in the cattle cycle, several of which overlap, portraying the process from genetic selection
through to beef processing.
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
sources. The key selection criteria typically are animals with a low death loss rate at birth, high rate of gain after birth and good feed efficiency.
Breeding Phase
Replacement heifers and mature cows will be bred naturally. This phase typically lasts for 60 days, during which the females are co-mingled 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
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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
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. OEF follows a Natural or Organic
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 OEF's animals and beef. This phase also overlaps with the seedstock selection, breeding and gestation phases.
Weaning
The weaning phase 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. OEF generally feeds all of its
calves through to finishing weight prior to conversion into beef products to be sold under OEF brands. 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
The 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. Natural and
Organic protocols for feeding specify the feedstock, and in the case of Organic protocols, the feedstock must be certified Organic.
Beef Processing
Beef processing involves the humane handling and slaughtering of cattle at abbatoirs that are either provincially or federally regulated. As the slaughter
process begins, livestock are contained to limit physical movement of the animal. The animal is stunned to ensure a humane end. Stunning also results
in decreased stress of the animal and superior meat quality. After stunning, the carcass is suspended for exsanguination followed by further processing
into primary beef products and byproducts. Throughout the process, attention is paid to animal welfare; food hygiene and safety; worker health,
welfare and safety; and production efficiency.
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 and its 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 and its 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 and its Investments, as applicable, may be harmed and their respective financial condition, results of
operations and cash flows 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 Company Generally
Investment Entity
The Company holds interests in the Investments. As a result, investors in the Company are subject to the risks attributable to the Investments.
The Company's ability to pay its expenses and any future dividends, to meet its obligations and to execute on current or desirable future opportunities
or acquisitions generally depends upon receipt of dividends from Investments, sufficient proceeds from the divestment of Investments, and the
Company's ability to raise additional capital. The likelihood that shareholders of the Company will receive returns will be dependent upon the operating
performance, profitability, financial position and creditworthiness of the Investments and on their ability to pay dividends to the Company or to be
divested by the Company at a gain.
Commodity Prices
The profitability of the Company's investments will be dependent upon the market price of mineral commodities, oil and natural gas and other natural
resources relevant to the particular investment. Decreases in the market price of such commodities could have an adverse effect on the Company's
business, financial condition, results of operations and common shares. 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
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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. Since the Company has significant investments in the oil and natural gas industry,
any improvement in or new discoveries of alternative energy technologies that increase the use of alternative forms of energy and reduce the demand
for oil and natural gas could have a material adverse effect on the Company's business, financial condition and results of operations.
Price Volatility
Securities of natural resource 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 Company's common shares, the market price
of public companies and the fair price of private 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 or at acceptable prices 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, 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 the Company 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 the Company'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.
Key Management and the 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. SRC's officers and employees are provided by SCLP pursuant to the
Amended and Restated MSA. SCLP may terminate any of the Company's key officers, consultants and employees without notice to the Company.
In addition, pursuant to the Amended and Restated MSA, SCLP may terminate the Amended and Restated MSA upon 180 days' notice. The termination
of any of the key officers, consultants or employees of the Company or 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.
Access to Capital
If required, the ability of the Company to arrange additional financing in the future will depend in part upon prevailing market conditions as well as
the business performance of the Company and the Investments. There can be no assurance that debt or equity financing will be available, or, together
with internally generated funds, will be sufficient to meet or satisfy the Company’s objectives or requirements or, if the foregoing are available to the
Company, that they will be on terms acceptable to the Company.
Foreign Currency Risk
The Company has United States dollar denominated investments totaling $70.4 million as at December 31, 2014. A 5% change in the currency
exchange rate (U.S. to CAD dollar) will affect the Company's net income in a given period by approximately $3.5 million. The Company does not
currently hedge its foreign exchange exposure.
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Conflicts of Interest
Certain directors and officers of the Company are or may become associated with other natural resource companies, SCLP, Sprott Inc., Sprott Resource
Lending Corp., Sprott Asset Management LP or Sprott Korea Corp., 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 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.
Dividends and DRIP
On August 13, 2013, the Board elected to terminate the DRIP and to cease paying monthly dividends. The Company does not currently intend to
pay a dividend on its common shares. Any future determination to pay dividends will be at the discretion of the Board and will depend upon the
capital requirements of the Company, results of operations and such other factors as the Board considers relevant.
Cybersecurity Risks and Threats
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. It is possible that the
business, financial and other systems of the Company or the companies in which it has invested could be compromised, which might not be noticed
for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, disruption of business operations
and safety procedures, loss or damage to worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events.
Risks Relating to the Energy Sector
Risks Relating to the Oil and Gas Exploration and Production Industry
The Company encourages you to consult Long Run's public disclosure record for information on risk factors affecting their business, including the
factors described in the section entitled ‘‘Risk Factors” in Long Run’s annual information form for the year ended December 31, 2013 (available under
Long Run's profile on SEDAR at www.sedar.com), which section (the "2013 Long Run Risk Factors") is incorporated by reference into this AIF.
The 2013 Long Run Risk Factors shall be deemed to no longer be incorporated by reference into this AIF upon the filing, under Long Run's profile
on SEDAR at www.sedar.com, of the 2014 Long Run AIF, at which time the risk factors in the 2014 Long Run AIF will be deemed to be incorporated
by reference into this AIF.
The following risks specifically apply to the E&P Companies, as noted, as well as, more generally, other companies in the oil and gas exploration and
production industry.
Volatility in Oil and Natural Gas Prices
The E&P Companies' results of operations and financial condition are dependent on the prices the E&P Companies receive for the oil and natural
gas (and related products) they produce and sell. Oil and natural gas prices 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 E&P Companies' control, including:
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global energy supply, production and policy, including the ability of the Organization of the Petroleum Exporting Countries ("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 including demand for different qualities and types of oil and liquids;
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;
government regulations;
the expected rates of declining current production;
technical advances affecting energy consumption;
domestic and foreign governmental regulations and taxes; and
speculative trading in oil and natural gas derivative contracts.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, NGL and natural gas price movements with
any certainty. A material decline in prices could result in a reduction of the E&P Companies' net production revenue. The economics of producing
from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes
of the E&P Companies' reserves. The E&P Companies might also elect not to produce from certain wells at lower prices.
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Oil and natural gas producers in North America, and particularly Canada, currently receive significantly discounted prices for their production due
to constraints on the ability to transport and sell such production to international markets. Additionally, limited natural gas processing capacity may
result in producers not realizing the full price for liquids associated with their natural gas production. A failure to resolve such constraints may result
in continued reduced commodity prices received by oil and natural gas producers such as the E&P Companies.
Any decline in crude oil or natural gas prices may have a material adverse effect on the E&P Companies' operations, financial condition, borrowing
ability, levels of reserves and the level of expenditures for the development of the E&P Companies' oil and natural gas reserves. Certain oil or natural
gas wells may become uneconomic to produce if market conditions deteriorate, thereby impacting the E&P Companies' production volumes.
Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply and the demand of these
commodities due to the current state of the world economies, OPEC actions, and sanctions imposed on certain oil producing nations by other
countries and ongoing credit and liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties
for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing
on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.
The Company or the E&P Companies 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 the E&P Companies hedge their commodity
price exposure, they may forgo the benefits they would otherwise experience if commodity prices were to increase. In addition, these commodity
price hedging activities could expose the Company or the E&P Companies 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 Sector - Risks Relating to the Oil and
Gas Exploration and Production Industry - Counterparty Risk" below.
Uncertainties Associated with Drilling and Well Stimulation Activities
The E&P Companies' future financial condition and results of operations will depend on the success of their exploration, development and production
activities. The E&P Companies' drilling and well stimulation activities are subject to many risks. For example, the E&P Companies can provide no
assurance that new wells drilled and completed by it will be productive or that the E&P Companies will recover all or any portion of their investment
in such wells. Drilling for oil, NGL and natural gas and attempts to stimulate well productivity often involve unprofitable efforts, not only from dry
wells but also from wells that are productive but do not produce sufficient oil, NGL or natural gas to return a profit at the realized prices after
deducting drilling, operating and other costs. The seismic data and other technologies the E&P Companies use do not allow them to know conclusively
prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development
activities are subject to numerous uncertainties beyond the E&P Companies' control, and increases in those costs can adversely affect the economics
of a project. Further, the E&P Companies' drilling, well stimulation and producing operations may be curtailed, delayed, canceled or otherwise
negatively impacted as a result of other factors, including:
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unusual or unexpected geological formations;
loss of drilling fluid circulation;
loss of title or other title related issues;
facility or equipment malfunctions;
surface access restrictions;
restrictions in oil, NGL and natural gas prices;
limitations in the market for oil, NGL and natural gas;
unexpected operational events;
shortages or delivery delays of equipment and services;
compliance with environmental and other governmental requirements; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and
equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
In addition, drilling for unconventional oil, NGL and natural gas, stimulating well productivity and production of unconventional oil, NGL and
natural gas resources poses additional operating risks different from conventional oil, NGL and natural gas production operating risks, including:
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higher capital costs than similar depth conventional natural gas wells because of necessary alternative drilling or completion techniques,
water production, treatment and disposal costs, additional compression, or other factors;
relatively long pilot production test times to determine commerciality or optimal practices, as compared to conventional oil and natural gas
fields;
peak production rates, time to reach peak rate, and time that peak rate can be sustained, are subject to substantially greater uncertainty for
unconventional oil and natural gas wells than conventional oil and natural gas wells;
difficulties associated with producing water, including scale formation, corrosion or backpressure caused by inefficient pumping, restrictions
on surface facilities capacity, failure of water disposal wells to adequately handle required volumes of produced water and related dewatering;
difficulties associated with extreme weather conditions including potential freezing;
more wells per section in some instances to optimally and cost-effectively develop reserves;
reduced wellhead pressures needed for production, leading to larger flow lines or additional compression; and
complexity of development of multiple productive zones.
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Requirement for Significant Capital Investment
The E&P Companies' future success depends upon their ability to find, develop or acquire oil, NGL and natural gas reserves that are economically
recoverable. The E&P Companies' reserves and production therefrom will generally decline as reserves are depleted, except to the extent that the
E&P Companies conduct successful exploration or development activities or acquire additional properties containing reserves, or both. To increase
reserves and production, the E&P Companies may undertake development, exploration and other replacement activities or use third parties to
accomplish these activities. The E&P Companies have made and expect to make in the future substantial capital investments in their business and
operations for the development, production, exploration and acquisition of oil, NGL and natural gas reserves. Historically, the E&P Companies
have financed capital investments primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under their
bank and other credit facilities. The E&P Companies' cash flow from operations and access to capital are subject to a number of variables, including:
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their reserves;
the level of oil, NGL and natural gas they are able to produce from existing wells;
the prices at which oil, NGL and natural gas are sold; and
their ability to acquire, locate and produce new reserves.
The E&P Companies may not have sufficient resources to undertake exploration, development and production activities or the acquisition of oil,
NGL and natural gas reserves. The E&P Companies' exploratory projects or other replacement activities, if any, may not result in significant additional
reserves and the E&P Companies may not have success drilling productive wells at low finding and development costs. If the E&P Companies are
unable to find, develop or acquire additional oil, NGL and natural gas reserves, their cash flow and results of operations may be adversely effected.
As such, the E&P Companies may require additional financing in order to carry out their oil, NGL and natural gas acquisition, exploration and
development activities that cannot be satisfied from cash flow from operations. There is a risk that if the economy and banking industry experiences
unexpected and/or prolonged deterioration, the E&P Companies' access to additional financing may be affected. Because of global economic
volatility, the E&P Companies may from time to time have restricted access to capital and increased borrowing costs. Failure to obtain such additional
financing on a timely basis could cause the E&P Companies to forfeit their interest in certain properties, miss certain acquisition opportunities and
reduce or terminate their operations. If the E&P Companies' revenues from their reserves decrease as a result of lower oil, NGL and natural gas
prices, operating difficulties, declines in reserves or otherwise, it will affect the E&P Companies' ability to obtain the necessary capital to replace their
reserves or to maintain their production. To the extent that external sources of capital become limited, unavailable, or available only on onerous
terms, the E&P Companies' ability to make capital investments and maintain existing assets may be impaired, and their assets, liabilities, business,
financial condition and results of operations may be materially and adversely affected as a result. Additionally, there can be no assurance that additional
debt or equity financing will be available to meet these requirements on favourable terms or at all and any equity financing may result in a change of
control of the E&P Companies.
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 E&P Companies' properties. The
actual reserves contained in the E&P Companies' properties will vary from the estimates summarized in this AIF and elsewhere 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 judgments 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 E&P Companies' 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:
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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 E&P Companies' control. If these factors, assumptions and prices prove to be inaccurate, the E&P Companies'
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 NGL 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.
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Inability to Add or Develop Additional Reserves
The E&P Companies 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 E&P Companies' 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 E&P Companies 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 E&P Companies' 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 E&P Companies cannot assure that they will be successful in
acquiring additional reserves on terms that meet their investment objectives. Without these additions, the E&P Companies' reserves will deplete and,
as a consequence, either their production or the average life of their reserves will decline.
An Increase in Operating Costs or a Decline in Production Level
Higher operating costs for the E&P Companies' properties will directly decrease the amount of cash flow received by the E&P Companies. Electricity,
chemicals, supplies, energy services and labour costs are a few of the E&P Companies' operating costs that are susceptible to material fluctuation.
The level of production from the E&P Companies' existing properties may decline at rates greater than anticipated due to unforeseen circumstances,
many of which are beyond the Company's and the E&P Companies' control. Higher operating costs or a significant decline in production could result
in materially lower revenues and cash flows.
Reserves and Production May Decline Over Time
Producing oil, NGL and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics
and other factors. Exploration and development are the E&P Companies' main methods of replacing and expanding their asset base. The E&P
Companies' exploration and development activities in their properties and other properties the E&P Companies pursue in the future may not be
successful for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive reservoirs will be
discovered. In addition, the future cost and timing of drilling, completing and tying-in wells are often uncertain. The E&P Companies' exploration
and development operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
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lack of acceptable prospective acreage;
mechanical difficulties such as major natural gas plant and regional pipeline failures;
unexpected drilling conditions;
pressure or irregularities in formations;
equipment failures or accidents;
lack of storage;
weather conditions;
title problems;
compliance with governmental regulations or required regulatory approvals;
inadequate access to natural gas gathering and processing infrastructure and capacity;
unavailability or high cost of drilling rigs, equipment or labour;
approvals of third parties;
reductions in oil, NGL or natural gas prices; and
limitations in the market for oil, NGL or natural gas.
The E&P Companies may be unable to acquire and develop properties in their core areas. The E&P Companies may not be able to develop, find or
acquire additional reserves to replace their current and future production at acceptable costs, which would adversely affect their business, financial
condition and results of operations.
Declining General Economic, Business or Industry Conditions
Concerns over global economic conditions, fluctuations in interest rates and foreign exchange rates, stock market volatility, energy costs, geopolitical
issues, inflation, the availability and cost of credit, the European debt crisis and slowing economic growth in developing countries have contributed
to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, NGL
and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession.
In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could
adversely affect the economies of Canada, the United States and other countries. Concerns about global economic growth have had a significant
adverse impact on global financial markets and commodity prices. If the economic climate in Canada or abroad deteriorates further, worldwide
demand for petroleum products could diminish further, which could impact the price at which the E&P Companies can sell their oil, NGL and natural
gas, affect the ability of the E&P Companies' vendors, suppliers and customers to continue operations and ultimately adversely impact the E&P
Companies' results of operations, liquidity and financial condition.
General Energy Sector Risk
The business and operations of the E&P Companies, 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 E&P Companies' operations may also subject them to the risk of vandalism or terrorist
threats including eco-terrorism. The foregoing hazards could result in personal injury, loss of life, reduced production volumes or environmental and
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other damage to the E&P Companies' property and the property of others. The E&P Companies cannot fully protect against all of these risks, nor
are all of these risks insurable. Although the E&P Companies 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 E&P Companies 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.
Uncertainties Associated with Exploration and Development of Unproved Properties
The E&P Companies may acquire significant amounts of unproved property in order to further their development efforts. Development and
exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered.
The E&P Companies may acquire unproved properties and lease undeveloped acreage that the E&P Companies believe will enhance their growth
potential and increase their earnings over time. However, the E&P Companies can provide no assurance that all prospects will be economically viable
or that the E&P Companies will not abandon their investments. Additionally, the E&P Companies can provide no assurance that unproved property
acquired by the E&P Companies or undeveloped acreage leased by the E&P Companies will be profitably developed, that new wells drilled by the
E&P Companies in prospects that it pursues will be productive or that the E&P Companies will recover all or any portion of their investment in
such unproved property or wells.
Drilling for oil, NGL and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not
produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is
often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled
as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for
other reasons. In addition, wells that are profitable may not meet the E&P Companies' internal return targets, which are dependent upon the current
and expected future market prices for oil, NGL and natural gas, expected costs associated with producing oil, NGL and natural gas and the E&P
Companies' ability to add reserves at an acceptable cost.
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 E&P Companies' 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 Sector - Energy Sector Overview - The Oil and Gas Industry - 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 E&P Companies, and
such costs may be significant, which may negatively impact the trading price or value of the Company's common shares.
The E&P Companies 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
damage) is not available on economically reasonable terms. Accordingly, the E&P Companies' 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 E&P Companies did 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 E&P Companies 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 likely be funded out of cash flows.
Should the E&P Companies be unable to fully fund the cost of remedying an environmental claim, the E&P Companies 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; health and safety 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 Sector - Energy Sector Overview - The Oil and Gas Industry".
To the extent that the E&P Companies 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 E&P Companies
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, or increase the E&P Companies' costs, any of which will have a material adverse impact on the E&P Companies. Additionally, various
levels of Canadian and U.S. governments have implemented, or are considering, legislation to reduce emissions of greenhouse gases. See "Energy
Sector - Energy Sector Overview - The Oil and Gas Industry - Environmental Regulation" for a description of these initiatives. Because the E&P Companies'
operations emit various types of greenhouse gases, such new legislation or regulation could increase the costs related to operating and maintaining
the E&P Companies' facilities and could require them to install new emission controls on their facilities, acquire allowances for their greenhouse gas
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emissions, pay taxes related to their greenhouse gas emissions and administer and manage a greenhouse gas emissions program. The E&P Companies
are not able at this time to estimate such increased costs; however, they could be significant.
Oil, NGL and natural gas companies operating in Alberta are subject to significant regulation with respect to their employees' health and safety.
Companies are required to self-report accidents and infractions, but regular and random audits of operations are also part of the regulatory process.
Previous violations of the same requirement are taken into account when assessing penalties and subsequent behavior may be subjected to escalating
levels of oversight and loss of operating freedom. Non-compliance with regulations may in the future result in suspension or closure of the E&P
Companies' operations or the imposition of other penalties against the E&P Companies.
Changes in Interpretation and Enforcement of Provincial Laws and Regulations
The E&P Companies' business may be adversely impacted by changes to the interpretation and enforcement of laws related, but not limited, to land
tenure, industry activity level, environmental impact, access to the E&P Companies' properties, well classification, operating standards and facility
requirements. In addition, the E&P Companies' business may be adversely impacted by changes in the interpretation and enforcement of provincial
royalty regimes. In Alberta, most of the production of oil, NGL and natural gas is subject to Crown lessor royalties that must be paid to the provincial
government. In Alberta, the royalty reserved to the Crown in respect of oil, NGL and natural gas production is determined by a sliding scale based
on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price
is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed.
Risks Associated with Climate Change Legislation
The E&P Companies' exploration and production facilities and other operations and activities emit greenhouse gases and may require the E&P
Companies to comply with greenhouse gas emissions legislation in Alberta or legislation that may be enacted in other provinces or federally. Climate
change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing
of climate change measures that are ultimately put in place. As a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC")
and as a participant to the Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on
January 29, 2010 that it will seek a 17% reduction in greenhouse gas emissions from 2005 levels by 2020. These greenhouse gas emission reduction
targets are not binding. Although it is not the case today, some of the E&P Companies' significant facilities may ultimately be subject to future
regional, provincial and/or federal climate change regulations to manage greenhouse gas emissions. The direct or indirect costs of compliance with
these regulations may have a material adverse effect on the business, financial condition, results of operations and prospects of the E&P Companies.
Any such regulations could also increase the cost of consumption, and thereby reduce demand for the oil, NGL and natural gas the E&P Companies
produce. Given the evolving nature of the debate related to climate change and the control of greenhouse gas and resulting requirements, it is not
possible to predict the impact on the E&P Companies and their operations and financial condition.
In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes,
thunderstorms, tornado's and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility
in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their
historical averages. Extreme weather conditions can interfere with the E&P Companies' production and increase the E&P Companies' costs, and
damage resulting from extreme weather may not be insured. However, at this time, the E&P Companies are unable to determine the extent to which
climate change may lead to increased storm or weather hazards affecting their operations.
Lower Oil and Gas Prices Increase the Risk of Write-Downs
Under International Financial Reporting Standards, 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 the E&P Companies' developed oil and natural gas properties being less
than its 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 E&P Companies would be required to reverse all, or a portion
of, the impairment previously recorded.
Uncertainties in the Assessment of Reservoir and Infrastructure Characteristics of Oil and Natural Gas Properties
Acquiring oil and natural gas properties requires the E&P Companies to assess reservoir and infrastructure characteristics, including recoverable
reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain.
In connection with the assessments, the E&P Companies perform a review of the subject properties, but such a review will not reveal all existing or
potential problems nor will it permit the E&P Companies to become sufficiently familiar with the properties to assess fully their deficiencies. In the
course of their due diligence, the E&P Companies may not inspect every well or pipeline. The E&P Companies cannot necessarily observe structural
and environmental problems, such as pipe corrosion, when an inspection is made. Even if problems are identified, the E&P Companies may not be
able to obtain contractual indemnities from the seller for liabilities created prior to the E&P Companies' purchase of the property. The E&P Companies
may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance
with their expectations.
Uncertainties Associated with Seismic Data
Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying
subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those
structures. In addition, the use of 3D seismic and other advanced technologies requires greater predrilling investments than traditional drilling
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strategies, and the E&P Companies could incur losses as a result of such investments. As a result, the E&P Companies' drilling activities may not be
successful or economical.
Unforeseen Title Defects
The Company or the E&P Companies, 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
the E&P Companies' title to the purchased assets. If this type of defect were to occur, the E&P Companies' entitlement to the production and
reserves (and, if applicable, resources) from the purchased assets could be jeopardized. Furthermore, from time to time, the E&P Companies 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 E&P Companies. Furthermore, from time to time, the E&P Companies or their industry partners may owe one another a contractual
or trust related obligation, including offset obligations, which they may default in satisfying and which may adversely affect the validity of an oil and
gas lease in which the E&P Companies have an interest. The existence of title defects, unsatisfied contractual or trust related obligations, including
offset obligations, or the resolution of any disputes with industry partners arising from same, may have a material adverse effect on the E&P Companies
or their assets and operations and as a result adversely affect the value of the Company's common shares.
Reliance on Surface and Groundwater Licenses
The E&P Companies rely on surface and groundwater, which is obtained under government licenses, to provide the substantial quantities of water
required for certain of their operations. There can be no assurance that the licenses to withdraw water will not be rescinded or that additional
conditions will not be added to these licenses. Further, there can be no assurance that the E&P Companies will not have to pay a fee for the use of
water in the future or that any such fees will be reasonable. Finally, new projects or the expansion of existing projects may be dependent on securing
licenses for additional water withdrawal, and there can be no assurance that these licenses will be granted on terms favourable to the E&P Companies,
or at all, or that such additional water will in fact be available to divert under such licenses.
The Oil and Natural Gas Industry is Cyclical
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants),
supplies and qualified personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and the demand for,
and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, the E&P Companies
rely on independent third-party service providers to provide most of the services necessary to drill new wells. If the E&P Companies are unable to
secure a sufficient number of drilling rigs at reasonable cost, their financial condition and results of operations could suffer, and the E&P Companies
may not be able to drill all of their acreage before their leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other
proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict the
E&P Companies' exploration and development operations, which in turn could impair the E&P Companies' financial condition and results of
operations.
Fluctuations in Foreign Currency Exchange Rates
The price that the E&P Companies receive for a majority of their oil and natural gas is based on United States dollar denominated benchmarks, and
therefore the price that the E&P Companies with operations in Canada 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 E&P Companies' net
Canadian production revenue by decreasing the Canadian dollars the E&P Companies receive for a given sale in United States dollars while offering
limited relief to the E&P Companies' cost structures, to the extent their costs are incurred in Canadian dollars.
Counterparty Risk
The E&P Companies 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. Furthermore, low oil and natural gas prices increase the risk of bad debts related to the E&P Companies'
industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to the E&P Companies may
adversely affect the E&P Companies' results of operations, cash flows and financial position.
A Decline in the Ability to Market Oil and Natural Gas Production
The E&P Companies' 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. In general, the E&P Companies do not control these transportation facilities
and the E&P Companies' access to them may be limited or denied. These transportation facilities may also fail or may not perform as predicted. A
significant disruption in the availability of these transportation facilities or compression and other production facilities could adversely impact the
E&P Companies' ability to deliver to market or produce their oil, NGL and natural gas and thereby result in the E&P Companies' inability to realize
the full economic potential of their production. If, in the future, the E&P Companies are unable, for any sustained period, to implement acceptable
delivery or transportation arrangements or encounter compression or other production related difficulties, the E&P Companies will be required to
shut in or curtail production from the field. Any such shut in or curtailment, or an inability to obtain favourable terms for delivery of the oil, NGL
and natural gas produced from the field, would adversely affect the E&P Companies' financial condition and results of operations. 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 E&P Companies' ability to produce and market oil and natural gas.
Oil and natural gas producers in North America, and particularly Canada, currently receive significantly discounted prices for their production due
to constraints on the ability to transport and sell such production to international markets. Also, limited natural gas processing capacity may result
in producers not realizing the full price for liquids associated with their natural gas production. A failure to resolve such constraints may result in
shut-in production or continued reduced commodity prices received by oil and natural gas producers such as the E&P Companies.
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While the third party pipelines generally expand capacity to meet market needs, there can be differences in timing between the growth of production
and the growth of pipeline capacity, and unfavourable economic conditions or financing terms may defer or prevent the completion of certain pipeline
projects or gathering systems that are planned for such areas. There are also occasionally operational reasons, including as a result of maintenance
activities, for curtailing transportation capacity. Accordingly, there can be periods where transportation capacity is insufficient to accommodate all
of the production from a given region, causing added expense and/or volume curtailments for all shippers. In such event, the E&P Companies may
have to defer development of or shut in its wells awaiting a pipeline connection or capacity and/or sell its production at lower prices than it would
otherwise realize or than the E&P Companies currently project, which would adversely affect the E&P Companies' results of and cash flow from
operations.
Due to the current shortage of pipeline capacity, Canadian oil and gas producers have turned to shipping crude oil by rail as a short-term alternative.
However, as the amount of crude oil shipped by rail has increased, regulatory and safety developments have occurred which will have unclear
consequences for the cost and availability of crude oil rail shipments moving forward. Following major accidents in Lac-Megantic, Québec and North
Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board issued recommendations to Transport Canada, the
responsible Canadian federal ministry, to improve the safe transportation of crude oil by rail. In response, the federal Transport Minister announced
an order removing approximately 5,000 DOT-111 tanker rail cars from Canadian railways within a short period of time, with another 65,000 DOT-111
tanker rail cars to be removed or retrofitted within three years, and plans to establish speed limits of 50 miles-per-hour or less for trains carrying 20
cars or more of crude oil or ethanol in areas that are built up or near drinking water. The increased regulation of rail transportation may reduce the
ability of railway lines to alleviate pipeline capacity issues and add additional costs to the transportation of crude oil by rail.
The E&P Companies' Activities are Affected by Seasonality
The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make
the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs
and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible
other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. There can be no assurance
that these seasonal factors will not adversely affect the timing and scope of the E&P Companies' exploration and development activities, which could
in turn have a material adverse impact on the E&P Companies' business, operations and prospects.
Exposure to Project Risks
The E&P Companies manage a variety of small and large projects in the conduct of their business. Project delays may delay expected revenues from
operations. Significant project cost over-runs could make a project uneconomic.
The E&P Companies' ability to execute projects and market oil, NGL and natural gas will depend upon numerous factors beyond their control,
including:
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the availability of processing capacity;
the availability and proximity of pipeline capacity;
the availability of storage capacity;
the supply of and demand for oil, NGL and natural gas;
the availability of alternative fuel sources;
the effects of inclement weather;
the availability of drilling and related equipment;
unexpected cost increases;
accidental events;
currency fluctuations;
changes in regulations;
the availability and productivity of skilled labour; and
the regulation of the oil and natural gas industry by various levels of government and governmental agencies.
Because of these factors, the E&P Companies may be unable to execute projects on time, on budget or at all, and may not be able to profitably market
the oil, NGL and natural gas that it produces.
Inability to Compete Successfully with other Organizations in the Oil and Natural Gas Industry
The oil and natural gas industry is highly competitive. The E&P Companies 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 E&P Companies.
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.
Challenges by First Nations
Certain First Nations people may have Aboriginal rights in relation to the E&P Companies' permit and lease lands in Alberta and other lands that
are potentially affected by the E&P Companies' activities. First Nations' rights are also affected by the federal and provincial regulatory framework
and practices governing Aboriginal rights. The Governments of Canada and Alberta have a duty to consult with those First Nations people in relation
to actions and decisions which may impact those rights and claims and, in certain cases, have a duty to accommodate their concerns. These duties
have the potential to adversely affect the E&P Companies' ability to obtain permits, leases, licenses and other approvals, or to meet the terms and
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conditions of those approvals. Opposition by First Nations people may also negatively impact the E&P Companies in terms of public perception,
diversion of management time and resources, legal and other advisory expenses, potential blockades or other interference by third parties in the E&P
Companies' operations, or court-ordered relief impacting the E&P Companies' operations. Any challenges by First Nations people could adversely
impact the E&P Companies' progress and ability to explore and develop their properties.
Risks Associated with Provincial Liability Management Programs
The Alberta government has developed liability management programs designed to prevent taxpayers from incurring costs associated with suspension,
abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder becomes defunct. The
program generally involves an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed their
deemed assets, a security deposit is required. Although the E&P Companies do not have to post security under the existing programs, changes to
the ratio of the E&P Companies' deemed assets to deemed liabilities or changes to the requirements of liability management programs may result
in the requirement for security to be posted in the future.
Risks Associated with Wildlife Protection Restrictions
Oil and natural gas operations in the E&P Companies' operating areas can be adversely affected by seasonal or permanent restrictions on drilling
activities designed to protect various wildlife. Seasonal restrictions may limit the E&P Companies' ability to operate in protected areas and can intensify
competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is
allowed. These constraints and the resulting shortages or high costs could delay the E&P Companies' operations and materially increase the E&P
Companies' operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or
require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where the E&P Companies
operate as threatened or endangered could cause the E&P Companies to incur increased costs arising from species protection measures or could
result in limitations on the E&P Companies' exploration and production activities that could have an adverse impact on the E&P Companies' ability
to develop and produce their reserves.
Risks Associated with Production of Hydrogen Sulfide
A significant portion of the natural gas produced in Alberta originates as Hydrogen Sulfide ("Sour Gas"). If a well encounters a high concentration
of Sour Gas it may have to be shut in due to the lack of existing Sour Gas handling infrastructure. Sour Gas leaks or other exposure to Sour Gas
produced from the E&P Companies' properties may result in damage to equipment, liability to third parties, adverse effects to humans, animals or
the environment, or the shutdown of operations. Special equipment and operating procedures are deployed by the industry for the production of
Sour Gas.
Expiration of Undeveloped Leasehold Acreage
The E&P Companies hold natural gas licenses and leases in Alberta under Crown license or lease. Under the terms of the Crown licenses and leases
which govern these properties, unless the E&P Companies establish commercial production on the properties subject to these leases during their
term, these licenses and leases will expire. There can be no assurance that any of the obligations required to maintain each lease will be met.
Continuations of expiring non-producing licenses and leases are reviewed by the Alberta Department of Energy ("DOE"), on a case by case basis.
A continuation of an operated license or lease is generally applied for if technical data demonstrates the possibility of a productive license or lease
in the near-term. If the E&P Companies' licenses and leases expire and the E&P Companies cannot obtain a lease continuation from the DOE, the
E&P Companies would lose their right to develop the related properties unless it subsequently nominates and successful repurchases the impacted
licenses and leases from the Alberta Government.
Inability to Dispose of Non-Strategic Assets on Attractive Terms
The E&P Companies' ability to dispose of non-strategic assets, such as acreage that they do not intend to place on their drilling schedule prior to
lease expirations, could be affected by various factors, including the availability of purchasers willing to purchase the non-strategic assets at prices
acceptable to the E&P Companies. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of such
retained liability or indemnification obligations may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is
typical in divestiture transactions, third parties may be unwilling to release the E&P Companies from guarantees or other credit support provided
prior to the sale of the divested assets. As a result, after a sale, the E&P Companies may remain secondarily liable for the obligations guaranteed or
supported to the extent that the buyer of the assets fails to perform these obligations.
Risks Associated with New Drilling Techniques
The E&P Companies' operations involve utilizing the latest drilling and completion techniques as developed by the E&P Companies and their service
providers. Risks that the E&P Companies face while drilling include, but are not limited to, landing their well bore in the desired drilling zone, staying
in the desired drilling zone while drilling horizontally through the formation, running their casing the entire length of the well bore and being able
to run tools and other equipment consistently through the horizontal well bore. Risks that the E&P Companies face while completing their wells
include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well
bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results
of the E&P Companies' drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and
have a longer history of established production.
Newer or emerging formations and areas have limited or no production history and consequently the E&P Companies are less able to predict future
drilling results in these areas. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are
drilled and production profiles are established over a sufficiently long time period. If the E&P Companies' drilling results are poorer than anticipated
or the E&P Companies are unable to execute their drilling program because of capital constraints, lease expirations, access to gathering systems, and/
or natural gas and oil prices decline, the return on the E&P Companies' investments in these areas may not be as attractive as they anticipate. Further,
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as a result of any of these developments the E&P Companies could incur material write-downs of their oil and natural gas properties and the value
of the E&P Companies' undeveloped acreage could decline in the future.
Risks Associated with Negative Public Perception of the Oil Industry
Oil and natural gas development and transportation, hydraulic fracturing and fossil fuels have figured prominently in recent political, media and activist
commentary on the subject of climate change, greenhouse gas emissions, water usage and environmental damage. The E&P Companies' corporate
reputation may be negatively affected by the negative public perception and public protests against oil and natural gas development and transportation
and hydraulic fracturing.
Risks Relating to the Land Contract Drilling Industry
The Company encourages you to consult ICD's public disclosure record for information on risk factors affecting their business, including the factors
described in the section entitled "Risk Factors" in the prospectus filed on August 11, 2014 under Rule 424(b)(4) under the United States Securities Act of
1933 in connection with ICD's IPO (available under ICD's profile on EDGAR at www.sec.gov), which section (the "2014 ICD Risk Factors") is
incorporated by reference into this AIF. The 2014 ICD Risk Factors shall be deemed to no longer be incorporated by reference into this AIF upon
the filing, under ICD's profile on EDGAR at www.sec.gov, of ICD's Form 10-K for the year ended December 31, 2014 (the "2014 ICD 10-K"), at
which time the risk factors in the 2014 ICD 10-K will be deemed to be incorporated by reference into this AIF.
Risks Relating to the Mining Sector
The Company encourages you to consult Corsa's public disclosure record for information on risk factors affecting their business, including the factors
described in the section entitled "Risk Factors" in Corsa's annual information form for the fiscal year ended December 31, 2013 and the nine-month
period ended September 30, 2014 (available under Corsa's profile on SEDAR at www.sedar.com), which section is incorporated by reference into this
AIF.
Production
A mining company's revenues depend on its level of mining production and the sales price for the minerals it has mined. Production targets are
based on operating mines and those that are in the permitting stage, under development or under option. As the estimation of resources and reserves
is speculative in nature, there can be no certainty that the resources in the current properties of mining companies will be upgraded to reserves. As
a result, mining companies may not achieve their production projections. Mining companies may then need to lease and/or option additional properties
which may take time and may be subject to the same uncertainties inherent in mining. In addition, production levels are no guarantee that mining
companies will be able to obtain sales contracts or orders for the minerals that they produce and as a result sales may be below their production
capabilities and mining companies may reduce actual production to reflect actual customer demand and sales orders received. Also, there is no
guarantee as to the price for mineral sales.
Resource Exploration, Development and Production Risks
Mining companies are engaged in the business of exploring, acquiring and developing resource properties. Resource exploration is speculative in
nature and there can be no assurance that any minerals discovered or acquired will result in an increase in a mining company's resource base. Such
exploration and development as well as acquisitions involves a high degree of financial and other risks over a significant period of time, which even
a combination of careful evaluation, experience and knowledge may not eliminate. Substantial expenses will be required to expand a mining company's
resource base and to design and construct mining and processing facilities. Whether a resource deposit will be commercially viable depends on a
number of factors, including the particular attributes of the deposit (i.e. mineral quality, size, access and proximity to infrastructure), financing costs,
the cyclical nature of commodity prices and government regulations (including those relating to environmental protection).
A future increase in a mining company's reserves will depend on its ability to select and acquire suitable properties. No assurance can be given that
any mining company will be able to locate or acquire control over satisfactory properties for acquisition that will be economically viable in the current
market.
Resources and Reserves
To achieve its projected level of production, a significant portion of a mining company's resources may need to be upgraded to reserves. Such
upgrade in classification may require additional data and establishing the economic feasibility of mineralization currently classified as resources.
There can be no assurance that a mining company will be able to successfully upgrade its resources to reserves.
Estimating reserves and resources involves a determination of economic recovery of minerals that are in the ground, which in turn requires that
assumptions be made regarding its future price and the cost of recovery. There are numerous uncertainties inherent in estimating the quantities and
qualities of, and costs to mine, recoverable reserves, including many factors beyond a mining company's control. Such factors include: improvements
to mining technology; changes to government regulation; geologic and mining conditions, which may not be fully identified by available exploration
data or may differ from a mining company's experience in current operations; historical production from the area compared with production from
other producing areas; future resource prices; operating costs; capital expenditures; taxes; royalties and development and reclamation costs; preparation
plant recovery levels and mine recovery levels; all of which may vary considerably from actual results.
A mining company's actual production experience may require the revision of production estimates because actual mineral tonnage recovered from
an identified reserve or property may vary materially from estimates. Resource reserves disclosed by a mining company should not be interpreted as
assurance of mine life or of the profitability of current or future operations. In addition, revenues and expenditures with respect to a mining company's
reserves may vary materially from estimates. The estimates of reserves may not accurately reflect a mining company's actual reserves and may need
to be restated in the future. Market fluctuations in resource prices, as well as increased production costs or reduced recovery rates, may render certain
mineral reserves and resources uneconomic and may ultimately result in a restatement of reserves and/or resources. Any inaccuracy in a mining
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company's estimates could result in lower than expected revenues or higher than expected costs. A mining company's recoverable reserves will decline
as it produces resources and a mining company may not be able to mine all of its reserves. Its future success may depend on conducting successful
exploration and development activities or acquiring properties containing economically recoverable reserves. There can be no assurance that a mining
company will succeed in developing additional mines in the future.
Permitting Matters
Many mining companies must obtain numerous permits, licenses and approvals that strictly regulate access, environmental and health and safety and
other matters in connection with resource mining. Permitting rules are complex and may change over time, which may make securing additional
permits or modification to existing permits and compliance difficult.
Regulatory agencies have considerable discretion in whether or not to issue permits or grant consents and they may choose not to issue permits or
grant consents to a mining company or renew existing permits, licenses or consents as they come due. There can be no assurance that a mining
company will be able to acquire, maintain, amend or renew all necessary licences, permits, mining rights or surface rights for its anticipated exploration
and development. If a mining company is to be granted a permit, it may be some time before those new permits are issued. Accordingly, new permits,
licenses and approvals required by a mining company to operate the mines may not be issued at all, or if issued, may not be issued in a timely fashion,
or may contain requirements which restrict its ability to conduct its mining operations or subject it to additional constraints or costs. Past or ongoing
violations of government mining laws could provide a basis to revoke existing permits or to deny the issuance of additional permits. In addition,
evolving reclamation or environmental concerns may threaten a mining company's ability to renew existing permits or obtain new permits in
connection with future development, expansions and operations.
Government Regulation
Government authorities regulate the mining industry to a significant degree, in connection with, among other things, exploration and development
activities, employee health and safety, labour standards, air quality standards, toxic substances, water pollution, groundwater quality and availability,
plant and wildlife protection, the reclamation and restoration of mining properties and the discharge of materials into the environment. Mining
companies are subject to extensive laws and regulations controlling not only the mining of and exploration of mineral properties, but also the possible
effects of such activities upon the environment. For example, government regulatory agencies may order certain mines to be closed temporarily or
permanently. Future legislation and regulations or amendments could cause additional expense, capital expenditures, reclamation obligations,
revocation of licenses, restrictions and delays in the development of a mining company's properties, the extent of which cannot be predicted.
Government regulations including regulations relating to the environment, prices, taxes, royalties, land tenure, land use and importing and exporting
of minerals also impact on the marketability of the minerals owned by mining companies.
These laws and regulations, particularly new legislative or administrative proposals (or judicial interpretations of existing laws and regulations) related
to the protection of the environment, could result in substantially increased capital, operating and compliance costs and could have a material adverse
effect on a mining company's operations and/or its customers' ability to use a mining company's products.
Failure to comply with applicable laws, regulations and permitting requirements may result in enforcement actions against mining companies, including
orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital
expenditures, installation of additional equipment, or remedial actions. Parties engaged in mining operations may be required to compensate those
suffering loss or damage by reason of the mining activities and may have civil or criminal fines or penalties imposed for violations of applicable laws
or regulations.
Operating Risks
Mining operations are and will continue to be subject to operating risks that could result in decreased mineral production. Such operating risks may
increase a mining company's cost of mining and delay or halt production at particular mines, either permanently or for varying lengths of time.
These conditions and events include but are not limited to:
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the lack of availability of qualified labour;
inability to acquire, maintain, amend or renew necessary permits or mining or surface rights in a timely manner, if at all;
failure of resource and reserve estimates to prove correct;
interruptions due to transportation delays or unavailability;
changes in governmental regulation of the mineral industry, including the imposition of additional taxes, fees or actions to suspend or
revoke its permits or changes in the manner of enforcement of existing regulations;
limited availability of mining and processing equipment and parts from suppliers;
the lack of availability of the necessary equipment of the type and size required to meet production expectations;
mining and processing equipment failures and unexpected maintenance problems;
unfavourable changes or variations in geologic conditions, such as the quality of mineral deposits, irregularity in mineral seams and the
amount of rock embedded in or overlying the mineral deposit and other conditions that can make underground or open pit mining difficult
or impossible;
severe and adverse weather and natural disasters, such as heavy rains and flooding;
increased or unexpected reclamation costs;
unfavourable fluctuations in the cost or availability of necessary commodities or commodities-based products such as diesel fuel, lubricants,
explosives, electric cables and steel;
unexpected mine safety accidents, including fires and explosions from methane; and
failure of the mineral mined to meet expected quality specifications.
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These conditions and events may increase a mining company's cost of mining and delay or halt production at particular mines either permanently
or for varying lengths of time. A mining company's planned exploration and development projects and acquisition activities may not result in the
acquisition of significant additional mineral deposits and a mining company may not have continuing success developing its current or additional
mines.
Mining Operations
Mining operations generally involve a high degree of risk. A mining company's operations will be subject to all of the hazards and risks normally
encountered in resource exploration, development and exploitation that are beyond the control of a mining company. Such risks include pit wall
slides, pit flooding, unusual and unexpected geological formations, seismic activity, rock bursts, ground failure and other conditions involved in the
drilling or cutting and removal of material, environmental hazards, industrial accidents, periodic interruptions due to adverse weather conditions,
labour disputes, political unrest, threats of war, terrorist threats and theft of production. The occurrence of any of the foregoing could result in
damage to, or destruction of, resource properties or interests, production facilities, personal injury, damage to life or property, environmental damage,
delays or interruption of operations, increases in costs, monetary losses, legal liability and adverse government action.
The climatic conditions of a mining company's activities will have an impact on operations and, in particular, severe weather such as heavy precipitation
and flooding could disrupt the delivery of supplies, equipment and fuel. Exploration and mining activity levels could fluctuate. Unscheduled
interruptions in a mining company's operations due to mechanical or other failures or industrial relations related issues or problems or issues with
the supply of goods or services could have a serious impact on the performance of those operations. Other operating risks include unfavourable
changes or variations in geological conditions such as the thickness of the mineral deposits and the amount of rock embedded in or overlying the
mineral deposit and other conditions that can make underground mining difficult or impossible; mining and processing equipment failures and
unexpected maintenance problems; increased water entering mining areas and increased or accidental mine water discharges; unfavourable fluctuations
in commodities-based products such as diesel fuel, reagents for processing, lubricants, electric cables, rubber, explosives, steel, copper, and other raw
materials; and unexpected mine safety accidents, including fires and explosions from methane. There can be no assurance that a mining company
will be able to manage effectively the expansion of its operations or that its current personnel, systems, procedures and controls will be adequate to
support operations.
Mineral Transportation and Costs
Mineral producers depend upon rail, barge, trucking, overland conveyor and other systems to deliver minerals to customers and transportation costs
are a significant component of the total cost of supplying minerals. While mineral customers typically arrange and pay for transportation of minerals
from the mine to the point of use, disruption of these transportation services because of weather-related problems, insurgency, strikes, lock-outs,
transportation delays, excessive demand for their services or other events could temporarily impair a mining company's ability to supply minerals to
customers and thus could adversely affect a mining company's revenue and results of operations.
Disruption in capacity of, or increased costs of, transportation services could make minerals less desirable, and could make a mining company's
minerals less competitive than other sources of that mineral. In addition, increases in the cost of fuel, or changes in other costs relative to transportation
costs for minerals produced by competitors, could adversely affect a mining company's operations. To the extent such increases are sustained, a
mining company could experience losses and may decide to discontinue certain operations forcing a mining company to incur closure or care and
maintenance costs, as the case may be.
Dependence on Third Party Suppliers and Loss of Customer Base
A mining company may enter into mineral supply agreements which may require the delivery of minerals on a regular basis to its customers. If a
mining company's own mining production does not reach capacity, that mining company may have to enter into mineral supply agreements with
third party suppliers in order to meet its customers' demands. There can be no assurance that the third parties will, from time to time, be able to
supply the requisite quantities of minerals on the schedule negotiated with a mining company. Such third party suppliers may be subject to the same
risks relating to engineering, weather, labour, materials and equipment as a mining company.
Changes in purchasing patterns in the mineral industry may make it difficult for a mining company to enter into long term supply agreements with
new customers. The execution of a satisfactory mineral supply agreement may be the basis on which a mining company will undertake the development
of mineral reserves required to be supplied under the agreement. When a mining company's current agreements with customers expire or are
otherwise renegotiated, a mining company's customers may decide to purchase fewer amounts of minerals than in the past or on different terms,
including pricing terms less favourable to a mining company, or may choose to purchase from other suppliers. Mineral contracts may also contain
force majeure provisions which may allow for the temporary suspension of performance by a mining company or its customers during the duration
of specified events beyond the control of the affected party.
Title to Assets
A mining company may lease or option mineral rights in order to conduct a number of its mining operations. If defects in title or boundaries are
found to exist after a mining company commences mining, its right to mine may be limited or prohibited. No assurance can be given that there are
no title defects affecting a mining company's properties or those which it proposes to acquire or those upon which it has operations. The mineral
or operations properties may be subject to prior unregistered liens, agreements or transfers or other undetected title defects. There can be no assurance
that title to a mining company's mineral properties or those on which it has operations will not be challenged or impugned or defeated by a holder
of superior title or registered liens or adverse claims. Third parties may have valid claims underlying portions of a mining company's interests and
the permits or tenures may be subject to prior unregistered agreements or transfers and title may be affected by undetected defects. If a title defect
exists, it is possible that a mining company may lose all or part of its interest in the properties to which such defects relate. If there are title defects
with respect to any properties, a mining company might be required to compensate other persons or perhaps reduce its interest in the property. Also,
in any such case, the investigation and resolution of title issues may divert a mining company's management's time from on-going exploration and
development programs.
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Joint ventures and Partnerships
Many mining companies participate in joint ventures with third parties. Some of these joint ventures are unincorporated, some are incorporated and
some are partnerships or limited partnerships. There are risks associated with joint ventures, including:
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disagreement with a joint venture partner about how to develop, operate or finance a project;
a joint venture partner not complying with a joint venture agreement;
possible litigation between joint venture partners about joint venture matters; and
the inability to exert control over decisions related to a joint venture without a controlling interest.
These risks could result in legal liability, affect a mining company's ability to develop or operate a project under a joint venture, or have a material
and adverse effect on its earnings, cash flows, financial condition or results of operations.
Surety Bonds and Letters of Credit
The law and regulations in certain jurisdictions may require mining companies to obtain surety bonds or letters of credit to secure payment of certain
long-term obligations such as mine closure or reclamation costs, workers' compensation costs, leases and other obligations. These bonds or letters
of credit are typically renewable annually. Surety bond or letter of credit issuers and holders may not continue to renew or may demand additional
collateral or other less favourable terms upon those renewals. The ability of issuers and holders to demand additional collateral or other less favourable
terms has increased as the number of companies willing to issue these bonds or letters of credit has decreased over time. Failure to obtain or renew
surety bonds or letters of credit on acceptable terms could affect a mining company's ability to secure reclamation and mineral lease obligations and
could affect a mining company's ability to mine or lease mineral properties. That failure could result from a variety of factors, including, without
limitation: (i) lack of availability, higher expense or unfavourable market terms of new bonds or letters of credit; (ii) restrictions on availability of
collateral for current and future third-party surety bond and letter of credit issuers under the terms of a mining company's debt instruments; and
(iii) the exercise by third-party issuers of their right to refuse to renew the surety bond or letter of credit.
Additional Funding Requirements
Capital expenditures for the exploration, development, production, and acquisition of mineral reserves in the future may depend in part on funds
not entirely raised by internally generated cash flow. As a result, a mining company may need external equity or debt financing and there is no
assurance that it will be able to secure either kind of external financing at an economically viable cost and under reasonable conditions, if at all. No
assurance can be given that a mining company will be able to raise the additional funding that may be required for such activities on terms acceptable
to that mining company or at all, should such funding not be fully generated from operations.
Additional equity financing could be dilutive to shareholders and could substantially decrease the trading price of a mining company's securities. A
mining company may issue common shares or other equity securities in the future for a number of reasons. Additional debt financing, if secured,
could involve restrictions being placed on financing and operating activities which could reduce the scope of a mining company's operations or
anticipated expansion, or involve forfeiting its interest in some or all of its properties and licenses, incurring financial penalties, or reducing or
terminating its operations.
Availability of Equipment and Access Restrictions
Natural resource exploration, development and exploitation activities are dependent on the availability of particular types of drilling, cutting, conveying
and other excavating equipment and related supplies and equipment in the particular areas where such activities will be conducted as well as their
parts in the case that maintenance is needed on such equipment. Demand for or restrictions on access to such limited equipment and supplies may
affect the availability of such equipment and may delay exploration, development and exploitation activities. Future operations could be adversely
affected if a mining company encounters difficulty obtaining equipment, tires and other supplies on a timely basis, or such equipment and supplies
are available only at significantly increased prices.
Labour
If either the rail, truck or barge carrier or port facilities upon which a mining company is dependent to deliver minerals to its customers are or
become unionized, there is potential for strikes, lockouts or other work stoppages or slow-downs involving the unionized employees of its key service
suppliers which could have a material adverse effect on a mining company. There may be competition for qualified personnel in the various jurisdictions
in which mining and operations take place and there can be no assurance that a mining company will be able to continue to attract and retain all
personnel necessary for the development and operations of its business. Mining is a labour-intensive industry. From time to time, a mining company
may encounter a shortage of experienced mine workers. In addition, the employees of a mining company may be unionized or choose to unionize,
which may disrupt operations on account of contract negotiations, grievances, arbitrations, strikes, lockouts or other work stoppages or actions. As
a result, a mining company may be forced to substantially increase labour costs to remain competitive in terms of attracting and retaining skilled
labourers. Furthermore, it is possible that a decreased supply of skilled labour may cause a delay in a mining company's operations and negatively
affect its ability to expand production.
Equipment Breakdown
Breakdowns of equipment, difficulties or delays in obtaining replacement shovels and other equipment, natural disasters, industrial accidents or other
causes could temporarily disrupt a mining company's operations, which in turn may also materially and adversely affect its business, prospects,
financial condition and results of operations.
Mineral Price and Demand Volatility
Mineral demand and price are determined by numerous factors beyond the control of a mining company including the domestic and international
demand for products; consumption by industries; the availability of competitive mineral supplies; the supply and demand for domestic and foreign
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minerals; seasonal changes in the demand for certain minerals; interruptions due to transportation delays; proximity to, and capacity and cost of,
transportation facilities; air emission standards for certain production facilities; inflation; political and economic conditions; global or regional political
events and trends; international events and trends; international exchange rates; the cost implications to a mining company in response to regulatory
changes, administrative and judicial decisions; production costs in major mineral producing regions; the price and availability of alternative fuels,
including the effects of technology developments; the effect of worldwide energy conservation efforts; future limitations on utilities' ability to use
certain minerals as energy sources due to the regulation and/or taxation of greenhouse gases under climate change initiatives; and various other
market forces.
An increase in demand for certain minerals could attract new investors to that industry, which could result in the development of new mines and
increased production capacity throughout the industry. An oversupply in world markets could occur. The general downturn in the economies of a
mining company's significant markets is a significant risk. A significant reduction in the demand for certain products could reduce the demand for
certain minerals. Similarly, if less expensive ingredients could be used in substitution for certain minerals in various production processes, the demand
for that mineral would materially decrease. The combined effects of any or all of these factors on mineral price or volume cannot be predicted.
Competition
The resource exploration and mining business is competitive in all of its phases. Competitive factors in the distribution and marketing of minerals
include price and methods and reliability of delivery. A mining company will compete with numerous other companies and individuals, including
competitors with greater financial, technical and other resources, in the search for and the acquisition of attractive resource properties. The principal
factors that determine the price for which a mining company's minerals can be sold are demand, competition, mineral quality, efficiency in extracting
and transporting minerals, and proximity to customers. Increases in transportation costs could make a mining company's minerals less competitive
or could make some of a mining company's operations less competitive than other sources of minerals. An oversupply of any particular mineral
will also likely adversely affect the price of that mineral on the market. There can be no assurance that a mining company will be able to compete
successfully with other mineral producers and suppliers and its failure to compete effectively could adversely affect its operations and performance.
Foreign Currency Risk
Certain mining companies report their financial results in a foreign currency; however, they may incur certain costs and expenses in Canadian dollars
or a different currency. As a result a mining company's operating results and cash flows could be negatively affected by currency exchange rates
between the Canadian dollar and another currency. In addition, risk may arise with respect to foreign currency as a result of the development and
operation of assets in foreign jurisdictions. Mining companies may elect not to actively manage their foreign exchange exposure.
In addition, a mining company may compete in international markets against minerals produced in other countries. Many minerals are generally sold
internationally in U.S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency
exchange rates, providing an advantage to mineral producers in other countries. Currency fluctuations among countries purchasing and selling minerals
could adversely affect the competitiveness of a mining company's minerals in international markets.
Operating in Foreign Jurisdictions
A mining company may operate in a number of foreign countries where there are added risks and uncertainties due to the different economic, cultural
and political environments. Some of these risks include nationalization and expropriation, social unrest and political instability, uncertainties in
perfecting mineral titles, trade barriers and exchange controls and material changes in taxation. Further, developing country status or an unfavorable
political climate may make it difficult for a mining company to obtain financing for projects in some countries.
Environmental Risks, Hazards and Liabilities
A mining company's operations may inadvertently substantially impact the environment or cause exposure to hazardous materials, either of which
could result in material liabilities to that mining company. A mining company may be subject to claims under domestic or foreign legislation, and/
or common law doctrines, for toxic torts, natural resource damages, and other damages as well as the investigation and clean-up of soil, surface water
and groundwater. Such claims may arise, for example, out of current, former or future activities at sites that a mining company owns or operates, as
well as at sites that a mining company or its predecessor entities owned or operated in the past, or at contaminated sites that have always been owned
or operated by third parties. Mining operations can also impact flows and water quality in surface water bodies and remedial measures may be required,
such as lining of stream beds, to prevent or minimize such impacts. Many of a company's mining operations may take place in the vicinity of streams,
and similar impacts could be asserted or identified at other streams in the future. A mining company's liability for such claims may be joint and
several, so that it may be held responsible for more than its share of the remediation costs or other damages, or even for the entire share.
A mining company may have reclamation and mine closure obligations. It is difficult to determine the exact amounts which may be required to
complete all land reclamation activities in connection with their properties. Estimates of total reclamation and mine-closure liabilities are based upon
permit requirements and a mining company's experience. The amounts recorded are dependent upon a number of variables, including the estimated
future retirement costs, estimated proven reserves, assumptions involving profit margins and inflation rates. If these accruals are insufficient or
liability in a particular year becomes greater than may be anticipated, a mining company's operating results could be adversely affected.
Environmental Regulation
All phases of the natural resources business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety
of international conventions and Canadian and other foreign laws and regulations. Environmental legislation provides for, among other things,
restrictions and prohibitions on spills, releases or emission of various substances produced in association with operations. The legislation also requires
that facility sites and mines be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance
with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, and in some cases,
enforcement actions including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed or permits revoked and
may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions. A mining company's total
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compliance with the full spectrum of environmental regulation may not always be possible, and significant penalties may be incurred as a result of
violations of environmental laws.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. The environmental issues affecting a mining company's operations include permitting and
reclamation requirements, air pollution laws and regulations, regulations relating to climate change, water pollution laws and regulations, hazardous
waste regulation, mine safety regulations and restrictions against greenhouse gas emissions. The discharge of pollutants into the air, soil or water
may give rise to liabilities to governments and third parties and may require mining companies to incur costs to remedy such discharge. No assurance
can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development
or exploration activities or otherwise adversely affect a mining company's financial condition, results of operations or prospects. A mining company
may also be subject under such regulations to clean-up costs and liability for toxic or hazardous substances that may exist on or under any of its
properties or that may be produced as a result of its operations.
Land Use Regulation and Conflicting Land Uses
Land use regulation may negatively impact the ability to begin or carry out mining operations in particular locations. Zoning laws control land use
and often prohibit mining entirely. New land use restrictions may be enacted in areas of current or planned mining operations by new legislation or
regulation. In some jurisdictions, existing surface mining statutes may also allow citizens to file petitions deeming certain land unsuitable for surface
mining for a variety of reasons.
A mining company's properties may be affected by other conflicting developments that may impact mineral development by increasing the cost of
mineral recovery and decreasing the amount of minerals recoverable. As determinations that lands are unsuitable are awarded more frequently, the
amount of land available for mining declines and the risk that mining in planned areas will be prohibited increases. There is a risk that certain lands
will not be open for mining, decreasing the number of operations that mining companies can maintain or acquire in the future. Even in areas where
mining may not be prohibited outright, the presence of other land uses restricts the ability of mining companies to operate efficiently. Residential
structures, other buildings, gas wells, pipelines, roads, electric transmission lines, and numerous land uses other than mining are commonly located
in areas where mining companies operate. These land uses may inhibit a mining company's operations, and negative impacts on these land uses that
may result from a mining company's operations could create liability exposure. Additionally, the need to accommodate other land uses may result in
a less efficient use of the mining property.
Aboriginal Title Claims
Mining companies and governments in many jurisdictions must consult with aboriginal peoples with respect to grants of mineral rights and the
issuance or amendment of project authorizations. Consultation and other rights of aboriginal people may require accommodations, including
undertakings regarding financial compensation, employment and other matters in impact and benefit agreements. This may affect a mining company's
ability to acquire within a reasonable time frame effective mineral titles in these jurisdictions, including in some parts of Canada in which aboriginal
title is claimed, and may affect the timetable and costs of development of mineral properties in these jurisdictions. The risk of unforeseen aboriginal
title claims also could affect existing operations as well as development projects and future acquisitions. These legal requirements may increase a
mining company's operating costs and affect its ability to expand or transfer existing operations or to develop new projects.
Mine Safety Regulation
Employee safety and health regulation in the mining industry is often comprehensive and pervasive. The cost of complying with numerous safety
and health laws applicable to the mining industry in many jurisdictions is substantial. In many cases, negative publicity surrounding accidents in the
mining industry has resulted in expensive new safety requirements and substantially increased penalties for failure to comply with these regulations.
Failure to comply with such requirements may result in fines and/or penalties being assessed against mining companies. Given the complexity of
the mine safety and health regulations, there is a risk that a mining company's business operations will be affected by these regulations.
Nationalization
In certain jurisdictions, certain industries such as mineral production are regarded as nationally or strategically important, but there is no assurance
they will not be expropriated or nationalized. Government policy can change to discourage foreign investment and renationalize mineral production,
or the government can implement new limitations, restrictions or requirements. There is no assurance that a mining company's assets in these
jurisdictions will not be nationalized, taken over or confiscated by any authority or body, whether the action is legitimate or not. While there are
provisions for compensation and reimbursement of losses to investors under these circumstances, there is no assurance that these provisions would
restore the value of the investors' original investment or fully compensate them for the investment loss.
Restriction against Greenhouse Gas Emissions
Laws restricting the emissions of greenhouse gases in jurisdictions or areas where mining companies conduct business or sell minerals could adversely
affect operations and demand for these minerals. Mining companies may be subject to regulation of greenhouse gas emissions from stationary
sources as well as mobile sources such as cars and trucks. Current and proposed laws, regulations and trends and electricity generators may influence
the switch to other fuels that generate less greenhouse gas emissions, possibly further reducing demand for certain minerals.
Anti-Corruption Legislation
Mining companies are subject to anti-corruption legislation including the Corruption of Foreign Public Officials Act (Canada) and other similar acts
(collectively "Anti-Corruption Legislation"), which prohibit mining companies or any of their officers, directors, employees or agents acting on
their behalf from paying, offering to pay or authorizing the payment of anything of value to any foreign government official, government staff
member, political party or political candidate in an attempt to obtain or retain business or to otherwise influence a person working in an office
capacity. The Anti-Corruption Legislation also requires public companies to make and keep books and records that accurately and fairly reflect their
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transactions and to devise and maintain an adequate system of internal accounting controls. International activities create the risk of unauthorized
payments or offers of payments by employees, consultants or agents, even though they may not always be subject to a mining company's control.
Mining company's existing safeguards and any future improvements may provide to be less than effective, and employees, consultants and agents
may engage in conduct for which mining companies may be held responsible. Any failure by a mining company to adopt appropriate compliance
procedures and to ensure that its employees and agents comply with Anti-Corruption Legislation and applicable laws and regulations in foreign
jurisdictions could result in substantial penalties or restrictions on its ability to conduct its business, which may have a material adverse impact on a
mining company or its share price.
Risks Relating to the Agriculture Sector
Risks Relating to UAG's Business
Unpredictable Weather Conditions, Pest Infestations and Diseases
The occurrence of severe adverse weather conditions, especially droughts, hail, floods or frost, is unpredictable and may have a potentially devastating
impact on agricultural, livestock and dairy production, and may otherwise adversely affect the supply and price of the agricultural commodities that
UAG sells and uses in its business. Adverse weather conditions may be exacerbated by the effects of climate change. The effects of severe adverse
weather conditions may reduce yields of UAG's products or require UAG to increase its level of investment to maintain yields. Additionally, higher
than average temperatures and rainfall can contribute to an increased presence of insects, which could negatively affect crop, rice and livestock yields.
Future droughts could also reduce the yield and quality of UAG's agricultural, livestock and dairy production.
The occurrence and effects of disease and plagues can be unpredictable and devastating to agricultural, livestock and dairy products, potentially
rendering all or a substantial portion of the affected harvests unsuitable for sale. UAG's crops, rice and blueberries are also susceptible to fungus and
bacteria that are associated with excessively moist conditions. Even when only a portion of the production is damaged, UAG's results of operations
could be adversely affected because all or a substantial portion of the production costs may have been incurred. Although some diseases are treatable,
the cost of treatment is high, and such events could adversely affect UAG's operating results and financial condition. Furthermore, if UAG fails to
control a given plague or disease and its production is threatened, it may be unable to supply its customers.
Diseases among UAG's cattle and sheep herds, such as brucellosis and foot-and-mouth disease, can have an adverse effect on dairy production and
fattening, rendering cows and sheep unable to produce dairy or meat for human consumption. Outbreaks of cattle and sheep diseases may also result
in the closure of certain important markets, such as the United States, to UAG's cattle and sheep products. A future outbreak of diseases among
UAG's cattle and sheep herds could adversely affect its cattle, sheep and dairy sales.
Product Price Fluctuations
Prices for agricultural products, like those of other commodities, have historically been cyclical and sensitive to domestic and international changes
in supply and demand and can be expected to fluctuate significantly. In addition, some of the agricultural products UAG produces, such as soybeans
and wheat, are traded on commodities and futures exchanges and thus are subject to speculative trading, which could adversely affect it. The prices
that UAG is able to obtain for its agricultural products depends on many factors beyond its control including:
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prevailing world commodity prices, which historically have been subject to significant fluctuations over relatively short periods of time,
depending on worldwide demand and supply;
changes in the agricultural subsidy levels of certain important producers (mainly the U.S. and the EU) and the adoption of other government
policies affecting industry market conditions and prices;
changes to trade barriers of certain important consumer markets (including China, India, the U.S. and the EU);
changes in government policies for biofuels;
world inventory levels (i.e., the supply of commodities carried over from year to year);
climatic conditions and natural disasters in areas where agricultural products are cultivated;
the production capacity of UAG's competitors; and
demand for and supply of competing commodities and substitutes.
Further, there is a strong relationship between the value of UAG's land holdings and market prices of the commodities UAG produces, which are
affected by global economic conditions. A decline in the prices of the commodities UAG produces below their current levels for a sustained period
of time could significantly reduce the value of UAG's land holdings.
A Limited Operating History with a History of Losses
UAG has a limited operating history and has recorded negative cash flows and incurred operating losses in many of the fiscal years since its formation.
The continued development of UAG's business and the acquisition of additional farmland will require it to make significant capital expenditures.
These expenditures, together with associated operating expenses, may result in continued negative cash flow and net losses in the foreseeable future.
In addition, with UAG's relatively limited operating history, the risk profile of its business may be higher than for those companies with more established
records of operation. UAG may continue to record losses and negative cash flows in future periods, its losses may increase in the future, and in the
event that UAG does have profits, it may be unable to sustain its operating cash flow.
UAG has a limited operating history upon which to evaluate the viability and sustainability of its current business and future prospects. Accordingly,
UAG's future prospects should be considered in light of the risks and uncertainties experienced by other early stage agricultural companies. UAG
may be unsuccessful in addressing any of these risks and uncertainties.
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Dependence on New Capital
UAG has previously financed its business with new equity because its cash flow from operations was insufficient to provide the necessary capital to
fund its operations and expansion. UAG may need additional capital to fund its operations and acquisitions of farmland. If UAG is unable to raise
equity or debt financing on favourable terms, UAG may not be able to fund its capital expenditures and UAG would be required to change its current
business plan.
Expansion of Business through Land Acquisitions
UAG has grown primarily through land acquisitions and the Company understands that UAG plans to continue growing by acquiring other farmland
throughout Uruguay. However, UAG's management is unable to predict whether or when any prospective land acquisitions will occur, or the likelihood
of certain transactions being completed on favourable terms and conditions. UAG's ability to continue to expand its business successfully through
land acquisitions depends on many factors, including its ability to identify land for acquisition or to access capital markets at a favourable cost and
negotiate favourable transaction terms. Even if UAG is able to identify acquisition targets and obtain the necessary financing to carry out these
acquisitions, UAG could financially overextend itself, especially if a land acquisition is followed by a period of lower than projected prices for UAG's
products.
Acquiring land also exposes UAG to risks associated with activities on such land by prior owners. The due diligence UAG typically conducts in
connection with an acquisition, and any contractual guarantees or indemnities that UAG may receive from the sellers of that land, may not be sufficient
to protect it from, or compensate it for, actual liabilities.
Legal Title to UAG Land
If UAG does not obtain governmental authorizations with respect to all of its lands, it could lose the rights to the use of such lands. It is the Company's
understanding that UAG executes purchase promise agreements, or promesas de compraventa, instead of definitive purchases, or compraventas definitivas,
to acquire its rural land in Uruguay. In order for UAG's subsidiaries to obtain legal title to and use the rural land acquired under a promesa, the Company
understands that Uruguayan law requires that each such subsidiary obtain prior governmental authorization. UAG has received governmental
authorization to obtain legal title to and use certain of its lands in the past and it is the Company's understanding that UAG expects to obtain such
authorizations in the future. However, it is the Company's understanding that if the Uruguayan government denies UAG's request for authorization
under the exemptions available to it, or it is determined that the required authorization has not been adequately obtained, UAG could lose its rights
to the use of such land and any of its subsidiaries that have not obtained such authorization would be required to dissolve and liquidate its assets to
its parent company. Any such liquidation could be on unfavourable terms, and could deprive UAG of the benefits of the rights to the use of such
lands under promesas. Any liquidation of a substantial portion of UAG's assets, or any loss of its rights to the use of such lands, could have a material
adverse effect on its business, financial condition and results of operations.
UAG has not conducted surveys of all its farmland and, consequently, the precise area and location of its titles may be in doubt. Title to UAG's
farmlands may be subject to clerical errors in the official certificates or plans or other undetected title defects. Any such clerical errors or defects in
the chain of ownership could subject UAG to third party title claims as the last acquirer of the farmland. A claim contesting UAG's title to a farmland
may cause UAG to lose its right to farm the land and UAG may incur significant costs related to the defense of its title.
Renewal of Farmland Leases
UAG currently leases farmland and the Company understands that UAG intends to increase the amount of farmland that it leases in the future. Many
of UAG's leases are for short-term periods of one to three years. UAG may be unable to secure new leases to expand its operations on terms that
are favourable to it, which would limit UAG's ability to optimize its operations as currently planned. UAG also may not be able to renew leases after
their respective terms conclude. Even if UAG is able to renew these leases, such renewals may not be on terms and conditions that are favourable
to UAG.
Competition
UAG operates in a market where there are other competitors. Competition within the agricultural, livestock and dairy industry is based primarily on
quality and price. If UAG is unable to compete effectively in these areas, it may lose existing customers or fail to acquire new customers. UAG relies
on advanced technological and scientific methodologies to improve its operations. If UAG fails to adopt new technology or to continually upgrade
its facilities and processes to reflect technological advances, such failure could negatively impact its competitive position.
UAG also experiences competition for farmland purchases. Certain of UAG's competitors have greater financial and capital resources. UAG could
face increased competition from newly formed or emerging entities, as well as from established entities that choose to focus (or increase their existing
focus) on farmland in Uruguay. As a result, farmland properties may not be available to UAG on commercially favourable terms or at all.
Volatility in Raw Material Prices
UAG's production process requires various raw materials, including fertilizer, feed, herbicide, agrochemicals and seeds, which it acquires from local
and international suppliers. It is the Company's understanding that UAG does not have long-term supply contracts for most of these raw materials.
Worldwide production of agricultural products has increased significantly in recent years, increasing the demand for agrochemicals and fertilizers.
This has resulted, among other things, in increased prices for fertilizers and agrochemicals. UAG's agricultural business is seasonal, and its revenues
may fluctuate significantly depending on the growing cycle of its crops. A significant increase in the cost of these raw materials, especially fertilizer,
feed and agrochemicals, a shortage of raw materials or the unavailability of these raw materials entirely could reduce its profit margin, reduce its
production and/or interrupt the production of some of its products.
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Seasonality and Fluctuation of Revenues
UAG's agricultural business is seasonal, based upon the planting, growing and harvesting cycles. In addition, quarterly results can vary significantly
from one year to the next due primarily to weather-related shifts in planting schedules, production yields, purchase patterns and costs. UAG incurs
substantial expenditures for fixed costs throughout the year and substantial expenditures for inventory in advance of the planting season.
Seasonality also relates to the limited windows of opportunity that UAG has to complete required tasks at each stage of crop cultivation. Should
events such as adverse weather or transportation interruptions occur during these seasonal windows, UAG would face reduced revenue without the
opportunity to recover until the following season. In addition, because of the seasonality of agriculture, UAG faces the risk of significant inventory
carrying costs should its customers’ activities be curtailed during their normal seasons.
Increased Energy Prices
UAG requires substantial amounts of diesel and other resources for its harvest activities and transport of its agricultural products. UAG relies upon
third parties for its supply of energy resources used in its operations. The prices for and availability of energy resources may be subject to change
or curtailment, respectively, due to, among other things, new laws or regulations, imposition of new taxes or tariffs, interruptions in production by
suppliers, imposition of restrictions on energy supply by government, worldwide price levels and market conditions. If energy supply is cut for an
extended period of time UAG may be unable to find replacement sources at comparable prices, or at all.
Dependence on Export Markets
UAG's operating results depend largely on economic conditions and regulatory policies for its products in major export markets. The ability of UAG's
products to compete effectively in these export markets could be adversely affected by a number of factors that are beyond its control, including the
deterioration of macroeconomic conditions, volatility of exchange rates, the imposition of greater tariffs or other trade barriers or other factors in
those markets, such as regulations relating to chemical content of products and safety requirements. Due to the growing participation in the worldwide
agricultural commodities markets by commodities produced in South America, South American growers, including UAG, are increasingly affected by
the measures taken by importing countries in order to protect their local producers. Measures such as the limitation on imports adopted in a particular
country or region may affect the sector’s export volume significantly and, consequently, UAG's operating results.
The EU has a zero tolerance policy with respect to the import of genetically modified organisms, or genetically modified organisms ("GMO"). While
the drought in Europe has led to the relaxation of these restrictions for certain of its products, UAG may be unable to continue exporting its products
with GMOs to the EU. If the sale of UAG's products into a particular importing country is adversely affected by trade barriers or by any of the
factors mentioned above, the relocation of its products to other consumers on terms equally favourable may not be possible.
Volatility of Agricultural Product Prices and No Hedging
Because UAG does not generally hedge the price risk on its agricultural products, it is unable to have minimum price guarantees for all of its production
and is, therefore, exposed to significant risks associated with the prices of agricultural products and their volatility. Fluctuations in prices of agricultural
products could result in UAG receiving lower prices for its agricultural products than its production costs. Further, as a commodities producer, UAG
naturally has a long position in agricultural products, which increases its risk of loss if prices of agricultural products decrease. If UAG enters into
hedges in the future and if the prices of agricultural products in respect of such hedges increase beyond the prices specified in its various hedging
agreements, UAG would lose some or all of the value of any such increase in prices. UAG may also be subject to exchange rate risks with respect to
hedges it may enter into for wheat because its futures and options positions are valued in U.S. dollars while a portion of its production costs are in
Uruguayan Pesos. In addition, if severe weather conditions or any other disaster causes lower production than that which it has already sold in the
market, UAG may suffer material losses in the repurchase of sold contracts.
Illiquidity of Farmland Assets
UAG's business is focused on acquiring and operating farmland. Farmland investments tend to be relatively illiquid, with the degree of liquidity
generally fluctuating in relation to demand for and the perceived desirability of such investments. Furthermore, the agricultural real estate market in
Uruguay is volatile. Such illiquidity and volatility may limit UAG's ability to vary its portfolio promptly in response to changing economic or investment
conditions. If UAG were required to liquidate farmland investments, the proceeds it receives might be significantly less than the aggregate carrying
value of such property.
Genetically Modified Organisms
Some of the agricultural commodities and food products that UAG produces contain GMOs, which could affect the marketability of its products
or its ability to sell to certain markets. UAG's soybean products contain GMOs in varying proportions depending on the year and location of production.
The use of GMOs in food has been met with varying degrees of acceptance in the markets in which UAG operates. The United States and Uruguay,
for example, have approved the use of GMOs in food products, and GMO and non-GMO grain in those countries is produced and frequently
commingled during the grain origination process. Elsewhere, adverse publicity about genetically modified food has led to governmental regulation
limiting sales of GMO products in some of the markets in which UAG's customers sell its products, including the EU. It is possible that new restrictions
on GMO products will be imposed in major markets for some of UAG's products or that its customers will decide to purchase fewer GMO products
or not buy GMO products at all.
Additionally, UAG's cattle and sheep may be fed with grains or grain by-products containing GMOs, such as soybeans or corn. Consequently, such
products could be considered to contain GMOs by its customers or by governmental or regulatory authorities in its export markets.
Product Contamination
If UAG's products become contaminated, it may be subject to product liability claims, product recalls and restrictions on exports that would adversely
affect its business. The sale of food products for human consumption involves the risk of injury to consumers. These injuries may result from
42
tampering by third parties, bioterrorism, product contamination or spoilage, including the presence of bacteria, pathogens, foreign objects, substances,
chemicals, other agents, or residues introduced during the growing, storage, handling or transportation phases.
Consumption of UAG's products could cause a health-related illness in the future and UAG could become subject to claims or lawsuits relating to
such matters. Even if a product liability claim is unsuccessful or is not fully pursued, the negative publicity surrounding any assertion that UAG's
products caused illness or injury could adversely affect its reputation with existing and potential customers and its corporate and brand image, and
UAG could also incur significant legal expenses. Moreover, claims or liabilities of this nature might not be covered by any rights of indemnity or
contribution that UAG may have against others.
Dependence on its Management Team
UAG is dependent on its management team, and its success may depend on its ability to retain or attract adequate managerial resources. UAG's
success depends, to a large extent, on the ability and judgment of its senior management to make appropriate decisions with respect to its operations.
UAG will continue to retain the qualified personnel needed for its business.
Labour Disputes
UAG's operations are dependent on farm labourers. If UAG became subject to a labour dispute, or if its farm labourers unionize, UAG may not
successfully conclude negotiations on favourable terms, which could result in a significant increase in the cost of labour or could result in work
stoppages or labour disturbances that disrupt its operations.
Future Changes to Laws and Regulations
UAG is subject to numerous laws and regulations. UAG could be adversely affected by changes in regulatory requirements, customs, duties or other
taxes. Existing and future government laws, regulations and policies (including environmental laws, regulations and policies) may greatly influence
how it operates its business, its business strategy and, ultimately, its financial viability. Further, Uruguayan governmental policies may directly or
indirectly influence a number of factors affecting UAG's business, such as the number of acres planted, the mix of crops planted, crop prices, inventory
levels and the rules regarding ownership of land.
Changes to Environmental Regulation as a Result of Climate Change
UAG's activities are subject to laws and regulations relating to the protection of the environment. Under various Uruguayan laws, UAG could become
liable for the costs of removal or remediation of certain hazardous or toxic substances released on, from or in one or more of its properties or
disposed of at other locations. The failure to remove or remediate such substances, if any, may adversely affect its ability to sell such property or to
borrow using the property as collateral, and could potentially also result in claims against UAG by private parties. In addition, global environmental
legislation and policies have become increasingly stringent in recent years as a result of concerns regarding climate change and environmental regulation
in the areas in which UAG operates may also become more stringent.
Insurance Coverage
UAG's production is, in general, subject to different risks and hazards, including adverse weather conditions, fires, diseases and pest infestations, other
natural phenomena, industrial accidents, labour disputes, changes in the legal and regulatory framework applicable to UAG and environmental
contingencies. UAG's insurance may only cover part of the losses UAG may incur and does not cover losses on certain crops and livestock. Furthermore,
certain types of risks may not be covered by the policies that UAG holds. Additionally, any claims to be paid by an insurer due to the occurrence of
a casualty covered by its policies may not be sufficient to compensate UAG for all of the damages suffered. Moreover, UAG may not be able to
maintain or obtain insurance of the type and amount desired at reasonable costs.
Trade Credit Risk
UAG is exposed to risks of loss in the event of non-performance by its customers. UAG has a limited operating history with sales concentrated in
a few key customers. Some of UAG's customers may be highly leveraged and subject to their own operating and regulatory risks. Notwithstanding
UAG's credit review and analysis mechanisms, UAG may experience financial loss in its dealings with other parties.
Risks Relating to OEF's Business
A Limited Operating History
OEF's current operations reflect a restructuring with significant acquisitions in the last two years. As such, OEF's current operations have a limited
history. Accordingly, OEF is subject to many risks common to such enterprises, including under-capitalization, cash shortages, lack of revenue,
integration difficulties and limitations with respect to personnel, financial and other resources. There is no assurance that OEF 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.
A Rise in the Price of Inputs
The profitability of OEF's retail products is highly susceptible to input costs, especially for cattle and chickens. OEF's vertically integrated cattle
supply provides additional control over a portion of beef product input costs, while the chicken supply chains remain outside OEF's control. However,
OEF is still susceptible to significant input cost uncertainty, including the cost of cattle feed and market prices for cattle.
Production and pricing of inputs, such as cattle and chicken, are determined by constantly changing market forces of supply and demand over which
OEF has limited or no control. Such factors include, among other things, weather patterns, outbreaks of disease, the level of supply inventories and
demand for grains and other feed ingredients, as well as government agricultural and energy policies.
Volatility in OEF's commodity and raw material costs directly impacts its gross margins and profitability. OEF's objective is to offset commodity
price increases with pricing actions over time. However, OEF may not be able to increase its product prices enough to sufficiently offset increased
43
raw material costs due to consumer price sensitivity or the pricing postures of its competitors. In addition, if OEF increases prices to offset higher
costs, it could experience lower demand for its products and sales volumes. Conversely, decreases in OEF's commodity and other input costs may
create pressure on it to decrease its prices. Over time, if OEF is unable to price its products to cover increased costs, to offset operating cost increases
with continuous improvement savings, then commodity and raw material price volatility or increases could materially and adversely affect its profitability,
financial condition and results of operations.
Product Pricing and Sales Volumes
OEF’s profitability is dependent, in large part, on its ability to make pricing decisions regarding its products that, on the one hand encourage consumers
to buy, yet on the other hand recoup development and other costs associated with those products. Products that are priced too high will not sell and
products priced too low will lower OEF’s profit margins.
The quantity and pricing for sales of OEF’s products to retail and wholesale customers are subject to fluctuations, including adverse changes, resulting
from, amongst other things, changes in end consumer demand, product decisions by wholesale customers and the actions of competitors.
Brand Value and Competition
The food industry, and the grocery retail sector, are intensely competitive. Competition is based on product availability, product quality, price, effective
promotions and the ability to target changing consumer preferences together with market share objectives and promotional activities of retailers.
OEF experiences price pressure from time to time as a result of retailers' promotional efforts, competitors promotional efforts and benchmark pricing
for commodity products in the product categories supplied by OEF. Increased competition together with increased retail consolidation could result
in reduced sales, margins, profits and market share.
In many product categories, OEF competes not only with other branded products, but also with private label or commodity products that generally
are sold at lower prices. Consumers are more likely to purchase OEF's products if they believe that its products provide a higher quality and greater
value than less expensive alternatives. If the difference in quality between OEF's brands and private label and commodity products narrows, or if
there is a perception of such a narrowing, consumers may choose not to buy OEF's products at prices that are profitable for it. In addition, in periods
of economic uncertainty, consumers tend to purchase more lower-priced products. To the extent this occurs, OEF could experience a reduction in
the sales volume of its higher margin products or a shift in its product mix to lower margin offerings.
Risks Related to OEF's Labour Force
OEF is subject to risks related to its labour force, including compliance with federal or provincial labour laws such as, amongst others, minimum
wage requirements, overtime, working and safety conditions, employment eligibility and temporary foreign worker requirements. Other risks related
to the labour force include any changes in employment eligibility requirements, the cessation or limitation of access to federal or provincial labour
programs, including the temporary foreign worker program, or significant increases in labour or other costs to OEF in running its businesses.
The majority of CPM's production workers are employed through the Canadian Temporary Foreign Workers Program ("TFWP"). In June 2014,
amendments were made to the TFWP, which may reduce the number and availability of employees it can hire through the program. To the extent
this occurs, the financial results of CPM and OEF could be adversely affected.
If new Canadian temporary foreign worker legislation is enacted, or the current TFWP is modified further, such laws or modifications may contain
provisions that could increase the costs in recruiting, training and retraining workers, and increase the costs of complying with employment laws and
standards.
Food Safety
OEF is subject to risks that affect the food industry in general, and is exposed to potential liability and costs related to food spoilage, accidental
contamination, food allergens, evolving consumer preferences and nutritional and health-related concerns, product tampering, consumer product
liability, product labeling and advertising errors, and the potential costs and disruptions of a product recall, either in their own operations, or in the
operations of the third parties they rely on for certain processing and other supply chain activities. OEF’s processes and products are susceptible to
contamination by disease-producing organisms, or pathogens, such as E. Coli, salmonella and listeria. There is a risk that these pathogens, as a result
of food processing, could be present in either OEF’s processing facilities or products. OEF requires strict control of the temperature at which it
stores its products and is susceptible to any risks of spoilage due to issues with maintaining appropriate temperatures.
OEF's employees and management follow strict food safety protocols and processes in their manufacturing facilities and distribution systems including,
but not limited to, striving for compliance with all applicable regulatory requirements, employee training and supervision in proper handling practices,
and the maintenance of systems that allow traceability of all meat products from CPM to other OEF businesses or third parties, and the traceability
of all meat products from OEF's businesses to customers or end retailers. However, these measures, even when working effectively, cannot eliminate
all risks of an instance of food borne illness. Pathogens can also be introduced to OEF’s products as a result of improper handling in transportation
or at the further processing, foodservice or consumer level, along with third party tampering of products.
OEF could also be required to recall certain of its products in the event of contamination or adverse test results or as precautionary measures. There
is also a risk that not all of the product subject to a recall will be properly identified, or that a recall will not be successful or not be enacted in a timely
manner. Any product contamination could subject OEF to product liability claims, adverse publicity and government scrutiny, investigation or
intervention, resulting in increased costs and decreased sales.
Livestock Disease
Cattle are vulnerable to viral infections and other diseases and there can be no assurance that OEF's livestock will not be infected. A serious outbreak
of disease amongst OEF's cattle may result in losses or costs, and have a negative impact on OEF's reputation. In addition, an outbreak of such
disease in the cattle industry generally, even if it does not directly infect OEF's cattle, could impact the cattle and beef industry negatively.
44
An outbreak of cattle disease or any outbreak of other animal epidemics might also result in material disruptions to CPM's operations, the operations
of its customers or suppliers, including other OEF businesses, or a decline in the industry or in the economic growth of Canada and surrounding
regions, any of which could have a material adverse impact on CPM's operations. Further, consumer concerns regarding safety and quality of food
products or health concerns could adversely affect the downstream sales of CPM's customers, including OEF.
Economic Dependence by OEF's Products on Large Accounts
The two largest accounts for OEF's products represented approximately 18% of OEF's consolidated revenues for 2014. Accordingly, OEF's success
depends, to a large extent, on its ability to retain its key customers, which may not be possible.
Regulation
OEF's operations are subject to extensive inspection and regulation by and policies from federal, provincial and local government agencies, including
but not limited to: the Canadian Food Inspection Agency; the Ministry of Agriculture in Canada; Health Canada and provincial Ministries of the
Environment in Canada, as well as foreign laws and regulations. Amongst other things, these agencies regulate the processing, packaging, storage,
distribution, advertising, and labeling of products, including food safety standards. OEF strives to maintain compliance with all laws and regulations
and maintain all permits and licenses relating to its operations. Nevertheless, there can be no assurance that OEF is in compliance with such laws and
regulations, has all necessary permits and licenses, and will be able to comply with such laws and regulations, permits and licenses in the future. Failure
to comply with applicable laws and regulations and loss of or failure to obtain permits, licenses and registrations could delay or prevent OEF from
meeting current product demand, introducing new products or building new facilities. If OEF is found to be out of compliance with applicable laws
and regulations, it could be subject to civil remedies, including fines, injunctions, recalls or seizures, as well as potential criminal sanctions. In addition,
the failure or alleged failure to comply with applicable laws and regulations could subject OEF to product liability claims, adverse publicity and
government scrutiny, investigation or intervention, resulting in increased costs and decreased sales. Claims regarding "natural" and "organic" products
have also been the subject of increased public scrutiny in recent years.
Regulatory Changes
There have been many developments in the Canadian agriculture industry over the past number of years. In particular, the Canadian government has
been actively engaged in activities to modernize and strengthen food safety laws in Canada and this area is expected to continue to develop. There
can be no assurance that additional regulation will not be enacted and it is difficult to predict the impact of any such additional regulation on OEF
and its operations and financial condition.
Sales to Foreign Countries
OEF sells products in select EU markets, China and the Middle East. As a result, OEF is subject to various risks and uncertainties relating to
international sales, including:
•
•
•
•
•
•
•
imposition of tariffs, quotas, trade barriers and other trade protection measures imposed by foreign countries regarding the importation
of poultry, beef, pork and prepared foods products, in addition to import or export licensing requirements imposed by various foreign
countries;
closing of borders by foreign countries to the import of poultry, beef and pork products due to animal disease or other perceived health
or safety issues;
impact of currency exchange rate fluctuations;
political and economic conditions;
tax rates that may exceed those in Canada and earnings that may be subject to withholding requirements and incremental taxes upon
repatriation;
potentially negative consequences from changes in tax laws; and
distribution costs, disruptions in shipping or reduced availability of freight transportation.
Negative consequences relating to these risks and uncertainties could jeopardize or limit OEF's ability to transact business in one or more of those
markets where it sells its products or in other developing markets and could adversely affect its financial results.
Consumer Trends
The success of OEF depends in part on its ability to respond to market trends and produce products that anticipate and respond to the changing
tastes and dietary habits of consumers. OEF’s failure to anticipate, identify, or react to these changes or to innovate could result in declining demand
and prices for its products.
Supply Chain Management
Successful management of OEF's supply chain is critical to its success. Insufficient supply of products threatens OEF's ability to meet customer
demands while over capacity threatens its ability to generate competitive profit margins.
Livestock Fertility Rates
OEF's cattle operations are largely dependent on maintaining adequate fertility rates amongst its cows. A significant decrease in fertility rates amongst
OEF's cows may lead to a decrease in the herd size and the quantity of beef for sale.
Lack of Qualified Personnel
OEF's performance depends to a significant extent on its ability to attract and retain highly qualified and skilled management personnel with appropriate
cattle, production and food product expertise. The loss of key persons or the inability to recruit appropriate personnel could have a negative impact
on OEF's performance. In addition, OEF would need to hire and retain qualified employees to work in various operational positions.
45
A Reliance on Third Party Operators in Cattle Operations
All of OEF's cattle raising operations are now conducted by third parties operating under contract to raise livestock owned by OEF. The actions and
performance of these third parties raising OEF’s cattle, including in areas such as calf weaning weights, calf weaning rates, and rate of weight gain
is not within OEF's control.
Poor Weather Conditions
Poor weather conditions or climate change may adversely affect OEF's operational results. Cattle operations can potentially be negatively impacted
by weather conditions leading to increased feeding costs, reduced weight gain by animals and potentially higher animal mortality.
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 declared an initial monthly dividend on December 12, 2012. Pursuant to the Dividend Policy, the Company paid a monthly dividend
at least equal to 0.833% of the Company's Book Value based on the most recently filed financial statements of the Company at the time the dividend
was declared. On February 25, 2013, the Company instituted a DRIP for Canadian shareholders.
On August 13, 2013, the Board elected to terminate the DRIP and to cease paying monthly dividends pursuant to the Company's Dividend Policy.
The Company does not currently intend to pay a dividend on its common shares. Any future determination to pay dividends will be at the discretion
of the Board and will depend upon the capital requirements of the Company, results of operations and such other factors as the Board considers
relevant.
During the last three financial years, the Company has declared and paid cash dividends per common share as noted below:
Dividend per
share
Record Date
Payment Date
$0.038
December 31, 2012
January 15, 2013
$0.038
January 31, 2013
February 15, 2013
$0.038
February 28, 2013
March 15, 2013
$0.038
March 28, 2013
April 12, 2013
$0.038
April 30, 2013
May 15, 2013
$0.035
May 31, 2013
June 17, 2013
$0.035
June 28, 2013
July 15, 2013
$0.035
July 31, 2013
August 15, 2013
46
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 2014 is set out below:
Month
Last
High
Low
Share Volume
January
$2.53
$2.72
$2.34
3,493,523
February
$2.42
$2.64
$2.41
1,984,737
March
$2.49
$2.56
$2.41
1,063,113
April
$2.53
$2.68
$2.40
1,741,996
May
$2.80
$2.80
$2.51
1,927,202
June
$3.16
$3.22
$2.65
4,391,621
July
$3.21
$3.27
$3.05
4,052,764
August
$3.28
$3.34
$3.00
2,251,624
September
$2.78
$3.30
$2.68
2,049,751
October
$2.09
$2.86
$2.05
3,489,532
November
$1.89
$2.25
$1.86
2,870,937
December
$1.88
$1.99
$1.39
5,239,493
Source: Bloomberg.
47
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; period
of directorship with the Company; and shareholdings of each of the directors and executive officers of the Company as of the date of this AIF.
Directors of the Company hold office until the next annual meeting of shareholders or until their successors are duly elected or appointed.
Number of
Voting Securities
Owned(4)
146,343(5)
Percentage of
Issued and
Outstanding
Voting Securities
0.15%
2013
90,600(6)
0.09%
Corporate Director
2012
54,643(7)
0.06%
Director
Corporate Director
2014
76,943(8)
0.08%
John Embry
Ontario, Canada
Director
Chief Investment Strategist,
Sprott Asset Management LP (an
investment management limited
partnership)
2007
1,650,000
1.69%
Peter Grosskopf
Ontario, Canada
Managing
Director and
Director
CEO and Director, Sprott Inc.
(an asset management company);
CEO and Director, Sprott
Resource Lending Corp. (a private
natural resource lending
company)
2012
N/A
N/A
Ron F. Hochstein(1)(2)(3)
British Columbia,
Canada
Director
2013
59,393(9)
0.06%
Michael Staresinic
Ontario, Canada
CFO
CEO and Director of Denison
Mines Corp. (a uranium
exploration and development
company); President, CEO and
Director of Lundin Gold Inc. (a
gold development company); and
Director of Energy Fuels Inc. (a
uranium company)
CFO, SRC
N/A
21,600(10)
0.02%
Arthur Einav
Ontario, Canada
General Counsel, Managing Director, SRC
Corporate
Secretary and
Managing
Director
Managing
Managing Director, SRC
Director
N/A
21,404(11)
0.02%
N/A
29,148(12)
0.03%
Name, Province/
State and Country of
Residence
Terrence A. Lyons(1)(2)
British Columbia,
Canada
Position held
with the
Company
Director and
Chairman
Principal Occupation
Corporate Director
Stephen Yuzpe
Ontario, Canada
President, CEO
and Director
President, CEO and Director,
SRC
Lenard F. Boggio(1)(2)(3)
British Columbia,
Canada
Director
Joan E. Dunne(1)(3)
Alberta, Canada
Andrew Stronach
Ontario, Canada
Director Since
2005
Notes:
(1) Member of the Corporate Governance and Nominating Committee and the Conflict Resolution Committee.
(2) Member of the Compensation Committee.
(3) Member of the Audit Committee.
(4) 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.
48
(5) 44,643 of the 146,343 common shares were designated for the account of Mr. Lyons under the Company's amended and restated 2014 employee profit sharing plan
(the "EPSP"). As at December 31, 2014, 29,762 of the common shares designated under the EPSP (the "EPSP Shares") were not yet vested.
(6) 15,600 of the 90,600 common shares were designated for the account of Mr. Yuzpe under the EPSP. As at December 31, 2014, all of the EPSP Shares were fully
vested.
(7) 44,643 of the 54,643 common shares were designated for the account of Mr. Boggio under the EPSP. As at December 31, 2014, 29,762 of the EPSP Shares were
not yet vested.
(8) 44,643 of the 76,943 common shares were designated for the account of Ms Dunne under the EPSP. As at December 31, 2014, 29,762 of the EPSP Shares were
not yet vested.
(9) 44,643 of the 59,393 common shares were designated for the account of Mr. Hochstein under the EPSP. As at December 31, 2014, 29,762 of the EPSP Shares
were not yet vested.
(10) 6,800 of the 21,600 common shares were designated for the account of Mr. Staresinic under the EPSP. As at December 31, 2014, all of the EPSP Shares were
fully vested.
(11) 8,500 of the 21,404 common shares were designated for the account of Mr. Einav under the EPSP. As at December 31, 2014, all of the EPSP Shares were fully
vested.
(12) 8,500 of the 29,148 common shares were designated for the account of Mr. Stronach under the EPSP. As at December 31, 2014, all of the EPSP Shares were
fully vested.
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) Terrence A. Lyons who, prior to October 2011, was Chairman of Northgate Minerals
Corporation (a gold mining company) and, prior to October 2013, was the Chairman of EACOM Timber Corporation (a lumber company); (ii)
Stephen Yuzpe who, prior to October 21, 2013, was the CFO of the Company; (iii) Lenard F. Boggio who was a partner of PricewaterhouseCooopers
LLP ("PwC") (an accounting firm) until May 2012; (iv) Joan E. Dunne who was the Vice President, Finance and CFO of Painted Pony Petroleum
Ltd. (a junior to mid-sized oil and gas company) until September 2013; (v) Peter Grosskopf who was the President of Cormark Securities Inc.
("Cormark") (a brokerage firm) from 2004 to 2010; (vi) Ron Hochstein who was the President of Denison Mines Corp. until January 2015; (vii)
Michael Staresinic who, prior to December 2013, was the Vice President, Finance of Sprott Inc. and, prior to September 2010, was the Vice President,
Finance of Integrated Asset Management Corp. (an alternative asset management company); (viii) Arthur Einav who, prior to May 10, 2010, practiced
law at Davis Polk & Wardwell LLP (a law firm); and (ix) Andrew Stronach who, prior to July 2010, was an independent consultant to SCLP, Sprott
Inc., the Company and OEF.
As of the date of this AIF, the directors and executive officers of the Company as a group, beneficially own, directly or indirectly, or exercise control
or direction over approximately 2.2 million common shares of the Company, being approximately 2.2% 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, CEO or CFO 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:
(a)
that was issued while the director or executive officer was acting in the capacity as director, CEO or CFO, or
(b) that was issued after the director or executive officer ceased to be a director, CEO or CFO and which resulted from an event that
occurred while that person was acting in the capacity as director, CEO or CFO.
In addition, except as set forth below, no director or executive officer of the Company:
(c) 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
(d) 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:
(e) 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
(f)
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.
On October 13, 2014, RB Energy Inc., ("RBI"), a company of which Mr. Ron Hochstein was a director during the period January 31, 2014 to October
3, 2014, announced that, among other things, the board of directors of RBI had approved a filing on October 14, 2014, for an initial order to
commence proceedings under the Companies' Creditors Arrangement Act (the "CCAA") at the Quebec Superior Court. On October 15, 2014, RBI further
announced that the Quebec Superior Court had issued an amended and restated initial order in respect of RBI and certain of its subsidiaries under
49
the CCAA (the "RBI Court Order"). RBI is now under the protection of the court. KPMG LLP has been appointed monitor under the RBI Court
Order. The TSX de-listed RBI's common shares effective at the close of business on November 24, 2014 for failure to meet the continued listing
requirements of the TSX. Since that time, RBI’s common shares have been suspended from trading.
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. ("Royal Oak") at the request of Brookfield, which was subject to cease trade orders in
each of the provinces in British Columbia, Alberta, Ontario and Quebec due to the failure of Royal Oak to file financial statements since the financial
year ended December 31, 2003. After restructuring, the cease trade orders were lifted on July 4, 2012. Royal Oak was privatized by Brookfield effective
December 31, 2013.
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 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 "D" hereto.
Composition of the Audit Committee
The audit committee of the Company (the "Audit Committee") is composed of the following three directors: Lenard F. Boggio (Chair), Joan E.
Dunne and Ron Hochstein. All three members are considered "independent" and "financially literate" (as such terms are defined in NI 52-110).
50
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:
Name
Lenard F. Boggio
(Chair)
Education and Experience
Mr. Boggio is a former partner of PwC. Mr. Boggio has significant expertise in financial reporting,
auditing matters and transactional support, previously assisting, amongst others, clients in the mineral
resource and energy sectors, including exploration, development and production stage operations in
the Americas, Africa, Europe and Asia. Mr. Boggio earned Bachelor of Arts and Bachelor of
Commerce degrees from the University of Windsor, Ontario. In 1985 Mr. Boggio became a member
of the Institute of Chartered Accountants of British Columbia and in 1999 he achieved his
CPA (Illinois). Mr. Boggio was conferred with an FCA designation in 2007 by the Institute of
Chartered Accountants of British Columbia for distinguished service to the profession
and community. Mr. Boggio was an audit and assurance practitioner with PwC, and prior to
that Coopers & Lybrand, from 1982 to his retirement as a partner of the firm in 2012.
Joan E. Dunne
Ms. Dunne has significant experience in the oil and gas industry. Ms. Dunne is a director and the
Chair of the Audit Committee of Tundra Oil & Gas Limited, a private energy company wholly owned
by James Richardson & Sons, Limited. She retired in September 2013 from Painted Pony Petroleum
Ltd. as Vice President, Finance and CFO since start-up in February 2007. Prior to Painted Pony, she
served as Vice President, Finance and CFO for several publically traded oil and gas companies. In
1983, Ms. Dunne received her Chartered Accountant designation from the Institute of Chartered
Accountants of Alberta. Ms. Dunne earned her Bachelor of Commerce (major accounting) degree
from the University of Calgary in 1979.
Ron Hochstein
Mr. Hochstein has a wealth of experience in the mining industry. He is currently the CEO of Denison
Mines Corp., a uranium exploration and development company, and President and CEO of Lundin
Gold Inc., a gold development company. Mr. Hochstein has served as an executive officer, director
and audit committee member of several public resource-based companies. Mr. Hochstein is a
Professional Engineer and has a B.Sc. in metallurgical engineering from University of Alberta and an
MBA from University of British Columbia.
Pre-Approval Policies and Procedures
The Audit Committee is responsible for the oversight of the work of the external auditor. As part of this responsibility, the Audit Committee is
required to pre-approve the audit and non-audit services performed by the external auditor in order to assure that they do not impair the external
auditor's independence from the Company. Accordingly, on May 10, 2013, the Audit Committee adopted an Audit and Non-Audit Pre-Approval
Policy (the "Pre-Approval Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by
the external auditor may be pre-approved.
Unless a type of service has received the pre-approval of the Audit Committee for the fiscal year pursuant to the Pre-Approval Policy, it requires
specific pre-approval by the Audit Committee if it is to be provided by the external auditor. Any proposed services exceeding the pre-approved cost
levels or budgeted amounts for the fiscal year as specified in the Pre-Approval Policy, will also require specific pre-approval by the Audit Committee.
The Audit Committee considers whether such services raise any issue regarding the independence of the external auditor. For this purpose, the Audit
Committee also takes into account whether the external auditor is best positioned to provide the most effective and efficient service, for reasons such
as its familiarity with the Company's business, people, culture, accounting, systems, risk profile and other factors and whether the service might
enhance the Company's ability to manage or control risk or improve audit quality. All such factors are considered as a whole, and no one factor is
necessarily determinative.
The Audit Committee is also mindful of the relationship between fees for audit and non-audit services in deciding whether to pre-approve any such
services and may determine, for each fiscal year, the appropriate ratio between the total amount of fees for audit services, and audit-related services
and the total amount of fees for tax services and for certain permissible non-audit services classified as all other services.
The Pre-Approval Policy describes the audit, audit-related, tax and all other services that have been granted the pre-approval of the Audit Committee.
The term of such pre-approval is 12 months from the date of pre-approval, unless the Audit Committee considers a different period and states
otherwise. The Audit Committee annually reviews and pre-approves the services that may be provided by the external auditor without obtaining
specific pre-approval from the Audit Committee. The Audit Committee can add or subtract to the list of pre-approved services from time to time,
based on subsequent determinations.
The Pre-Approval Policy also outlines a list of prohibited non-audit services which may not be provided by the Company's external auditor.
On March 19, 2014, the Audit Committee granted pre-approval for all audit, audit-related, tax and all other services to be provided to the Company
by the external auditor as specified in the Pre-Approval Policy to an aggregate annual (fiscal year) maximum of $750,000 (other than specifically preapproved audit services).
51
External Auditor Service Fees (By Category)
For the years ended December 31, 2014 and 2013, PwC and its affiliates received or accrued fees from the Company, SRP and OEOG as detailed
below:
December 31, 2014
December 31, 2013
($)
($)
Audit Fees
164,532
395,000
Audit-Related Fees
184,000
184,500
15,900
85,300
—
85,500
364,432
750,300
Tax Fees
All Other Fees
Total Fees
The "Audit Fees" noted above were paid to PwC in connection with the annual audits. The "Audit-Related Fees" noted above were paid to PwC in
connection with review of interim financial statements, investment valuation and accounting guidance. "Tax Fees" relate 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.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
For the year ended December 31, 2014, the Company (i) paid and accrued to SCLP a Management Services Fee (as defined below in "Material Contracts
- Amended and Restated MSA") in the amount of $7.7 million (2013: $8.1 million; 2012: $10.0 million) for services SCLP rendered to the Company in
accordance with the terms of the Amended and Restated MSA; and (ii) paid and accrued to SCLP $7 thousand (2013: $25 thousand; 2012: $nil.) for
reimbursable expenses in accordance with the terms of the Amended and Restated MSA. In 2014, SRCLP did not accrue a Management Profit
Distribution (as defined below in "Material Contracts - Partnership Agreement") pursuant to the Partnership Agreement.
The general partner of SCLP is Sprott Consulting GP Inc. The directors and officers of Sprott Consulting GP Inc. are: Peter Grosskopf (President
and director), Stephen Yuzpe (CFO) and Arthur Einav (Managing Director, General Counsel and Secretary). The sole limited partner of SCLP, and
the sole shareholder of Sprott Consulting GP Inc., is Sprott Inc. The directors and officers of Sprott Inc. are: Eric Sprott (Chairman), Peter Grosskopf
(CEO and director), Marc Faber (director), Jack C. Lee (director), Sharon Ranson (director), Arthur Richards Rule IV (director), James T. Roddy
(director), Paul H. Stephens (director), Rosemary Zigrossi (director), Steven Rostowsky (CFO and Corporate Secretary) and Arthur Einav (General
Counsel). Sprott Inc. 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: Stephen Yuzpe (President and director) and Arthur Einav (General Counsel and Corporate Secretary). The
sole limited partner of SRCLP, and the sole shareholder of Sprott Resource Consulting GP Inc., is SCLP.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Company's common shares is CST Trust Company., P.O. Box 700, Postal Station B, Montreal, QC, H3B 3K3.
The register of transfers of the Company's common shares is located in the Toronto office of CST Trust Company.
MATERIAL CONTRACTS
The only material contracts entered into by the Company within the year ended December 31, 2014 or before or after such time, that are still in effect,
other than in the ordinary course of business, are the Amended and Restated MSA and the Partnership Agreement. Copies of these material contracts
have been filed on SEDAR and can be found at www.SEDAR.com.
Amended and Restated MSA
On October 1, 2011, the Board 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 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 CEO; and one individual to serve as CFO.
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 winding-up, 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
52
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 (the "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 Compensation"). 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. The Company is also responsible for all reasonable expenses incurred by SCLP in connection
with its duties pursuant to the Amended and Restated MSA to the extent such expenses were incurred for the Company and do not represent
administrative costs of SCLP necessary for it to carry out its functions thereunder.
Pursuant to the Amended and Restated MSA, the Company has agreed to indemnify SCLP and its directors and officers, among others, in respect
of certain losses and claims, subject to prescribed exceptions.
For the year ended December 31, 2014, the Company (i) paid or accrued to SCLP a Management Services Fee in the amount of approximately $7.7
million for services SCLP rendered to the Company in accordance with the terms of the Amended and Restated MSA (such amount includes the
Management Compensation amount of approximately $2.8 million); and (ii) paid or accrued to SCLP approximately $7 thousand for reimbursable
expenses in accordance with the terms of the Amended and Restated MSA.
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 under the name "Sprott Resource Partnership". The Company
now invests and operates in the natural resource sector through SRP.
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 SRP, 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
SRP pursuant to the Partnership Agreement. Following execution of the Partnership Agreement, the Class B Unit held by the Company's affiliate
was redeemed by SRP and the affiliate ceased to be a partner of SRP.
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 SRP.
The Managing Partner holds all non-voting Partnership units and, within the terms and conditions established by the Company, will manage SRP's
investment activities and assets, and administer the day-to-day operations of SRP. SRCLP may be removed as the managing partner of SRP by way
of a Special Resolution (as defined in the Partnership Agreement) approved by no less than two thirds of the votes cast by the holders of the voting
SRP units who vote on the resolution.
SRCLP, as managing partner, has the power and authority to transact the business of SRP and to deal with and in SRP's assets for the use and benefit
of SRP, except as limited by any direction of the Board, and subject to certain limits on authority established from time to time by the Board.
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 SRP and Net Losses of SRP 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 SRP, an amount equal to the sum of the following amounts: (i) the product of the average Quarterly
Net Asset Value of SRP 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 SRP 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 SRP" means, in respect of a fiscal quarter of SRP, the average of the net asset value of SRP as at the end of such fiscal quarter and
the net asset value of SRP as at the end of the immediately preceding fiscal quarter. "Net Profits of SRP" means, for any fiscal year of SRP, the
net profits of SRP plus Components of Other Comprehensive Income less the profits or loss attributable to the minority interest or non-controlling
interest for such fiscal year as set forth in SRP's audited financial statements prepared in respect of such fiscal year and plus/less any amounts to be
agreed upon between SRC and SRCLP; provided that if the Net Profits of SRP is a negative amount, such amount shall be referred to as "Net Losses
of SRP". "Components of Other Comprehensive Income" means, for any fiscal year of SRP, the other comprehensive income of SRP that
relates to an asset whose impairment is included in the Net Profits of SRP as set forth in SRP's audited financial statements prepared in respect of
such fiscal year, provided that (i) the Components of Other Comprehensive Income that relates to any asset shall not be greater than the impairment
included for such asset in the Net Profits of SRP and (ii) Components of Other Comprehensive Income shall be decreased by any negative amount
of the total other comprehensive income for such fiscal year.
If SRP 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 SRP
53
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 non-cash 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 SRP for such noncash consideration; (b) the Managing Partner is removed as managing partner of SRP; and (c) SRP 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 SRP for the fiscal year, an amount equal to
the net profits of SRP for such fiscal year less the Management Profit Distribution for such fiscal year.
SRP shall continue until the earlier of:
•
•
•
•
the passing of a Special Resolution to dissolve SRP;
the disposition of all or substantially all of the assets of SRP;
the date on which one partner holds all voting and non-voting units of SRP; and
the entry of a final judgment, order or decree of a court of competent jurisdiction adjudicating SRP to be a bankrupt, and the expiration
without appeal of the period, if any, allowed by applicable law in which to appeal therefrom.
INTERESTS OF EXPERTS
Names and Interests of Experts
The Company's auditors are PricewaterhouseCoopers LLP, Chartered Accountants, PwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, M5J
0B2. PwC have advised that they are independent of the Company in accordance with applicable rules of professional conduct.
The Company's independent qualified reserves evaluator is McDaniel & Associates Consultants Ltd. ("McDaniel"), 2200, 255 - 5th Avenue S.W.,
Calgary, Alberta, T2P 3G6. As of the date hereof, the "Designated Professionals" (as defined in Form 51-102F2 under the Canadian Securities
Administrators' National Instrument 51-102 - Continuous Disclosure Obligations) of McDaniel do 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 management's discussion and analysis for its most recently
completed financial year.
54
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.
As at December 31, 2014, Sprott Resource Corp. (the "Company") carries on its oil and gas activities through its subsidiary One Earth Oil & Gas Inc.
("One Earth Oil & Gas" or "OEOG").
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 One Earth Oil & Gas. All of the Company's reserves are located in Alberta,
Canada.
As at December 31, 2014, the Company owned 97.1% percent of the issued and outstanding shares of One Earth Oil & Gas, representing approximately
71.7 million of the approximately 73.8 million issued and outstanding shares of One Earth Oil & Gas. As a result, 2.9 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 2.9 percent minority interest in One Earth Oil & Gas which is not owned by the Company.
As at December 31, 2014, One Earth Oil & Gas had options and warrants outstanding, the exercise of some or all of which would dilute the Company's
interest in One Earth Oil & Gas. For further information, see "Intercorporate Relationships" in the Company's Annual Information Form ("AIF"). 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 One Earth Oil
& Gas' proved and probable reserves in a report dated March 3, 2015 and effective December 31, 2014 (the "One Earth Oil & Gas Reserve Report").
The information included in this Statement is based on and derived from the One Earth Oil & Gas Reserve Report.
In addition, it should be noted that:
(i)
(ii)
estimates in this Statement of future net revenue, whether calculated without discount or using a discount rate, do not represent fair
market value; and
estimates in this 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.
All values in this Statement are expressed in Canadian dollars, unless specifically noted otherwise. Certain numbers in the tables in this
Statement may not add due to rounding.
1
PART 1 - DATE OF STATEMENT
Relevant Dates
Statement date: March 3, 2015
Effective date: December 31, 2014
Preparation date: March 3, 2015
2
PART 2 - DISCLOSURE OF RESERVE DATA
The following tables set forth the gross and net reserves of the Company as at December 31, 2014, 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, 2014
FORECAST PRICES AND COSTS
Light and Medium
Reserves Category
Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved Reserves
Probable Reserves
Total Proved plus Probable Reserves
Crude Oil
Gross
Net
(Mbbls) (Mbbls)
9
3
—
12
54
66
Heavy Oil
Gross
(Mbbls)
8
2
—
10
45
54
—
—
—
—
—
—
3
Natural Gas
Net
(Mbbls)
—
—
—
—
—
—
Gross
(MMcf)
474
849
—
1,323
1,705
3,028
Natural Gas Liquids
Net
(MMcf)
393
714
—
1,106
1,405
2,511
Gross
(Mbbls)
5
8
—
13
18
30
Net
(Mbbls)
4
6
—
10
14
24
SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2014
FORECAST PRICES AND COSTS
Reserves Category
Unit Value
Before Tax
Before Deducting Income Taxes Discounted After Deducting Income Taxes Discounted Discounted
at
at
at
0%
5%
10%
15%
20%
0%
5%
10%
15%
20%
10%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
$/boe
Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped
Total Proved Reserves
Probable Reserves
0.8
0.9
—
1.7
4.9
0.7
0.8
—
1.5
3.8
0.6
0.8
—
1.4
2.9
0.6
0.7
—
1.2
2.4
0.5
0.6
—
1.1
1.9
Total Proved plus Probable
Reserves
6.6
5.3
4.3
3.6
3.0
4
0.8
0.7
0.6
0.6
0.5
8.00
0.9
0.8
0.8
0.7
0.6
6.00
—
—
—
—
—
—
1.7
1.5
1.4
1.2
1.1
6.80
4.9
3.8
2.9
2.4
1.9
10.10
6.6
5.3
4.3
3.6
3.0
8.70
The following table sets forth the elements of the future net revenue attributable to the Company's proved reserves and proved plus probable reserves,
using forecast prices and costs and calculated without discount.
TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
AS OF DECEMBER 31, 2014
FORECAST PRICES AND COSTS
Reserves Category
Total Proved
Total Probable
Total Proved plus Probable
Revenue
(MM$)
Royalties
(MM$)
Abandonment
and
Operating Development Reclamation
Costs
Costs
Costs
(MM$)
(MM$)
(MM$)
Future Net
Revenue
Before
Future
Income
Tax
Expenses
(MM$)
7.58
0.92
3.71
0.88
0.33
1.73
15.07
2.12
6.33
1.63
0.10
4.89
22.64
3.05
10.04
2.51
0.42
6.62
5
Future
Income
Tax
Expenses
(MM$)
—
—
—
Future
Net
Revenue
After
Income
Taxes
(MM$)
1.73
4.89
6.62
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, 2014
FORECAST PRICES AND COSTS
Production Group
Future Net Revenue
Before Income
Unit
Unit
Taxes(3)
Value
Value
(discounted at 10%/yr)
(discounted at 10%/yr)
(discounted at 10%/yr)
(M$)
($/bbl)
($/Mcf)
Light and Medium Oil(1)
43
11.91
N/A
Heavy Oil(1)
(51)
N/A
N/A
1,389
N/A
1.27
Light and Medium Oil(1)
691
15.31
N/A
Heavy Oil(1)
(51)
N/A
N/A
3,691
N/A
1.67
Total Proved
Natural Gas(2)
Total Proved Plus Probable
Reserves
Natural Gas(2)
Notes:
(1) Gas reserves included in Light, Medium and Heavy Oil are solution gas reserves only.
(2) Unit values are calculated using the 10% discount rate divided by the Major Product Type Net Reserves for each group.
(3) Processing income is included where applicable.
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 One Earth Oil & Gas were calculated using forecasts and inflation and exchange rate assumptions
provided by McDaniel, effective January 1, 2015. Also set forth below are the Company's weighted average prices received for each product type in
2014.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
FORECAST PRICES AND COSTS
Year
U.S.
Henry Hub
Gas Price
$US/MMBtu
Alberta
AECO
Spot
Price
$C/MMBtu
Forecast
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
3.30
3.80
4.05
4.30
4.55
4.85
5.10
5.30
5.50
5.70
5.80
5.90
6.05
6.15
6.30
+2%/yr
Thereafter
Alberta
Average
Plantgate
$C/MMBtu
(1)
Alberta
Aggregator
Plantgate
$C/MMBtu
Alberta
Spot
Sales
Plantgate
$C/MMBtu
Sask.
Prov.
Gas
Plantgate
$C/MMBtu
British
Columbia
Average
Plantgate
$C/MMBtu
3.50
4.00
4.25
4.50
4.70
5.00
5.30
5.50
5.70
5.90
6.00
6.10
6.25
6.35
6.50
3.30
3.80
4.05
4.30
4.50
4.80
5.05
5.25
5.45
5.65
5.75
5.85
6.00
6.10
6.25
3.30
3.80
4.05
4.30
4.50
4.80
5.05
5.25
5.45
5.65
5.75
5.85
6.00
6.10
6.25
3.30
3.80
4.05
4.30
4.50
4.80
5.05
5.25
5.45
5.65
5.75
5.85
6.00
6.10
6.25
3.40
3.90
4.15
4.40
4.60
4.90
5.15
5.35
5.55
5.75
5.85
5.95
6.15
6.25
6.40
3.20
3.70
3.95
4.20
4.40
4.70
4.95
5.15
5.35
5.55
5.65
5.75
5.85
5.95
6.10
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
Notes:
(1) This forecast also applies to direct sales contracts and the Alberta gas reference price used in the crown royalty calculations.
7
Alberta
WTI
Brent
Edmonton
Bow
River
Western
Canadian
Alberta
Sask
Cromer
Edmonton
Cond. &
Crude
Crude
Light
Hardisty
Select
Heavy
Medium
Natural
Exchange
Oil
Oil
Crude Oil
Crude Oil
Crude Oil
Gasolines
Propane
Butanes
$US/bbl
$US/bbl
$C/bbl
$C/bbl
$C/bbl
$C/bbl
$C/bbl
$/bbl
$/bbl
$/bbl
(1)
(2)
(3)
(4)
(5)
(6)
(7)
2015
65.00
70.00
68.60
58.30
57.60
51.10
64.50
72.60
26.10
52.80
2.0
0.860
2016
75.00
77.60
83.20
70.70
69.90
62.00
78.20
87.30
36.50
67.00
2.0
0.860
2017
80.00
82.60
88.90
75.60
74.70
66.20
83.60
93.10
44.50
71.60
2.0
0.860
2018
84.90
87.60
94.60
80.40
79.50
70.50
88.90
98.80
49.30
76.20
2.0
0.860
2019
89.30
92.00
99.60
84.70
83.70
74.20
93.60
103.90
51.80
80.30
2.0
0.860
2020
93.80
96.60
104.70
89.00
87.90
78.00
98.40
109.10
54.70
84.40
2.0
0.860
2021
95.70
98.50
106.90
90.90
89.80
79.60
100.50
111.40
56.20
86.10
2.0
0.860
2022
97.60
100.50
109.00
92.70
91.60
81.20
102.50
113.60
57.50
87.80
2.0
0.860
2023
99.60
102.50
111.20
94.50
93.40
82.80
104.50
115.90
58.90
89.60
2.0
0.860
2024
101.60
104.60
113.50
96.50
95.30
84.60
106.70
118.30
60.30
91.50
2.0
0.860
2025
103.60
106.60
115.70
98.30
97.20
86.20
108.80
120.60
61.50
93.20
2.0
0.860
2026
105.70
108.80
118.00
100.30
99.10
87.90
110.90
123.00
62.70
95.10
2.0
0.860
2027
107.80
111.00
120.40
102.30
101.10
89.70
113.20
125.50
64.00
97.00
2.0
0.860
2028
110.00
113.20
122.80
104.40
103.20
91.50
115.40
128.00
65.20
99.00
2.0
0.860
2029
112.20
115.50
125.30
106.50
105.30
93.30
117.80
130.60
66.60
101.00
2.0
0.860
Thereafter
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
+2%/yr
2.0
0.860
Year
Crude Oil Crude Oil
US/CAN
Edmonton Edmonton
Inflation
%
Rate
$US/$CAN
Forecast
Notes:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
West Texas Intermediate at Cushing Oklahoma 40 degrees API/0.5% sulphur
North Sea Brent blend 37 degrees API/1.0% sulphur
Edmonton Light Sweet 40 degrees API, 0.3% sulphur
Bow River at Hardisty Alberta (Heavy stream)
Western Canadian Select at Hardisty, Alberta
Heavy crude oil 12 degrees API at Hardisty, Alberta (after deduction of blending costs to reach pipeline quality)
Midale Cromer crude oil 29 degrees API, 2.0% sulphur
8
SUMMARY OF THE COMPANY'S 2014 WEIGHTED AVERAGE PRICES
Light & Medium Oil ($/bbl)
One Earth Oil & Gas
Heavy Oil ($/bbl)
84.26
59.92
9
Natural Gas ($/Mcf)
5.24
NGL ($/bbl)
62.96
PART 4 - RECONCILIATION OF CHANGES IN RESERVES
The following table reconciles the Company's oil and natural gas reserves (on a gross reserves basis) from December 31, 2013 to December 31, 2014
using forecast prices and costs.
RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
BASED ON FORECAST PRICES AND COSTS
Light and Medium Oil
December 31, 2013
Associated and Non-Associated
Gas
Natural Gas Liquids
Proved
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)
27
43
70
21
8
29
18
20
38
1,538
1,504
3,042
—
—
—
—
—
—
—
—
—
Discoveries
Extensions and Improved
Recovery
Heavy Oil
—
—
—
—
—
—
—
3
1
5
298
121
419
(11)
12
1
—
—
—
(6)
(4)
(10)
(223)
29
(194)
Acquisitions
—
—
—
—
—
—
—
—
—
—
50
50
Dispositions
—
—
—
—
—
—
—
—
—
—
—
—
Economic Factors
—
—
—
(17)
(8)
(25)
—
—
—
—
—
—
4
4
—
4
2
66
—
—
—
13
Technical Revisions
Production
At December 31, 2014
—
4
12
54
10
—
18
2
289
30
1,323
—
1,705
289
3,028
PART 5 - ADDITIONAL INFORMATION RELATING TO RESERVES DATA
Undeveloped Reserves
Undeveloped Reserves were attributed by McDaniel 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
Proved Undeveloped Reserves and Year First Attributed
Year
Prior
2012
2013
2014
Light and Medium Oil
(Mbbl)
First
Cumulative at
Attributed
Year End
—
—
—
—
—
—
—
—
Heavy Oil
(Mbbl)
First
Cumulative
Attributed at Year End
—
—
—
—
—
—
—
—
Natural Gas
(MMcf)
First
Cumulative
Attributed
at Year End
—
—
—
—
—
—
—
—
NGLs
(Mbbl)
First
Cumulative
Attributed
at Year End
—
—
—
—
—
—
—
—
Probable Undeveloped Reserves and Year First Attributed
Year
Prior
2012
2013
2014
Light and Medium Oil
(Mbbl)
First
Cumulative at
Attributed
Year End
57
58
—
31
—
30
—
30
Heavy Oil
(Mbbl)
First
Cumulative
Attributed at Year End
—
—
—
—
—
—
—
—
Natural Gas
(MMcf)
First
Cumulative
Attributed
at Year End
2,304
2,554
—
527
—
284
—
284
NGLs
(Mbbl)
First
Cumulative
Attributed
at Year End
23
26
—
7
—
4
—
3
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, One Earth Oil &
Gas 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, especially heavy oil reserves, can be affected significantly by fluctuations
in product pricing that are beyond the Company's control.
11
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 One Earth Oil & Gas 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.
2015
2016
2017
2018
2019
Remainder
Total for all
years
undiscounted
Total for all
years
discounted at
10% per year
Proved
M$
12
883
—
—
—
—
—
Proved
Plus Probable
M$
2,454
—
—
—
—
60
883
2,513
861
2,361
Oil and Gas Properties and Wells
OEOG has interests in properties in three areas, all of which are located in Alberta: (i) Gift Lake; (ii) Wetaskiwin; and (iii) Campbell.
OEOG’s main focus in 2014 was evaluation of the Gift Lake heavy oil area utilizing stratigraphic core holes and seismic evaluation. Development
drilling for production based on this evaluation was deferred in 2014 due to rapidly changing oil prices.
In the conventional producing area, potential gas tie-ins in Wetaskiwin were evaluated and one to three gas wells will be tied in for production in 2015.
At Campbell, the producing well was shut-in as a result of a plant shut-down by the area gas plant operator. Alternative tie-ins for Campbell are being
pursued for 2015.
Production from the Wetaskiwin, Campbell and Gift Lake areas averaged 156 boe/d in 2014.
On January 1, 2015, OEOG acquired 65% of the heavy oil reserves and production in a Pekisko heavy oil play (the "Pekisko Play") adjacent to OEOG's
existing land interests at Gift Lake. The remaining 35% of the Pekisko Play was acquired by an industry partner with operational experience in the area
and Gift Energy Limited ("Gift Energy").
Oil and Gas Wells
The following table sets forth the number of producing and non-producing wells of One Earth Oil & Gas at December 31, 2014.
Producing Wells
One Earth Oil & Gas
Alberta
Total
Gross
Oil
2.0
2.0
Net
Gas
Gross
2.0
2.0
3.0
3.0
Net
Gross
2.1
2.1
Oil
2.0
2.0
Non-Producing Wells
Gas
Net
Gross
2.0
2.0
6.0
6.0
Net
4.3
4.3
Properties with No Attributed Reserves
The Gift Lake property consists of over 28,480 gross acres (14,240 net). As at December 31, 2014, reserves for the one Gift Lake producing well was
revised to nil by McDaniel based on economic factors. Development drilling is planned for this property once oil prices recover. Pursuant to the joint
venture agreement with Gift Energy, if the WTI price for oil exceeds US$65 for one month in 2015, OEOG must drill one well within 90 days of that
month.
OEOG has undeveloped land holdings in its conventional operations in Alberta, consisting of 2,271 gross acres (1,570 net) with no attributed reserves
as at December 31, 2014.
OEOG has no significant land that expires by January 1, 2016.
Forward Contracts
Neither the Company nor OEOG 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.
13
Abandonment and Reclamation Costs
OEOG 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. All fifteen gross wells (11.65 net) evaluated by McDaniels included abandonment and reclamation costs.
McDaniel estimates that OEOG's total abandonment and reclamation costs will be $420,000 undiscounted and $175,000 discounted at 10%. Of the
total undiscounted abandonment and reclamation costs, 100% was included in estimating future net revenue (total proved plus probable). One Earth
Oil & Gas does not expect to pay any such costs in the next three financial years.
One Earth Oil & Gas
2015
2016
2017
Total Total Proved
Proved Plus Probable
M$
M$
—
—
49
31
32
32
2018
2019
Remainder
Total for all
years
undiscounted
Total for all
years discounted
at 10% per year
22
—
—
22
222
335
325
420
175
175
Tax Horizon
The Company’s oil and gas activities are conducted through OEOG and will be taxed within OEOG. Depending on production, commodity prices
and capital spending levels, the Company does not expect One Earth Oil & Gas to pay income taxes in the foreseeable future.
Costs Incurred
The following table sets forth the costs incurred by One Earth Oil & Gas in 2014:
$
Costs (Canada)
Proved Property Acquisitions (including facilities )
Unproved Property Acquisitions
Exploration
Development
Total
14
—
—
7,559,519
4,821,117
12,380,636
Exploration and Development Activities for 2014
The following table sets forth the number and type of development and exploratory wells completed by One Earth Oil & Gas in 2014.
Oil Wells
Gas Wells
Service Wells and Stratigraphic Test Wells
Dry Holes
Total Completed Wells
Development Wells
Gross
Net
—
—
—
—
—
—
—
—
—
—
Exploratory Wells
Gross
Net
—
—
—
—
7
7
—
—
7
7
For a description of the Company's most important and likely exploration and development activities, see "Oil and Gas Properties and Wells" above.
15
Production Estimates
The following table summarizes the estimated 2015 average daily production reflected in the estimates of gross proved reserves and gross proved plus
probable reserves disclosed under Part 2 of this Statement. These estimates were provided by McDaniel.
Light/Medium
Oil
(bbls/d)
9
Gross Proved Reserves(1)
Gross Proved plus Probable
Reserves(2)
—
Natural Gas
Liquids
(bbls/d)
11
—
13
Heavy Oil
(bbls/d)
26
Natural
Gas
(Mcf/d)
996
Total
Production
(boe/d)
186
1,245
246
Notes:
(1) The estimated 2015 average daily production volume for Wetaskiwin is 181 boe/d, which represents more than 20 percent of the disclosed estimated
production.
(2) The estimated 2015 average daily production volume for Wetaskiwin is 231 boe/d, which represents more than 20 percent of the disclosed estimated
production.
16
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, 2014 and the
netbacks received:
Quarter Ended
Quarter Ended
Quarter Ended
Quarter Ended
March 31, 2014
June 30, 2014
September 30, 2014
December 31, 2014
Average Daily Production
Natural Gas (Mcf/d)
1,298
977
630
199
Natural Gas Liquids (bbls/d)
5
7
5
4
Light & Medium Oil (bbls/d)
11
14
10
9
Heavy Oil (bbls/d)
10
7
14
11
Combined (boe/d)
243
191
134
56
Natural Gas Netbacks ($/Mcf)
Revenue
$
5.71
$
5.47
$
4.35
$
3.92
Royalties
$
0.73
$
0.77
$
0.59
$
0.45
Production Costs
$
1.91
$
2.20
$
2.96
$
4.07
Netback
$
3.07
$
2.50
$
0.81
$
0.60
Revenue
$
82.57
$
95.39
$
86.52
$
66.45
Royalties
$
14.79
$
6.94
$
12.76
$
22.42
Production Costs
$
19.81
$
13.18
$
15.91
$
12.12
Netback
$
47.98
$
75.27
$
57.85
$
31.91
Revenue
$
63.08
$
72.11
$
64.78
$
42.43
Royalties
$
7.72
$
7.50
$
7.40
$
6.60
Production Costs
$
70.86
$
66.48
$
56.47
$
49.51
Netback
$
(15.50)
$
(1.88)
$
0.91
$
(13.67)
Revenue
$
75.62
$
63.07
$
59.81
$
50.22
Royalties
$
18.20
$
15.85
$
15.78
$
14.54
Production Costs
$
15.51
$
12.34
$
10.02
$
11.49
Netback
$
41.92
$
34.89
$
34.01
$
24.20
Light & Medium Oil Netbacks ($/bbl)
Heavy Oil Netbacks ($/bbl)
Natural Gas Liquids Netbacks ($/bbl)
17
Production by Important Field
The following table sets forth the average daily production in 2014, by product type, for One Earth Oil & Gas' important fields:
Heavy Oil
bbls/d
Light and Medium
Crude Oil
bbls/d
Natural Gas
Mcf/d
NGL
bbls/d
Total
boe/d
Wetaskiwin
Gift Lake
Other
—
11
—
8
—
3
526
—
247
5
—
—
101
11
44
Company Total
11
11
773
5
156
18
APPENDIX "B"
Report on Reserves by McDaniel & Associates Consultants Ltd.
(Form 51-101F2)
[SEE NEXT PAGE]
March 3, 2015
Sprott Resource Corp.
Suite 2750, Royal Bank Plaza, South Tower
200 Bay Street, P.O. Box 90
Toronto, Ontario
M5J 2J2
Attention:
Re:
The Board of Directors of Sprott Resource Corp.
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, 2014. The reserves
data are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2014 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, 2014, 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
APPENDIX "C"
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, 2014, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated the Company's reserves data. The report of the independent qualified reserves evaluator
is presented in Appendix A 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 Form 51-101F2 which is the report 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) Stephen Yuzpe
Stephen Yuzpe
President and Chief Executive Officer
(signed) Terrence Lyons
Terrence Lyons
Chairman
(signed) Michael Staresinic
Michael Staresinic
Chief Financial Officer
(signed) Lenard Boggio
Lenard Boggio
Director
March 3, 2015
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APPENDIX "D"
Audit Committee Charter
[SEE NEXT PAGE]
SPROTT RESOURCE CORP.
AUDIT COMMITTEE CHARTER
(Adopted by the Board on December 19, 2008, as amended on March 19, 2014 and March 3, 2015)
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)
II.
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; and
performing the additional duties set out in this Charter or otherwise delegated to the Committee by the Board.
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.
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
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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
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:
(b)
(i)
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;
(ii)
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;
(iii)
discussing with management and the Company's auditor the quality of generally accepted accounting principles
("GAAP"), not just acceptability of GAAP;
(iv)
discussing with management any significant variances between comparative reporting periods; and
(v)
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.
Auditor
The Committee is responsible for recommending to the Board:
(i)
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
(ii)
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 effectiveness of the auditor's relationship with management and the Committee;
(ii)
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;
(iii)
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;
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(d)
(iv)
meeting in camera with the auditor whenever the Committee deems it appropriate;
(v)
annually, or more frequently as necessary, completing an assessment of the performance of the Company’s auditor;
and
(vi)
every four years, or more frequently as necessary, completing a comprehensive review of the performance of the
Company’s auditor.
Accounting Policies
The Committee is responsible for:
(e)
(i)
reviewing the Company's accounting policy note to ensure completeness and acceptability with GAAP as part of the
approval of the financial statements;
(ii)
discussing and reviewing the impact of proposed changes in accounting standards or securities policies or regulations;
(iii)
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;
(iv)
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.
Risk and Uncertainty
The Committee is responsible for reviewing, as part of its approval of the financial statements:
(i)
uncertainty notes and disclosures; and
(ii)
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.
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)
the plan and scope of the annual audit with respect to planned reliance and testing of controls; and
(ii)
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)
tax and financial reporting laws and regulations;
(ii)
legal withholdings requirements;
(iii)
environmental protection laws; and
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(iv)
VIII.
other matters for which directors face liability exposure.
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:
X.
(a)
the receipt, retention and treatment of complaints received by the Company regarding accounting, internal accounting controls,
or auditing matters; and
(b)
the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or
auditing matters.
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.
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