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Message: SABRETOOTH ENERGY LTD. Fiscal year 2008
SABRETOOTH ENERGY LTD.
Annual Information Form
Fiscal Year Ended December 31, 2008
Dated March 20, 2009
- i - TABLE OF CONTENTS
GLOSSARY...............................
ABBREVIATIONS..........................
CONVERSIONS .......................................
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS.............................
THE CORPORATION............................
Incorporation..........................
Address .......................................
Intercorporate Relationships .......................................
General Development of the Business .......................................
Other Recent Developments .......................................
Significant Acquisitions...........................
BUSINESS OF SABRETOOTH.............................
General................................
Business Strategy...............................
RESERVES DATA AND OTHER OIL AND GAS INFORMATION .......................................
Disclosure of Reserves Data .......................................
Reserves Reconciliation.........................
Additional Oil & Gas Information .......................................
Other Oil and Gas Information .......................................
INDUSTRY CONDITIONS.............................
RISK FACTORS................................
DESCRIPTION OF SHARE CAPITAL .......................................
DIVIDENDS .......................................
MARKET FOR SECURITIES.............................
DIRECTORS AND OFFICERS...............................
AUDIT COMMITTEE INFORMATION .......................................
LEGAL PROCEEDINGS AND REGULATORY ACTIONS................................
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...........................
TRANSFER AGENT AND REGISTRAR..............................
MATERIAL CONTRACTS..............................
INTERESTS OF EXPERTS................................
ADDITIONAL INFORMATION .......................................
ADDENDA
APPENDIX A:
Report of Management and Directors on Oil and Gas Disclosure
Report on Reserves Data by Independent qualified Reserves Evaluator or Auditor
APPENDIX B:
Audit Committee Terms of Reference
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GLOSSARY
Terms not otherwise defined herein have the meaning set forth below.
"1175043" means 1175043 Alberta Ltd.;
"ABCA" means the Business Corporations Act (Alberta);
"AEUB" means the Alberta Energy and Utilities Board.
"Annual Information Form" means this annual information form;
"Annual Financial Statements" means the Corporation’s audited consolidated financial statements for the years
ended December 31, 2008 and 2007;
"Bear Ridge" means Bear Ridge Resources Inc.;
"Board" means the board of directors of the Corporation.
"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of
Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum
(Petroleum Society).
"Common Shares" means common voting shares in the capital of the Corporation;
"Escrow Agreement" means the value securities escrow agreement dated December 24, 2008 between the
Corporation, HFG and Olympia Trust Company;
"GLJ HFG Report" means the engineering evaluation of the oil and natural gas interests of HFG prepared by GLJ
dated February 6, 2009 and effective December 31, 2008;
"GLJ Sabretooth Report" means the independent engineering evaluation of the oil and natural gas interests of the
Corporation prepared by GLJ dated March 5, 2009 and effective December 31, 2008
"GLJ Reports" means collectively the GLJ Sabretooth Report and the GLJ HFG Report;
"Gross" means in relation to:
(a) the Corporation’s interest in production and reserves, its "Corporation gross reserves", which are
the Corporation’s interest (operating and non-operating) share before deduction of royalties and
without including any royalty interest of the Corporation;
(b) wells, the total number of wells in which the Corporation has an interest; and
(c) properties, the total area of properties in which the Corporation has an interest’
"HFG" means HFG Holdings Inc.;
"Net" means in relation to:
(a) the Corporation’s interest in production and reserves, the Corporation’s interest (operating and
non-operating) share after deduction of royalties obligations, plus the Corporation’s royalty
interest in production or reserves;
(b) wells, the number of wells obtained by aggregating the Corporation’s working interest in each of
its gross wells; and
(c) the Corporation’s interest in a property, the total area in which the Corporation has an interest
multiplied by the working interest owned by the Corporation;
"NI 51-101" means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
"NI 52-110" means National Instrument 52-110 Audit Committees.
"Non-Voting Shares" means non-voting shares in the capital of the Corporation;
"Registration Rights Agreement" means the registration rights agreement between the Corporation and HFG dated
December 24, 2008;
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"SEC" means Stratagem Energy Corporation;
"Sabretooth" or the "Corporation" means Sabretooth Energy Ltd.;
"Services Agreement" means the management services agreement dated December 24, 2008 between the
Corporation and HFG;
"TSX" means the Toronto Stock Exchange;
"TSXV" means the TSX Venture Exchange; and
"Working Interest" means when used to describe Sabretooth’s share of production, the total of Sabretooth’s
working interest share of production before deducting royalties owned by others.
Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise
requires, shall have the same meanings herein as in NI 51-101.
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ABBREVIATIONS
API American Petroleum Institute M$ thousands of dollars
Bbls barrels Mbbl thousand barrels
Bbls/d barrels of oil per day Mboe thousand barrels of oil equivalent
Bcf billion cubic feet Mcf thousand cubic feet
Boe barrel of oil equivalent Mmcf million cubic feet
Boe/d barrels of oil equivalent per day Mmcf/d million cubic feet per day
GJ gigajoule NGLs natural gas liquids
GJ/d gigajoule per day Stb stock tank barrel
Boes are presented on the basis of one Boe for six Mcf of natural gas. Disclosure provided herein in respect of Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. CONVERSIONS
The following table sets forth certain standard conversions from Standard Imperial units to the International System
of Units (or metric units).
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 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
GJ Mcf 1.055
All dollar amounts herein are expressed in Canadian dollars unless otherwise indicated.
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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
This Annual Information Form contains forward-looking statements. These statements relate to future events or
future performance of Sabretooth. When used in this Annual Information Form, the words "may", "would",
"could", "will", "intend", "plan", "anticipate", "believe", "estimate", "predict", "seek", "propose", "expect",
"potential", "continue", and similar expressions, are intended to identify forward-looking statements. These
statements involve known and unknown risks, uncertainties, and other factors that may cause actual results or events
to differ materially from those anticipated in such forward-looking statements. Such statements reflect the
Corporation’s current views with respect to certain events, and are subject to certain risks, uncertainties and
assumptions. Many factors could cause the Corporation’s actual results, performance, or achievements to vary from
those described in this Annual Information Form. Should one or more of these risks or uncertainties materialize, or
should assumptions underlying forward-looking statements prove incorrect, actual results may differ materially from
those described in this Annual Information Form as intended, planned, anticipated, believed, estimated, or expected.
Specific forward-looking statements in this Annual Information Form include, among others, statements pertaining
to the following:
• • • • •
factors upon which Sabretooth will decide whether or not to undertake a specific course of action;
world-wide supply and demand for petroleum products;
expectations regarding Sabretooth’s ability to raise capital;
treatment under governmental regulatory regimes; and
commodity prices.
With respect to forward-looking statements in this Annual Information Form, Sabretooth has made assumptions,
regarding, among other things:
• • • •
the impact of the ongoing world credit crisis and recession
the impact of increasing competition;
Sabretooth’s ability to obtain additional financing on satisfactory terms; and
Sabretooth’s ability to attract and retain qualified personnel.
Sabretooth’s actual results could differ materially from those anticipated in these forward-looking statements as a
result of the risk factors set forth below and elsewhere in this Annual Information Form including, without
limitation, the following:
• • • • • • •
general economic conditions, including the impact of the ongoing world credit crisis and recession;
volatility in global market prices for oil and natural gas;
competition;
liabilities and risks, including environmental liability and risks, inherent in oil and gas operations;
the availability of capital;
alternatives to and changing demand for petroleum products;
changes in legislation and the regulatory environment, including uncertainties with respect to the Kyoto
Protocol; and
•
the other factors considered under "Risk Factors" herein.
Furthermore, statements relating to "reserves" are deemed to be forward-looking statements, as they involve the
implied assessment, based on certain estimates and assumptions, that reserves described can be recovered and
profitable in the future.
Financial outlook information contained in this Annual Information Form about prospective results of operations,
financial position or cash flows is based on assumptions about future events, including economic conditions and
proposed courses of action, based on management’s assessment of the relevant information currently available.
Readers are cautioned that such financial outlook information contained in this Annual Information Form should not
be used for purposes other than for which it is disclosed herein.
The forward–looking statements contained in this Annual Information Form are expressly qualified in their entirety
by this cautionary statement. These statements speak only as of the date of this Annual Information Form. The
Corporation does not intend and does not assume any obligation, to update these forward-looking statements to
reflect new information, subsequent events or otherwise, expect as required by law.
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THE CORPORATION Incorporation
Sabretooth Energy Ltd. was incorporated as Metrophotonics Inc. pursuant to the Business Corporations Act
(Ontario) on April 4, 2000.
On January 31, 2005, the Corporation’s articles were amended to add an unlimited number of Non-Voting Shares to
the authorized capital, to consolidate the Corporation’s Common Shares on a 100 for one basis and to reduce the
stated capital of the Common Shares. On February 4, 2005, the Corporation’s name was changed from
"Metrophotonics Inc." to "1395177 Ontario Inc." On September 29, 2005, the Corporation was continued under the
laws of Alberta and changed its name to "Sabretooth Energy Ltd."
On February 15, 2006, SEC was amalgamated with Sabretooth and the amalgamated corporation continued under
the name "Sabretooth Energy Ltd." Sabretooth changed its fiscal year end from June 30 to December 31 effective
with its December 31, 2005 year end.
On July 18, 2007, the Corporation amended its articles in order to convert all the issued and outstanding Non-Voting
Shares into Common Shares and to immediately thereafter consolidate the Common Shares on a four for one basis.
On January 1, 2008, Sabretooth amalgamated with its wholly-owned subsidiary, Sabretooth Resources Inc.
(formerly Bear Ridge Resources Inc.) and the amalgamated corporation continued under the name "Sabretooth
Energy Ltd."
Address
The head office of Sabretooth is located at 702, 2303 – 4th Street S.W. Calgary, Alberta, T2S 2S7 and the registered
office of Sabretooth is located at 4300, 888 – 3rd Street S.W., Calgary, Alberta, T2P 5C5.
Intercorporate Relationships
Sabretooth has two subsidiaries: 1175043 and HFG.
1175403 was incorporated pursuant to the provisions of the ABCA on June 7, 2005 and does not carry on any
business. 117403 is wholly-owned by Sabretooth.
HFG was incorporated pursuant to the provisions of the ABCA on March 2, 2007 and carries on operations as an oil
and gas exploration and production company. Sabretooth acquired approximately 71% of HFG on December 24,
2008. All HFG common shares acquired by Sabretooth have been placed in escrow in accordance with the terms of
the Escrow Agreement pursuant to the policies of the TSXV. HFG’s common shares are listed on the TSXV under
the symbol "hfg".
Pursuant to the Services Agreement, Sabretooth is responsible for managing the day to day affairs of HFG and,
among other things, is obligated to make the services of its chief executive officer and chief financial officer
available to HFG. The fees payable by HFG to Sabretooth under the Services Agreement may not exceed an
aggregate of $150,000 until such time as HFG enjoys positive cash flow. The Services Agreement may be
terminated after one year by either party upon giving 60 days prior written notice. Additionally, either Sabretooth or
HFG may terminate the Services Agreement upon ten days written notice in the event that HFG undergoes a change
of control.
Sabretooth and HFG have also entered into the Registration Rights Agreement, which grants Sabretooth the right to
participate in future offerings by HFG of common shares (or securities convertible into common shares) on a pro
rata basis for so long as Sabretooth owns 20% or more of the outstanding common shares of HFG. The Registration
Rights Agreement also requires HFG to prepare a prospectus and to provide certain other assistance in certain
circumstances in the event Sabretooth wishes to dispose of some or all of its HFG common shares.
General Development of the Business
Prior to February 4, 2005, Sabretooth (then known as Metrophotonics Inc.) carried on the business of designing,
developing and marketing monolithic protonic integrated circuits for use primarily in telecom systems and
sub-systems. In connection with approvals of the shareholders of the Corporation in January 2005: (i) the
Corporation’s articles were amended to add an unlimited number of Non-Voting Shares to the authorized capital; (ii)
the Corporation’s articles were amended to consolidate the Common Shares on a 100 for one basis; (iii) the stated
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capital of the Common Shares was reduced; (iv) an aggregate of 556,050 Common Shares and a $2,728,500
principal amount convertible debenture were issued to Matco Investments Ltd. for an aggregate subscription amount
of $3,015,000; (v) the subscription proceeds and substantially all of the other assets of Sabretooth were contributed
to a new corporation in return for the issuance to Sabretooth of shares of that corporation and the assumption by that
corporation of liabilities of Sabretooth associated with the transferred assets; (vi) the shares of that other corporation
were distributed to the shareholders of Sabretooth; and (vii) the Corporation’s name was changed from
"Metrophotonics Inc." to "1395177 Ontario Inc.".
In connection with an agreement entered into between Sabretooth and 1175043 in June 2005: (i) Matco Investments
Ltd. converted the $2,728,500 principal amount convertible debenture into an aggregate of 5,295,650 Non-Voting
Shares; (ii) Sabretooth acquired all of the issued and outstanding shares of 1175043 in consideration of the issue of
556,050 Common Shares and 10,788,309 Non-Voting Shares; and (iii) the Board was changed to be comprised of
two persons, Marshall Abbott and Hank Swartout. At the time of its acquisition, 1175043’s assets consisted of
approximately $5,800,000 in cash and two farm-in agreements relating to petroleum and natural gas leases in the
Pouce Coupe area of Alberta and no liabilities.
On October 27, 2005, Sabretooth purchased SEC, a private oil and gas company, for aggregate consideration of
1,753,000 Common Shares and 50,646,000 Non-Voting Shares, 9,100,000 Non-Voting Share purchase options and
$675,000 in cash. The Non-Voting Share purchase options issued in connection with the acquisition of SEC were
never exercised and expired in accordance with their terms on August 22, 2007.
On December 27, 2005, Sabretooth issued 1,148,152 Common Shares on a flow-through basis to management and
directors at a price of $2.75 per share for gross proceeds of $3,157,418.
In June 2006, Sabretooth issued 3,589,286 Common Shares and 3,589,286 Non-Voting Shares at a price of $1.40
per share for gross proceeds of $10.05 million. The proceeds were invested in 1243533 Alberta Ltd., a
wholly-owned subsidiary of Sabretooth. On June 30, 2006, 1243533 Alberta Ltd. purchased 545,142 Common
Shares and 14,166,941 Non-Voting Shares at a price of $1.30 per share, or $19,125,708 in aggregate, pursuant to an
offer made to all of Sabretooth’s shareholders. Such offer fulfilled an obligation to provide a liquidity event to
shareholders, which Sabretooth incurred in connection with the acquisition of SEC. 1243533 Alberta Ltd. was
wound up in November 2006 and the 14,712,083 Common Shares and Non-Voting Shares then held by 1243533
Alberta Ltd. were cancelled.
On November 9, 2006, Sabretooth issued 8,000,000 Common Shares on a flow-through basis at a price of $2.00 per
share for gross proceeds of $16,000,000.
On August 21, 2007, Sabretooth acquired 100% of the issued and outstanding common shares of Bear Ridge for
aggregate consideration of 18.6 million Common Shares and $57.25 million by way of plan of arrangement.
On December 24, 2008, Sabretooth sold 59 net sections of Montney petroleum and natural gas rights, and certain
wells and seismic access and interpretations to HFG in exchange for 156,546,590 common shares of HFG at a
deemed price of $0.20 per share. Sabretooth also assumed a $1.0 million tie-in commitment and purchased
5,000,000 common shares of HFG for cash at a price of $0.20 per share. As a result of these transactions,
Sabretooth acquired approximately 71% of the outstanding common shares of HFG. Sabretooth also entered into
the Escrow Agreement, Registration Rights Agreement and Services Agreement in connection with this transaction.
As at December 31, 2008 the Corporation employed 18 full time head office staff and 1 permanent field operations
staff.
Other Recent Developments
On October 25, 2007, the Alberta government released the New Royalty Framework ("NRF") pertaining to royalties
on oil and gas resources including oil sands, conventional oil and gas and coalbed methane. The NRF is scheduled to
take effect on January 1, 2009. The NRF was the Alberta government's response to the recommendations put forth
by the Alberta Royalty Review Panel. Given the methodology used in the proposed royalty regime, the effect on
Sabretooth’s cash flow will be affected by depths and productivity of wells. The actual effect of the Alberta royalty
rate changes on Sabretooth will be determined based on, among other things, the actual legislation enacted, the
production rates, commodity prices, foreign exchange rates, production mix, service costs and the percentage of
production from Alberta after January 1, 2009.
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On March 3, 2009 The Alberta Government released a three-point incentive program aimed at stimulating new and
continued economic activity for conventional producers. The highlights of the province’s three-point plan include
the following:
• A drilling royalty credit for new, conventional, oil and natural gas wells drilled between April 1, 2009 and
March 31, 2010. This one-year program will provide a $200-per-metre-drilled royalty credit to companies
on a sliding scale based on their production levels from the prior year. Based on last year’s production,
Sabretooth will qualify for the maximum credit under this plan.
• A new well incentive program, which offers a maximum five-per-cent royalty rate for the first year of
production from new oil or gas wells. This program also commences on April 1, 2009 and runs for one
year.
• To encourage the clean-up of inactive oil and gas wells, the province will invest $30 million in a fund
committed to abandoning and reclaiming old well sites.
Sabretooth anticipates that the NRF (including the new initiative announced on March 3, 2009), in combination with
low natural gas prices, will have a positive impact on Sabretooth’s Crown royalty rates for 2009.
Significant Acquisitions
Sabretooth did not complete any significant acquisitions during the year ended December 31, 2008 for which
disclosure is required under Part 8 of National Instrument 51-102 Continuous Disclosure Obligations.
BUSINESS OF SABRETOOTH General
Sabretooth is engaged in the acquisition, exploration, development and production of petroleum and natural gas
reserves on Western Canada.
Business Strategy
Sabretooth’s business strategy is to increase production, cash flow and shareholder value in a cost-effective manner
by focused drilling, accretive acquisitions and operational efficiency. We manage risk by following our investment
guidelines, namely:
•
Drill for low-decline, long-life, unconventional gas in the Montney Formation through Sabretooth’s 71%
equity interest in HFG.
• • •
Drill for selected conventional targets at medium to shallow depths for multiple prospective horizons.
Invest in areas with year-round access and existing infrastructure.
Focus on our British Columbia and Alberta assets to take advantage of favourable royalty regimes and
holidays.
•
Capitalize on our extensive in-house technical expertise to generate drilling opportunities and take
advantage of property and corporate acquisitions that add value to shareholders.
•
Use our existing infrastructure and extensive seismic data base as a potential profit centre and as leverage
to enhance our position in our core areas.
• RESERVES DATA AND OTHER OIL AND GAS INFORMATION
Use financial expertise to raise capital in the most efficient way in a tight market.
The following tables set forth certain information relating to the oil, natural gas and natural gas liquids reserves of
Sabretooth and the net present value of future net revenue associated with such reserves as at December 31, 2008.
All such reserves were evaluated by GLJ in the GLJ Reports. Pursuant to NI 51-101, the Corporation is required to
include 100% of the reserves owned by HFG in the Corporation's oil and gas reserves disclosure. The information
set forth below is derived from the GLJ Reports, which have been prepared in accordance with the standards
contained in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook.
The tables summarize the data contained in the GLJ Reports and, as a result, may contain slightly different numbers
than the GLJ Reports due to rounding. Reserve amounts are stated before deduction of royalties as evaluated in the
GLJ Reports. All evaluations of future net cash flows are stated prior to provision for indirect costs and after
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deduction of royalties, estimated future capital expenditures and well abandonment and disconnect costs. It should
not be assumed that the present values of estimated future net cash flows shown below are representative of the fair
market value of the reserves. There is no assurance that such price and cost assumptions will be attained and
variances could be material. The recovery and reserve estimates of reserves provided herein are estimates only and
there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than
the estimates provided herein. The Report of Management and Directors on Oil and Gas Disclosure and the Report
on Reserves Data by Independent Qualified Reserves Evaluator can be found in Appendix A attached hereto.
Disclosure of Reserves Data SUMMARY OF OIL AND GAS RESERVES BASED ON FORECAST PRICES AND COSTS AS OF DECEMBER 31, 2008
Remaining Reserves
Light and Medium Oil Natural Gas NGLs Total
Gross Net Gross Net Gross Net Cross Net
Reserve Category
PROVED
Developed Producing 345 299 14,068 12,235 135 101 2825 2,439
Developed Non-Producing 72 52 4,922 4,081 67 50 960 782
Undeveloped 32 27 5,407 4,602 48 34 981 827
TOTAL PROVED 449 378 24,397 20,918 251 184 4,766 4,048
PROBABLE 195 165 13,955 11,264 168 115 2,684 2,158
TOTAL PROVED PLUS
PROBABLE
643 543 38,353 32,181 419 299 7,455 6,206
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SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE BASED ON FORECAST PRICES AND COSTS AS OF DECEMBER 31, 2008 Before Taxes
Discounted at 0% at 5% at 10% at 15% at 20%
M$ M$ M$ M$ M$
PROVED
Developed producing 88,491 68,169 56,024 47,993 42,283
Developed Non-Producing 29,063 20,732 15,807 12,593 10,349
Undeveloped 19,675 10,835 6,541 4,098 2,558
TOTAL PROVED 137,229 99,736 78,371 64,684 55,190
PROBABLE 96,167 56,492 39,160 29,619 23,579
TOTAL PROVED PLUS PROBABLE 233,396 156,229 117,532 94,304 78,769
After Taxes
Discounted at 0% at 5% at 10% at 15% at 20%
M$ M$ M$ M$ M$
PROVED
Developed producing 88,491 68,169 56,024 47,993 42,283
Developed Non-Producing 29,063 20,732 15,807 12,593 10,349
Undeveloped 18,957 10,669 6,500 4,087 2,555
TOTAL PROVED 136,511 99,570 78,330 64,672 55,187
PROBABLE 68,742 44,513 32,868 25,967 21,322
TOTAL PROVED PLUS PROBABLE 205,253 144,083 111,198 90,639 76,508
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SUMMARY OF FUTURE NET REVENUE BASED ON FORECAST PRICES AND COSTS AS OF DECEMBER 31, 2008 Future Net Revenue (undiscounted) (M$)
Proved
Reserves
Proved Plus
Probable
Reserves
(Undiscounted) (Undiscounted)
Revenue 294,567 481,249
Royalties 37,802 67,060
Operating Costs 101,175 155,260
Development Costs 16,168 22,798
Abandonment Costs 2,192 2,736
Future net revenue before income taxes 137,229 233,396
Income taxes 718 28,143
Future net revenue after income taxes 136,511 205,253
SUMMARY OF FUTURE NET REVENUE BY PRODUCT BASED ON FORECAST PRICES AND COSTS AS OF DECEMBER 31, 2008 Future Net Revenue (before tax) discounted at 10%
Proved
Reserves
(M$)
Proved Plus
Probable
Reserves
(M$)
Proved
Reserves
Unit Value
($/Mcfe)
Proved Plus
Probable
Reverves
Unit Value
($/Mcfe)
Light and medium oil (including solution gas and other by-products) 7,635 10,263 4.61 4.05
Natural gas (including by-products but excluding solution gas and byproducts
from oil wells) 70,736 107,269 3.13 3.11
Total 78,371 117,532 3.17 3.17
Notes to reserves data tables:
(1) Pursuant to NI 51-101, the following definitions are employed in the determination of the reserves:
Reserve Categories
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known
accumulations, from a given date forward, based on
• • •
analysis of drilling, geological, geophysical and engineering data;
the use of established technology; and
specified economic conditions.
Reserves are classified according to the degree of certainty associated with the estimates.
Proved reserves
quantities recovered will exceed the estimated proved reserves. There is at least a 90 percent probability that the quantities actually
recovered will equal or exceed the estimated proved reserves.
Developed reserves
installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
The developed category may be subdivided into producing and non-producing:
Developed producing reserves
These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of
production must be known with reasonable certainty.
Developed non-producing reserves
but are shut-in, and the date of resumption of production is unknown.
Undeveloped reserves
when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements
of the reserves classification (proved, probable, possible) to which they are assigned.
Probable reserves
remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. There is at least a
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50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable
reserves.
Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the
lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual
entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set
of economic conditions:
(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
and
(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved
plus probable reserves.
A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide
a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using
deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be
no difference between estimates prepared using probabilistic or deterministic methods.
Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE
Handbook.
(2) Values may not add exactly due to rounding.
(3) In the economic analysis, abandonment costs for the wells net of salvage value have been included in the individual property
evaluations.
(4) The extent and character of ownership and all information related to revenues and expenses, and other data were accepted as provided
by Sabretooth. Only direct field expenditures and incomes have been evaluated in this report. General and administrative expenses and
incomes are not reported herein. No field inspection was considered necessary by GLJ.
(5) The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to
future operating and capital costs. Crude oil and natural gas benchmark reference pricing, effective January 1, 2009, inflation and
exchange rates utilized by GLJ in the GLJ Reports were as follows:
Light Crude Oil
Natural
Gas NGLs
Year
WTI
Cushing
Oklahomaa
($US/Bbl)
Edmonton
Par Price
40° API
($/Bbl)
Alberta
AECO-C
($/Mmbtu)
Edmonton
Propane
($/Bbl)
Edmonton
Butanes
($/Bbl)
Edmonton
Pentanes
Plus
($/Bbl)
Energyb
Cost
Inflation
Rate
(%/Yr)
Operating
Cost
Inflation
Rate
(%/Yr)
Exchange
Rate
($US/
$Cdn)
Forecast
2009 57.50 68.61 7.58 43.22 52.14 69.98 2% 2% 0.825
2010 68.00 78.94 7.94 49.73 61.57 80.52 2% 2% 0.850
2011 74.00 83.54 8.34 52.63 65.16 85.21 2% 2% 0.875
2012 85.00 90.92 8.70 57.28 70.92 92.74 2% 2% 0.925
2013 92.01 95.91 8.95 60.42 74.81 97.82 2% 2% 0.950
2014 93.85 97.84 9.14 61.64 76.32 99.80 2% 2% 0.950
2015 95.73 99.82 9.34 62.89 77.86 101.81 2% 2% 0.950
2016 97.64 101.83 9.54 64.15 79.43 103.87 2% 2% 0.950
2016 99.59 103.89 9.75 65.45 81.03 105.97 2% 2% 0.950
2016 101.59 105.99 9.95 66.77 82.67 108.10 2% 2% 0.950
escalated rate of 2% thereafter
(a) 40° API, 0.4% sulphur.
(b) Based on WTI US$/bbl.
(6) Weighted average historical prices realized by the Corporation for the year ended December 31, 2008 were $8.06/Mcf for natural gas,
$93.64/Bbl for crude oil, $93.57/Bbl for NGLs.
- 13 -
Reserves Reconciliation
The following table sets out a reconciliation of Sabretooth’s reserves as at December 31, 2008 compared to
December 31, 2007 based on forecast prices and costs.
Light and Medium Oil
Associated and Non-associated
Gas NGLs
Gross
Proved
(Mbbl)
Gross
Probable
(Mbbl)
Gross
Proved
Plus
Probable
(Mbbl)
Gross
Proved
(Bcf)
Gross
Probable
(Bcf)
Gross
Proved
Plus
Probable
(Bcf)
Gross
Proved
(Mbbl)
Gross
Probable
(Mbbl)
Gross
Proved
Plus
Probable
(Mbbl)
Dec. 31, 2007 545 229 775 27,740 14,816 42,556 267 149 416
Production (75) - (75) (4,381) - (4,381) (43) - (43)
Dispositions(1) (319) (101) (420) (4,232) (2,466) (6,697) (71) (45) (116)
Discoveries,
Extensions, and Infills 264 131 395 7,318 3,815 11,132 84 65 149
Improved Recovery,
Economic Factors(2)
Technical Revisions(3) 33 (65) (32) (2,047) (2,210) (4.257) 13 (1) 12
Dec. 31, 2008 448 194 643 24,398 13,955 38,353 251 168 419
Notes:
(1) Includes production attributable to any acquired interests from the acquisition date to the effective date of the GLJ Reports and
production realized from disposed interests from the opening balance date to the effective date of disposition.
(2) Includes economic revisions related to price and royalty factor changes.
(3) Includes technical revisions due to reservoir performance, geological and engineering changes; economic revisions due to changes in
economic limits; and working interest changes resulting from the timing of interest revisions. Economic revisions constitute a minor
component of the total technical revisions.
Additional Oil & Gas Information Undeveloped Reserves
The following tables set forth the gross proved undeveloped reserves and the probable undeveloped reserves, each
by product type, and based on forecast pricing attributed to the Corporation in the most recent three financial years
and, in the aggregate, before that time:
Proved Undeveloped Reserves Light and Medium Oil Natural Gas Natural Gas Liquids Year (Mbbl) (MMcf) (Mbbl) Boe
Prior thereto 0 0 0 0
2006 ................................ 0 480 3 83
2007 ................................ 0 2,311 13 399
2008 ................................ 32 3,704 38 687
Total Probable Undeveloped Reserves Light and Medium Oil Natural Gas Natural Gas Liquids Year (Mbbl) (MMcf) (Mbbl) Boe
Prior thereto 0 1,977 13 343
2006 ................................ 0 1,449 17 259
2007 ................................ 0 2,293 9 390
2008 ................................ 46 3,771 49 723
Total 46 9,490 88 1,715
In general, once proved and/or probable undeveloped reserves are identified they are scheduled into Sabretooth’s
development plans. The Corporation anticipates developing its proved and probable undeveloped reserves within
two years. A number of factors that could result in delayed or cancelled development are as follows:
- 14 -
• • •
changing economic conditions (due to pricing, operating and capital expenditure fluctuations);
changing technical conditions (production anomalies (i.e. water breakthrough, accelerated depletion));
multi-zone developments (i.e. prospective formation completion may be delayed until the initial completion
is no longer economic);
•
a larger development program may need to be spread out over several years to optimize capital allocation
and facility utilization; and
• Significant Factors or Uncertainties
surface access issues (landowners, weather conditions, regulatory approvals).
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the
control of the Corporation. The reserves data included herein represents estimates only. In general, estimates of
economically recoverable hydrocarbon reserves and the future net cash flows therefrom are based upon a number of
variable factors and assumptions, such as historical production from the properties, the assumed effects of regulation
by governmental agencies and future operating costs, all of which may vary considerably from actual results. All
such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree
of speculation involved. For those reasons, estimates of the economically recoverable hydrocarbon reserves
attributable to any particular group of properties, classification of such reserves based on risk of recovery and
estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at
different times, may vary substantially. The actual production, revenues, taxes and development and operating
expenditures of the Corporation with respect to these reserves will vary from such estimates, and such variances
could be material.
Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on
these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the
same reserves based upon production history will result in variations, which may be substantial, in the estimated
reserves.
Consistent with the securities disclosure legislation and policies of Canada, the Corporation has used forecast prices
and costs in calculating reserve quantities included herein. Actual future net cash flows also will be affected by other
factors such as actual production levels, supply and demand for hydrocarbon, curtailments or increases in
consumption by hydrocarbon purchasers, changes in governmental regulations and taxations, currency exchange
rates and the impact of inflation on costs.
Future Development Costs
The table below sets out the development costs deducted in the estimation of future net revenue attributable to
proved reserves and proved plus probable reserves (using forecast prices and costs only). Note all future
development costs are associated with assets.
- 15 -
Forecast Prices and Costs
Proved Reserves
Proved Plus
Probable Reserves
(M$) (M$)
2009 8,123 12,610
2010 3,588 5,551
2011 3,588 3,558
2012 - -
2013 758 827
Remaining years 143 253
Total undiscounted 16,168 22,798
Total discounted at 10% per year 14,200 20,273
We expect that the capital listed in the preceding table will be funded through a combination internally generated
cash flows, equity financings, if available, and drawdowns from credit facilities, if any. The effect of funding costs
on reserves and future net revenue are anticipated to be nil.
Other Oil and Gas Information Oil and Gas Properties
In addition to major properties in the Peace River Arch area of Alberta and the Gunnell area of British Columbia,
Sabretooth has established a gas weighted core set of properties in the Montney unconventional gas fairway in
Alberta and British Columbia. The Corporation owns a total of approximately 230,000 gross acres (121,000 net
acres) of oil and natural gas leases with the potential for multi-zone production at an average working interest of
approximately 53%. In addition, through its 71% equity ownership position in HFG, the Corporation operates and
indirectly holds interests in approximately 47,000 gross acres (39,000 net acres) of Montney unconventional
petroleum and natural gas rights. HFG holds an average working interest of approximately 83% in such properties.
Peace River Arch, Alberta
The Peace River Arch assets are located in Central West Alberta and Central East British Columbia. These assets
include an average working interest of approximately 52% in 152,000 gross (79,000 net) acres of undeveloped land.
The Peach River Arch properties include fields located in the Fourth Creek, George, Royce, Josephine, Earring,
Mulligan, Balsam, Blueberry and Cecil areas. The Peace River Arch assets also include 10 (2.7 net) producing oil
wells, 8 (4.5 net) non-producing oil wells, 38 (20.8 net) producing gas wells and 30 (16.8 net) non-producing gas
wells.
Production from the Peach River Arch assets are weighted 83% to natural gas with the balance being light oil and
NGLs. Production is pipelined to third party owned processing facilities that include fluid handling and gas
processing with a sales gas connection to Nova or Alliance. All separated emulsion is processed at third party
facilities.
During the year ended December 31, 2008, Sabretooth drilled 5 gross wells (3.9 net) in this area with discoveries at
Blueberry, Earring and Gordondale. As a result of the announcement of the NRF, Sabretooth reduced its focus on
conventional Alberta drilling after the first quarter of 2008 and redeployed its capital to British Columbia. With the
Alberta royalty holiday announced in March 2009, Sabretooth is reviewing its plans in this area.
Gunnell
The Gunnell assets are located in North East British Columbia. These assets include an average working interest of
approximately 30% in 17,400 gross (5,100 net) acres of undeveloped land. The Gunnell assets also include 31 (7.2
net) producing gas wells and 2 (0.3 net) non-producing gas wells.
Production from the Gunnell assets is primarily natural gas. Gas production is pipelined to a partner owned facility
and then Spectra.
- 16 -
During the year ended December 31, 2008, Sabretooth drilled 5 gross wells (1.25 net) in this area with a success rate
of 100%.
In 2009, Sabretooth plans to drill 2 gross (0.6 net) horizontal wells at Gunnell.
Ownership of HFG and Montney Assets
As at December 31, 2008, the Corporation held approximately 71% of the outstanding common shares of HFG.
HFG owns 59 net sections of Montney petroleum and natural gas rights which HFG acquired from the Corporation
on December 24, 2008. At December 31, 2008, the HFG Report estimated HFG’s proved and probable reserves to
be 23 Mbbls of crude oil, of which 16 Mbbls was proved, and 1,808 MMcf of natural gas, of which 1,167 MMcf
was proved. Minority shareholders indirectly owned approximately 29% of these reserves at December 31, 2008.
The Montney assets are located in central East British Columbia and Central West Alberta. These assets include an
average working interest of approximately 83% in approximately 33,250 gross (27,500 net) acres of undeveloped
land. The Montney properties include fields located in the Sinclair, Gordondale, Mica, Paradise, Oak/West
Stoddart, Red Creek and Birley areas. The Montney assets also include 1 (0.5 net) producing oil wells, 2 (1.67 net)
producing gas wells and 8 (5.71 net) non-producing gas wells.
Production from the Montney assets are weighted 90% to natural gas with the balance being light oil and NGLs.
Production is pipelined to a third party owned facility that includes NGL handling and gas processing with a sales
gas connection to Nova Pipeline.
During the year ended December 31, 2008, Sabretooth drilled 2 gross wells (1.67 net) in this area with discoveries at
Red Creek and Gordondale.
In 2009, HFG and Sabretooth plan to drill 4 gross (4.0 net) wells in the Montney.
Oil and Gas Wells
The following table set forth Sabretooth’s crude oil and natural gas wells as at December 31, 2008:
Producing
Light and Medium
Oil
Producing
Natural Gas
Non-Producing
Crude Oil
Non-Producing
Natural Gas Total
Gross Net Gross Net Gross Net Gross Net Gross Net
Alberta, Canada 10 2.7 38 20.8 8 4.5 30 16.8 86 44.8
British Columbia,
Canada 2 1.8 35 8.7 1 1.0 10 4.5 48 16.0
Total 12 4.5 73 29.5 9 5.5 40 23.3 134 62.8
Properties with No Attributed Reserves
The Corporation has an interest in approximately 311,919 gross (148,820 net) acres located in Canada to which no
reserves have been attributed. Based on its current drilling program, the Corporation expects that its rights in
approximately 17,060 net acres of land will expire in the next 12 months.
Forward Contracts
The following information presents all positions for the commodity contracts outstanding as at December 31, 2008.
Term Volume Price Basis
April 1, 2008 to March 31, 2009 3,000 GJ/day $7.04 AECO
April 1, 2008 to March 31, 2009 6,000 GJ/day $7.08 AECO
April 1, 2009 to March 31, 2010 6,000 GJ/day $7.85 AECO
- 17 -
Abandonment and Reclamation Costs
The future estimated costs for site restoration and abandonments as at December 31, 2008 were $2,516,000 and the
total estimated, inflated undiscounted cash flows required to settle such obligations, before considering salvage,
were approximately $7,694,000. Sabretooth expects these obligations to be settled in approximately 1 to 20 years.
As at December 31, 2008, no funds had been set aside to settle these obligations.
As at December 31, 2008, Sabretooth had a working interest in 62.8 net wells of which 34.0 were producing and
28.8 were non-producing. Sabretooth’s cost of abandoning and reclaiming the leases such wells and related
facilities, net of salvage values, is estimated in the GLJ Reports to be $2,192,000 undiscounted and $832,000 using a
10% discount rate. Approximately $270,000 is expected to be incurred in the first three years.
Tax Horizon
In 2008, Sabretooth did not pay any income taxes. To offset future income taxes payable, Sabretooth has the
following estimated tax pools as at December 31, 2008:
Scientific Research and Development Expenses $ 23 million
Non-Capital Loss Carryforwards $ 11 million
UCC Pools $ 30 million
COGPE Pools $ 14 million
Canadian Exploration Expense Pools $ 26 million
Canadian Development Expense Pools $ 16 million
Share Issuance Costs $ 4 million
Investment Tax Credits $ 4 million
Sabretooth does not expect to pay income taxes in the 2009 fiscal year assuming Sabretooth incurs further Canadian
exploration expense and Canadian development expense and utilizes such tax pools available to protect future
revenue.
Costs Incurred
The following table summarizes the capital expenditures made by the Corporation on crude oil and natural gas
properties during the year ended December 31, 2008:
Property Acquisition Costs (M$) Country Proved Properties Unproved Properties Exploration Costs (M$) Development Costs (M$)
Canada Nil 5,944 19,824 7,621
Exploration and Development Activities
The following table summarizes the gross and net exploratory and development wells Sabretooth has drilled, or has
participated in for the year ended December 31, 2008:
Gross Net
Exploratory Development Exploratory Development
Light/medium oil wells 2 1 1.81 0.81
Natural gas wells 6 7 5.16 2.41
Dry wells(1) 2 0 0.8 0
Total wells 10 8 7.77 3.22
Note:
(1) "Dry Wells" refers to a well which is not productive. A productive well is a well which is capable of producing oil or natural gas in
quantities considered by the operator to be efficient to justify the costs required to complete and produce the well.
- 18 -
The Corporation’s key areas of exploration and development are Peace River Arch, Oak/Stoddart, Gunnell, and
Fireweed. The Corporation drilled 17 wells in the Peace River Arch, Oak/Stoddart, Gunnell, and Fireweed area and
1 well in the Watelett area in 2008. In 2009, Sabretooth intends to drill approximately 10 (6.6 net) natural gas wells
in the Peace River Arch, Oak, Sinclair, Birley, Mica, Gordondale and Gunnell.
Production Estimates
The following table sets out the volumes of Sabretooth production estimated for 2009, which is reflected in the
estimate of future net revenue using forecast prices as disclosed in the tables contained under "Disclosure of
Reserves Data – Reserves Data (Forecast Prices and Costs)":
Gross Proved Gross Probable
Light and
Medium Oil
(Bbls/d)
Natural Gas
(Mcf/d)
Natural Gas
Liquids
(Bbls/d)
Light and
Medium Oil
(Bbls/d)
Natural Gas
(Mcf/d)
Natural Gas
Liquids
(Bbls/d)
Fourth Creek 4 1,176 10 6 372 5
Gordondale 32 2,691 29 2 456 6
Gunnell - 3,280 18 - 103 1
Mica 51 939 23 1 28 1
Other 136 1,428 17 3 387 4
222 9,513 97 13 1,346 15
Production History
The following table sets forth certain information in respect of production, product prices received, royalties,
production costs and netbacks received by the Corporation for each quarter of the last financial year. All production
has been in Canada:
2008
Three Months
Ended
March 31
Three Months
Ended
June 30
Three Months
Ended
September 30
Three Months
Ended
December 31
Average Daily Production
Light/Medium Crude Oil (Bbl/d) 278 179 198 186
Natural Gas (Mcf/d) 15,773 12,422 10,924 9,480
Natural Gas Liquids ($/Bbl) 372 107 108 122
Average Prices Received
Light/Medium Crude Oil ($/Bbl) 87.57 125.19 111.43 53.55
Natural Gas ($/Mcf) 7.63 8.91 8.32 7.34
Natural Gas Liquids ($/Bbl) 112.20 113.55 111.42 67.98
Royalties
Light/Medium Crude Oil ($/Bbl) 6.10 2.49 0.21 2.10
Natural Gas ($/Mcf) 14.60 12.74 10.70 10.4
Natural Gas Liquids ($/Bbl) 44.80 15.50 14.05 22.91
Production Costs
Light/Medium Crude Oil ($/Bbl) 1.27 1.10 2.05 1.80
Natural Gas ($/Mcf) 11.03 12.74 18.88 15.30
Natural Gas Liquids ($/Bbl) 0.43 0.66 1.12 1.18
Netback Received
Light/Medium Crude Oil ($/Bbl) 3.09 3.11 2.74 2.27
Natural Gas ($/Mcf) 26.90 35.91 25.21 19.34
Natural Gas Liquids ($/Bbl) 1.04 1.89 1.49 1.49
- 19 -
The following table sets out the Corporation’s aggregate production volume by important field for the year ending
December 31, 2008.
Field
Light and Medium Oil
(Bbl/d)
Natural Gas
(Mcf/d)
Natural Gas Liquids
(Bbl/d)
Total
(boe/d)
Fourth Creek 9 1,404 8 251
George 2 907 3 156
Gordondale 2 1,323 4 226
Gunnell 0 3,841 21 661
Mica 21 1,010 28 217
Other 176 3,654 53 838
Total 210 12,139 115 2,349
INDUSTRY CONDITIONS
The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including
land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation
enacted by various levels of governments and with respect to pricing and taxation of oil and natural gas by
agreements among the governments of Canada, Alberta and British Columbia, all of which should be carefully
considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will
affect the Corporation's 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 Corporation 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, oil producers negotiate sales contracts directly with oil purchasers, with the result that the market
determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market,
and the value of refined products. Oil exports may be made under export contracts having terms not exceeding one
year in the case of light oil, and not exceeding two years in the case of heavy oil, provided that an order approving
any such export has been approved by the National Energy Board ("NEB"). Any oil export to be made pursuant to a
contract of longer duration requires an exporter to obtain an export licence from the NEB and the issue of such a
licence requires the approval of the Canadian federal government.
In Canada, the price of natural gas sold is determined by negotiation between buyers and sellers. Natural gas
exported from Canada is subject to regulation by the NEB and the government of Canada. Exporters are free to
negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue
to meet certain criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less
than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to
an NEB licence and Government of Canada approval.
The provincial governments of Alberta and British Columbia also regulate the removal of gas from their
jurisdictions for consumption elsewhere based upon such factors as reserve availability, transportation arrangements
and market considerations.
Royalties
In addition to federal regulations, each province has legislation and regulations which govern land tenure, royalties,
production rates, environmental protection and other related matters. The royalty regime is a significant factor in the
profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are
determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by
governmental regulation and are generally calculated as a percentage of the value of the gross production, and the
royalty rate payable generally depends in part on the prescribed reference prices, well productivity, geographical
location, field discovery date, method of recovery and the type or quality of the petroleum product produced.
Royalties payable on production from lands other than Crown lands are determined by negotiation between the
mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and
royalties. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner's
- 20 -
interest through non-public transactions. These are often referred to as overriding royalties, gross overriding
royalties, net profits interests, or net carried interests.
Competitive Conditions
The oil and natural gas industry in Canada is intensely competitive in all its phases. Sabretooth competes with a
substantial number of other companies that may have greater technical or financial resources. Many of such
companies not only explore for and produce oil and natural gas, but also carry on refining operations and market oil
and other products on a worldwide basis. Generally there is intense competition for the acquisition of undeveloped
or producing resource properties considered to have commercial potential. Prices paid for oil and natural gas
properties are subject to market fluctuations and will directly affect the profitability of producing any oil or natural
gas reserves that may be acquired or developed by the Corporation. See "Risk Factors – Competition".
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial
and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of
various substances produced in association with certain oil and gas industry operations. In addition, such legislation
requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.
Compliance with such legislation can require significant expenditures and a breach of such requirements may result
in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the
imposition of material fines and penalties.
Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act
(Alberta) (the "EPEA"), which came into force on September 1, 1993, and the Oil and Gas Conservation Act
(Alberta) (the "OGCA"). The EPEA and OGCA impose stricter environmental standards, require more stringent
compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta
Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide
emissions from industrial operations including the oil and gas industry. In addition, the reduction emission
guidelines outlined in the Climate Change and Emissions Management Amendment Act came into effect on July 1,
2007 ("CCEMAA"). Under this legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse
gases a year must reduce their emissions intensity by 12%. Industries have three options to choose from in order to
meet the reduction requirements outlined in this legislation, and these are: (i) by making improvement to operations
that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have emissions
below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate
Change and Emissions Management Fund (the "Fund"). Industries can either choose one of these options or a
combination thereof. Pursuant to CCEMAA and the Specified Gas Emitters Regulation, companies were obliged to
reduce their emission intensity by 12% by March 31, 2008. Alberta industries have achieved 2.6 million tonnes of
actual reduction, due to changes in operations and investing on verified offset projects. In addition, certain
companies contributed $40 million to the Fund. It is reasonably likely that the trend towards stricter standards in
environmental legislation and regulation will continue.
On January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta's
projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and
storage, which will be mandatory for in situ oil sand facilities that use heavy fuels for steam generation; (ii) energy
conservation and efficiency; and (iii) greening production through increased investment in clean energy technology,
including supporting research on new oil sands extraction processes, as well as the funding of projects that reduce
the cost of separating carbon dioxide from other emissions supporting carbon capture and storage. In addition to this
action plan, the Provincial Energy Strategy unveiled on December 11, 2008 is expected to, among other things,
support the upgrading, refining and petrochemical clusters existing in the Province, market Alberta's energy
internationally, review the emission targets and carbon charges applied to large facilities, and promote the
innovation of energy technology by encouraging investment in research and development.
British Columbia's Environmental Assessment Act became effective June 30, 1995. This legislation rolls the
previous processes for the review of major energy projects into a single environmental assessment process with
public participation in the environmental review process. On February 27, 2007 the Government of British
Columbia unveiled the Energy Plan outlining its strategy towards the environment and which includes targeting for
- 21 -
zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in
sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for
applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy
and environmental issues. With regards to the oil and natural gas industry the objective is to achieve clean energy
through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract
investment for the development of the oil and natural gas sector. Among the changes to be implemented are: (i) a
new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an
infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing
wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of
unconventional resources such as tight gas and coalbed gas; and (vii) new the Oil and Gas Technology Transfer
Incentive Program that encourages the research, development and use of innovative technologies to increase
recoveries from existing reserves and promotes responsible development of new oil and gas reserves. Furthering
these initiatives, the Government of British Columbia introduced on July 1, 2008, revenue-neutral carbon tax
legislation that is applied to all fossil fuels used in the Province of British Columbia. The tax would be phased in,
and the initial rate would be based on CO2e of $10 per tonne for the first six months of 2009 and $15 per tonne for
the last six months of 2009, following $5 per tonne increases on July of every year until 2012. Tax credits and
reductions will be used in order to offset the tax revenues that the Government of British Columbia would receive
otherwise. On April 3, 2008, the Government of British Columbia introduced the Greenhouse Gas Reduction (Cap
and Trade) Act which will allow participation in the Western Climate Initiative cap and trade systems being
developed. The system establishes a limit on emissions, and allows regulated emitters to buy/sell emission
allowances or offset emits. The emitter is obliged to obtain emission allowances (compliance units) equal to the
amount of greenhouse gases emitted within a certain period of time, and that are supposed to be surrendered to the
Government of British Columbia as compliance proof.
In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"). The Kyoto Protocol
calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between 2008
and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately
40% gross reduction in Canada's current emissions. It is questionable, based on the Updated Action Plan announced
by the Federal Government (see below), that the Kyoto Protocol target of 6% below 1990 emission levels will be
enforced in Canada. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations
under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. On April 26, 2007, the
Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan")
also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan covers not
only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a
number of energy using products.
The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-
Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating
carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through
competitive process; and (iii) targeting research to lower the cost of technology.
In order to strengthen the Action Plan, on March 10, 2008, the Government of Canada released "Turning the Corner
– Taking Action to Fight Climate Change" (the "Updated Action Plan") which provides some additional guidance
with respect to the Government's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by
2050. The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries
including the oil sands, oil and gas and refining. The Updated Action Plan is intended to create a carbon emissions
trading market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a
market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in 2010 and an
additional 2% in subsequent years for existing facilities. This target will be applied to regulated sectors on a facility
specific, sector-wide or corporate basis; in the case of oil sands production, petroleum refining, natural gas pipelines
and upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex
and diverse, or where emissions are affected by factors beyond the control of the facility operator). Emissions from
new facilities, which are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage
continuous emissions intensity reductions over time, and will be granted a 3-year grace period during which no
emissions intensity targets will apply. Targets will begin to apply on the fourth year of commercial operation and the
baseline will be the third year's emissions intensity, with a 2% continuous annual emission intensity improvement
- 22 -
required. The definition of new facility also includes greenfield facilities, major expansions constituting more than a
25% increase in a facility's physical capacity, as well as transformations to a facility that involve significant changes
to its processes. For upstream oil and gas and natural gas pipelines, it will be applied using a sector-specific
approach. For the oil sands, its application will be process-specific, oil sands plants built in 2012 and later, those
which use heavier hydrocarbons, up-graders and in-situ production will have mandatory standards in 2018 that will
be based on carbon capture and storage.
In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum
annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes
of CO2 equivalent per upstream oil and gas facility; and (iii) 10,000 boe/d/company. These proposed thresholds are
significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per
facility.
Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions,
offset credits, clean development credits and credits for early action. The most significant of these compliance
mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to
contribute in order to comply with emissions intensity reductions. The contribution rate will increase over time,
beginning at $15 per tonne for the 2010-12 period, rising to $20 per tonne in 2013, and thereafter increasing at the
nominal rate of GDP growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018.
Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce
greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale
and transformative projects at the same contribution rate and under similar requirements as mentioned above.
The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere,
allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate
offset credits, project proponents must propose and receive approval for emissions reduction activities that will be
verified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated
entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them
for future use or sale.
Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the
Clean Development Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits will be
restricted to 10% of each firm's regulatory obligation, with the added restriction that credits generated through forest
sink projects will not be available for use in complying with the Canadian regulations.
Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entities
for emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and
bankable.
Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting
requirements, it is not currently possible to predict either the nature of those requirements or the impact on the
Corporation and its operations and financial condition at this time.
See "Risk Factors – Environmental".
Pipeline Capacity
Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural
gas industry and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of
capacity on the inter provincial pipeline systems also continues to affect the ability to export oil and natural gas.
The North American Free Trade Agreement
On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the
U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the
Canada U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to
determine whether exports of energy resources to the U.S. or Mexico will be allowed, provided that any export
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restrictions are justified under certain provisions of the General Agreement on Tariffs and Trade, and further
provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the
total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period or in
such other representative period as the parties may agree), (ii) impose an export price higher than the domestic price
subject to an exception with respect to certain 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, prohibition in any circumstances in
which any other form of quantitative restriction is prohibited, and in the case of import price requirements, such
requirements do not apply with respect to enforcement of countervailing and anti dumping orders and undertakings.
The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits
discriminatory border restrictions and export taxes. The 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.
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, licenses and permits for varying periods and on conditions set forth in provincial legislation including
requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be
privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms
and conditions as may be negotiated.
Seasonality
The level of activity in the Canadian oil and 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 drilling 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. See "Risk Factors – Seasonal Impact on Industry".
RISK FACTORS Exploration, Development and Production Risks
Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful
evaluation may not be able to overcome. The long-term commercial success of the Corporation depends on its
ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual
addition of new reserves, any existing reserves the Corporation may have at any particular time and the production
therefrom will decline over time as such existing reserves are exploited. A future increase in the Corporation’s
reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but
also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that
the Corporation will be able to continue to locate satisfactory properties for acquisition or participation. Moreover,
if such acquisitions or participations are identified, the Corporation may determine that current markets, terms of
acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no
assurance that further commercial quantities of oil and natural gas will be discovered or acquired by the
Corporation.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that
are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating
costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and
various field operating conditions may adversely affect the production from successful wells. These conditions
include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme
weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.
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To the extent the Corporation is not the operator of its oil and gas properties, the Corporation will be dependent on
such operators for the timing of activities related to such properties and will be largely unable to direct or control the
activities of the operators.
While diligent well supervision and effective maintenance operations can contribute to maximizing production rates
over time, production delays and declines from normal field operating conditions cannot be eliminated and can be
expected to adversely affect revenue and cash flow levels to varying degrees.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards
typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas
releases and spills, each of which could result in substantial damage to oil and natural gas wells, production
facilities, other property and the environment or in personal injury. In accordance with standard industry practice,
the Corporation is not fully insured against all of these risks, nor are all such risks insurable. Although the
Corporation maintains liability insurance in an amount that it considers consistent with industry practice, the nature
of these risks is such that liabilities could exceed policy limits, in which event the Corporation could incur
significant costs that could have a material adverse effect upon its financial condition. Oil and natural gas
production operations are also subject to all the risks typically associated with such operations, including
encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into
producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse
effect on future results of operations, liquidity and financial condition.
Global Financial Crisis
Recent market events and conditions, including disruptions in the international credit markets and other financial
systems and the deterioration of global economic conditions, have caused significant volatility to and reductions in
commodity prices. These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in
the broader U.S. and global credit and financial markets and resulting in the collapse of, and government
intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less
liquidity, restricted acces to debt or equity financing, widening of credit spreads, a lack of price transparency,
increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns
about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other
financial institutions caused the broader credit markets to further deteriorate and stock markets to decline
substantially. These factors have negatively impacted the Corporation's valuations and will impact the performance
of the global economy going forward.
The current global credit crisis and recession has prices are expected to remain volatile for the near future as a result
of market uncertainties over the supply and demand of these commodities due to the current state of the world
economies, OPEC actions and the ongoing global credit and liquidity concerns.
Prices, Markets and Marketing
The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation will be
affected by numerous factors beyond its control. The Corporation’s ability to market its natural gas and oil may
depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. The
Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines
and processing facilities, and related to operational problems with such pipelines and facilities as well as extensive
government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and
natural gas and many other aspects of the oil and natural gas business.
The Corporation’s revenues, profitability and future growth and the carrying value of its oil and gas properties are
substantially dependent on prevailing prices of oil and gas which are volatile and subject to fluctuations. The
Corporation’s ability to borrow and to obtain additional capital on attractive terms is also substantially dependent
upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor
changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond
the control of the Corporation. These factors include economic conditions, in the United States and Canada, the
actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the
Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of
alternative fuel sources. Fluctuations in the price of oil and gas could have an adverse effect on the Corporation’s
carrying value of its proved reserves, borrowing capacity, revenues, profitability and funds flows from operations.
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Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the
supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the
ongoing credit and liquidity concerns.
Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often
cause disruption in the market for oil and 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.
In addition, financial resources available to the Corporation are in part determined by the Corporation’s borrowing
base. A sustained material decline in prices from historical average prices could reduce the Corporation’s borrowing
base, therefore reducing the bank credit available to the Corporation which could require that a portion, or all, of the
Corporation’s bank debt be repaid.
Variations in Foreign Exchange Rates and Interest Rates
World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is
therefore effected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent years, the
Canadian dollar has increased materially in value against the United States dollar although the Canadian dollar has
recently decreased from such levels. Material increases in the value of the Canadian dollar negatively impact the
Corporation’s production revenues. Future Canadian/United States exchange rates could accordingly impact the
future value of the Corporation’s reserves as determined by independent evaluators.
To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a
credit risk associated with counterparties with which the Corporation may contract.
An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt,
which could negatively impact the market price of the Common Shares.
Regulatory
Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to
extensive controls and regulations imposed by various levels of government that may be amended from time to time,
including those described above under "Industry Conditions". The Corporation’s operations may require licenses
from various governmental authorities. There can be no assurance that the Corporation will be able to obtain all
necessary licenses and permits that may be required to carry out exploration and development at its projects and the
obtaining of such licences and permits may delay operations of the Corporation. Changes to the regulation of the oil
and gas industry in jurisdictions in which the Corporation operates may adversely impact the Corporation’s ability to
economically develop existing reserves and add new reserves.
Kyoto Protocol
Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto
Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide,
methane, nitrous oxide and other so-called "greenhouse gases". The Corporation's exploration and production
facilities and other operations and activities emit greenhouse gases which will require the Corporation to comply
with the new regulatory framework announced on March 10, 2008 by the Federal Government which is intended to
force large industries to reduce emissions of greenhouse gases, in addition to the proposed Clean Air Act (Canada)
of 2006 and Alberta's recently enacted Climate Change and Emissions Management Act and Specified Gas Emitters. The direct or indirect costs of these regulations may have a material adverse effect on the Corporation's
Regulation
business, financial condition, results of operations and prospects. See "Industry Conditions – Environmental
Regulation".
Environmental
All phases of the oil and natural gas business present environmental risks and hazards and are subject to
environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental
legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various
substances produced in association with oil and natural gas operations. The legislation also requires that wells and
facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
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authorities. Compliance with such legislation can require significant expenditures and a breach of applicable
environmental legislation may result in the imposition of fines and penalties, some of which may be material.
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 discharge of oil, natural
gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may
require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it will be in
material compliance with current applicable environmental regulations 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 have a material adverse effect on the Corporation's business, financial condition,
results of operations and prospects. There has been much public debate with respect to Canada's ability to meet these
targets and the Government's strategy or alternative strategies with respect to climate change and the control of
greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required
by the Kyoto Protocol or as otherwise determined, could have a material impact on the nature of oil and natural gas
operations, including those of the Corporation. Given the evolving nature of the debate related to climate change and
the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on the
Corporation and its operations and financial condition. See "Industry Conditions – Environmental Regulation".
Substantial Capital Requirements
The Corporation anticipates making substantial capital expenditures for the acquisition, exploration, development
and production of oil and natural gas reserves in the future. In the event the Corporation’s revenues or reserves
decline, the Corporation may have limited ability to expend the capital necessary to undertake or complete future
drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be
available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is
available, that it will be on terms acceptable to the Corporation. The inability of the Corporation to access sufficient
capital for its operations could have a material adverse effect on the Corporation’s financial condition, results of
operations or prospects.
Additional Funding Requirements
The Corporation’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From
time to time, the Corporation may require additional financing in order to carry out its oil and gas acquisition,
exploration and development activities. Failure to obtain such financing on a timely basis could cause the
Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate
its operations. If the Corporation’s revenues from its reserves decrease as a result of lower oil and natural gas prices
or otherwise, it will affect the Corporation’s ability to expend the necessary capital to replace its reserves or to
maintain its production. If the Corporation’s cash flow from operations is not sufficient to satisfy its capital
expenditure requirements, there can be no assurance that additional debt or equity financing to meet these
requirements will be available at all or on terms acceptable to the Corporation.
Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves
and cash flows to be derived therefrom, including many factors beyond the Corporation’s control. The reserve and
associated cash flow information set forth in this Annual Information Form represents estimates only. In general,
estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based
upon a number of variable factors and assumptions, such as historical production from the properties, future
commodity prices, production rates, ultimate reserve recovery, timing and amount of capital expenditures,
marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future
operating costs, all of which may vary from actual results. All such estimates are to some degree speculative, and
classifications of reserves are only attempts to define the degree of speculation involved. For those reasons,
estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of
properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected
therefrom prepared by different engineers, or by the same engineers at different times, may vary. The Corporation’s
actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary
from estimates thereof and such variations could be material.
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Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on
these methods are generally less reliable than those based on actual production history. Subsequent evaluation of
the same reserves based upon production history and production practices will result in variations in the estimated
reserves and such variations could be material.
In accordance with applicable securities laws, GLJ, the independent evaluator, has used forecast price and cost
estimates in calculating reserve quantities included herein. Actual future net revenue will be affected by other
factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in
consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of
inflation on costs.
Actual production and revenues derived therefrom will vary from the estimates contained in the GLJ Reports, and
such variations could be material. The GLJ Reports are based in part on the assumed success of activities the
Corporation intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom
contained in the GLJ Reports will be reduced to the extent that such activities do not achieve the level of success
assumed in the GLJ Reports.
Royalty Rates
The Alberta provincial government has implemented changes to its royalty structure, as discussed above under the
heading "The Corporation - Other Recent Developments". These changes to the Alberta royalty regime, as well as
the potential for additional future changes and corresponding changes in the royalty regimes applicable in other
provinces, have created uncertainty surrounding the ability to accurately estimate future royalties, resulting in
additional volatility and uncertainty in the oil and gas market. Increases to royalty rates in jurisdictions in which the
Corporation operates may negatively impact the Corporation’s results from operations and its ability to
economically develop existing reserves or add new reserves.
Competition
Oil and gas exploration is intensely competitive in all its phases and involves a high degree of risk. The Corporation
competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties
and in the marketing of oil and natural gas. The Corporation’s competitors include oil and natural gas companies
that have substantially greater financial resources, staff and facilities than those of the Corporation. The
Corporation’s ability to increase reserves in the future will depend not only on its ability to explore and develop its
present properties, but also on its ability to select and acquire suitable producing properties or prospects for
exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and
methods and reliability of delivery. Competition may also be presented by alternate fuel sources.
Availability of Drilling Equipment and Access
Oil and natural gas exploration and development activities are dependent on the availability of drilling and related
equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or
access restrictions may affect the availability of such equipment to the Corporation and may delay exploration and
development activities. To the extent the Corporation is not the operator of its oil and gas properties, the
Corporation will be dependent on such operators for the timing of activities related to such properties and will be
largely unable to direct or control the activities of the operators.
Title to Assets
It is the practice of the Corporation when acquiring significant oil and gas leases or interest in oil and gas leases to
examine the title to the interest under the lease. In the case of minor acquisitions the Corporation may rely upon the
judgment of oil and gas lease brokers or landmen who perform the field work in examining records in the
appropriate governmental office before attempting to place under lease a specific interest. The Corporation believes
that this practice is widely followed in the oil and gas industry. Nevertheless, there may be title defects which affect
lands comprising a portion of the Corporation’s properties which may adversely affect the Corporation.
Hedging
From time to time the Corporation may enter into agreements to receive fixed prices on its oil and natural gas
production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase
beyond the levels set in such agreements, the Corporation will not benefit from such increases. Similarly, from time
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to time the Corporation may enter into agreements to fix the exchange rate of Canadian to United States dollars in
order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States
dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Corporation
would not benefit from the fluctuating exchange rate for the fixed price agreement amount.
Issuance of Debt
From time to time the Corporation may enter into transactions to acquire assets or the shares of other corporations.
These transactions may be financed partially or wholly with debt, which may increase the Corporation’s debt levels
above industry standards. Depending on future exploration and development plans, the Corporation may require
additional equity and/or debt financing that may not be available or, if available, may not be available on favourable
terms. Neither the Corporation’s articles nor its by-laws limit the amount of indebtedness that the Corporation may
incur. The level of the Corporation’s indebtedness from time to time, could impair the Corporation’s ability to
obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.
Investment in ABCP
As at December 31, 2008, the Company held Canadian third party asset backed commercial paper ("ABCP") with
an original cost of $24,147,000. These investments matured during the third quarter of 2007 but, as a result of the
liquidity issues in the ABCP market, did not settle on maturity. As a result, the Corporation classified its investment
in ABCP as a long-term investment in its Annual Financial Statements and attributed a value of $13,968,000 to its
ABCP investment as of December 31, 2008.
On January 21, 2009, upon completion of the restructuring process overseen by the Pan-Canadian Investors
Committee, the Corporation’s investment in ABCP was exchanged for new notes of various classes issued by a trust
referred to as Master Asset Vehicle 2. The estimated fair value of the replacement notes is unchanged from the
December 31, 2008 estimated fair value.
There are currently no market quotations available for the new replacement notes and the estimate fair market value
attributed to such notes by the Corporation is based on assumptions which may prove to be inaccurate. Continuing
uncertainties regarding the value of the assets which underlie the ABCP, the amount and timing of cash flows, the
evolution of the liquidity of the market for the new notes issued following the restructuring and the evolution of the
prevailing financial crisis and other factors could give rise to a further change in the value of the Company’s
investment in ABCP which could negatively impact the Company’s earnings.
Credit Risk
The majority of the Corporation’s accounts receivable are due from joint venture partners in the oil and gas industry
and from purchasers of the Corporation’s petroleum and natural gas production and are subject to the same industry
factors such as commodity price fluctuations and escalating costs. The Corporation generally extends unsecured
credit to these customers and therefore, the collection of accounts receivable may be affected by changes in
economic or other conditions.
Failure to Realize Anticipated Benefits of Acquisitions and Dispositions
The Corporation makes acquisitions and dispositions of businesses and assets in the ordinary course of business.
Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating
operations and procedures in a timely and efficient manner as well as the Corporation’s ability to realize the
anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of
Sabretooth. The integration of acquired business may require substantial management effort, time and resources and
may divert management’s focus from other strategic opportunities and operational matters. Management
continually assesses the value and contribution of services provided and assets required to provide such services. In
this regard, non-core assets are periodically disposed of, so that the Corporation can focus its efforts and resources
more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the
Corporation, if disposed of, could be expected to realize less than their carrying value on the financial statements of
the Corporation.
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Seasonal Impact on Industry
The level of activity in the Canadian oil and 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 drilling 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. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity
and corresponding declines in the demand for the goods and services of Sabretooth.
Conflicts of Interest
There are potential conflicts of interest to which some of the directors and officers of the Corporation will be subject
in connection with the operations of the Corporation. Some of the directors and officers are engaged and will
continue to be engaged in the search of oil and gas interests on their own behalf and on behalf of other corporations,
and situations may arise where the directors and officers will be in direct competition with the Corporation.
A majority of the board of HFG and all of HFG’s officers are directors and/or officers of Sabretooth. Sabretooth,
which is the majority shareholder of HFG, operates all of HFG’s assets and is active in the same areas as, and may
from time to time directly compete with, HFG.
Conflicts of interest, if any, which arise will be subject to and be governed by procedures prescribed by the ABCA
which require a director or officer of a corporation who is a party to or is a director or an officer of or has a material
interest in any person who is a party to a material contract or proposed material contract with the Corporation, to
disclose his interest and to refrain from voting on any matter in respect of such contract unless otherwise permitted
under the ABCA.
Reliance on Key Personnel
The Corporation’s success depends in large measure on certain key personnel. The loss of the services of such key
personnel could have a material adverse affect on the Corporation. The Corporation does not have key person
insurance in effect for management. The contributions of these individuals to the immediate operations of the
Corporation are likely to be of central importance. In addition, the competition for qualified personnel in the oil and
natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract
and retain all personnel necessary for the development and operation of its business. Investors must rely upon the
ability, expertise, judgment, discretion, integrity and good faith of the management of the Corporation.
Expiration of Licences and Leases
The Corporation’s properties are held in the form of licences and leases and working interests in licences and leases.
If the Corporation or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the
licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain
each licence or lease will be met. The termination or expiration of the Corporation’s licences or leases or the
working interests relating to a licence or lease may have a material adverse effect on the Corporation’s results of
operations and business.
Management of Growth
The Corporation may be subject to growth-related risks including capacity constraints and pressure on its internal
systems and controls. The ability of the Corporation to manage growth effectively will require it to continue to
implement and improve its operational and financial systems and to expend, train and manage its employee base.
The inability of the Corporation to deal with this growth could have a material adverse impact on its business,
operations and prospects.
Insurance
The Corporation’s involvement in the exploration for and development of oil and natural gas properties may result
in the Corporation becoming subject to liability for pollution, blow outs, property damage, personal injury or other
hazards. Although prior to drilling the Corporation will obtain insurance in accordance with industry standards to
address certain of these risks, such insurance has limitations on liability that may not be sufficient to cover the full
extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain
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circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high
premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce
the funds available to the Corporation. The occurrence of a significant event that the Corporation is not fully
insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the
Corporation’s financial position, results of operations or prospects.
DESCRIPTION OF SHARE CAPITAL
The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number of
Non-Voting Shares. As at December 31, 2008 there were 38,660,650 Common Shares issued and outstanding and
no Non-Voting Shares were issued and outstanding.
Each Common Share entitles the holder thereof to one vote at all meetings of shareholders of Sabretooth (except
meetings at which only holders of another specified class of shares are entitled to vote); to receive dividends as and
when declared by the Board (provided that Sabretooth shall not pay dividends on the Common Shares or the
Non-Voting Shares unless, at the same time and as the case may be, Sabretooth declares and pays dividends on the
Non-Voting Shares or Common Shares in a proportionate amount); and, subject to the prior rights of holders of any
other class of shares ranking prior to the Common Shares and on a pari passu basis together with the holders of the
Non-Voting Shares, to receive the remaining property of Sabretooth upon liquidation, dissolution or wind-up of
Sabretooth.
Holders of Non-Voting Shares are not, as such, entitled to receive notice of or to attend any meeting of shareholders
or to vote at any such meeting, subject to the provisions of the ABCA. Holders of Non-Voting Shares are entitled to
dividends as and when declared by the Board (provided that Sabretooth shall not pay dividends on the Non-Voting
Shares unless, at the same time, Sabretooth also declares and pays dividends on the Common Shares in a
proportionate amount); and, subject to the prior rights of holders of any other class of shares ranking prior to the
Non-Voting Shares on a pari passu basis together with the holders of the Common Shares, to receive the remaining
property of Sabretooth upon the liquidation, dissolution or wind-up of Sabretooth. Holders of Non-Voting Shares
do not have a right to participate if a takeover bid is made for the Common Shares.
DIVIDENDS
Sabretooth has not paid any dividends since incorporation. It is not expected that dividends will be paid in respect
of the shares of Sabretooth during the current phase of development of Sabretooth's business and operations. The
payment of dividends in the future will be at the discretion of the directors and shall be dependent on the future
earnings and financial condition of the Corporation and such other factors as the directors consider appropriate.
- 31 -
MARKET FOR SECURITIES
The Common Shares are listed and posted for trading on the TSX under the symbol "SAB".
The following table sets forth the high and low trading prices and the aggregate volume of trading of the Common
Shares on the TSX for the periods indicated (as quoted by the TSX) intraday:
Period High $ Low $ Volume
2008 2.95 0.19 102,458
January 2.34 1.83 57,732
February 2.85 2.19 66,213
March 2.84 2.51 70,474
April 2.75 2.12 117,985
May 2.95 2.20 279,565
June 2.86 2.10 190,043
July 2.79 2.00 107,739
August 2.05 1.64 62,093
September 1.93 1.10 45,761
October 1.31 0.35 115,160
November 0.43 0.30 67,007
December 0.34 0.19 39,582
DIRECTORS AND OFFICERS
The following are the names and place of residence of the directors and officers of Sabretooth as at the date hereof,
their position and offices with Sabretooth and their principal occupations during the past five years.
Name and Province / Country of Residence Principal Occupation for Past Five Years Position of Office within Sabretooth Year Became a Director or Officer
Marshall Abbott(2)(3)
Calgary, Alberta, Canada
Geologist. Chairman and CEO Sabretooth
since 2005. Prior thereto, Chairman and CEO
of Cougar Hydrocarbons from 2001 to 2003.
CEO and Director 2005
Tom Brinkerhoff(2)
Calgary, Alberta, Canada
President Brinkerhoff Drilling since 1979. Director 2005
John H. Campbell, Jr.(3)(4)
Houston, Texas, USA
Managing Director, Quantum Energy Partners
since 2003. Prior thereto, Senior Vice
President Operations - North America
Onshore for Ocean Energy, Inc. (former
NYSE: OEI)
Director 2005
Brent Perry(1)
Calgary, Alberta, Canada
Lawyer. Partner with Felesky Flynn LLP
(law firm) since 1983.
Director 2005
Hank Swartout(3)
Calgary, Alberta, Canada
Executive Chairman, Precision Drilling since
1987.
Chairman and Director 2005
S. Wil VanLoh, Jr. (1)(2)(4)
Houston, Texas, USA
Managing Partner, Quantum Energy Partners
since 1998.
Director 2005
Vincent J. Chahley (1)
Calgary, Alberta, Canada
Independent Businessman. Prior thereto,
Managing Director, Corporate Finance,
Tristone Capital Inc. from May 2001 to June
2005. Effective May 1, 2009 Mr. Chahley
will start as Managing Director Corporate
Finance with Fist Energy Capital Corporation.
Director 2007
- 32 -
Name and Province / Country of Residence Principal Occupation for Past Five Years Position of Office within Sabretooth Year Became a Director or Officer
Joe McFarlane
Calgary, Alberta, Canada
Chartered Accountant. CFO of Sabretooth,
since June 2005. Prior thereto Controller of
NAV Energy Trust from 2004 to June 2005
and various positions with PanCanadian /
EnCana from 2001 to June 2005.
Chief Financial Officer 2005
Mike Ponto
Calgary, Alberta, Canada
Professional Landman. Vice President Land
of Sabretooth since 2006. Consultant,
Paramount Energy Trust during 2006.
Consultant with EnCana from 2005 to 2006.
Consultant with Apache from 2004 to 2005.
Prior thereto, various positions with APF.
Vice President Land 2006
Christine Robertson
Calgary, Alberta, Canada
Professional Engineer. Chief Operating
Officer of Sabretooth since 2006. Vice
President Engineering, Valiant Energy Inc.
July 2005 to 2006. Prior thereto Vice
President Engineering of Forte Resources Inc.
from October 2004 to July 2005, Manager
Reservoir Engineering of Forte Resources Inc.
from March 2004 to October 2004 and of
Forte Oil Corporation from March 2003 to
March 2004.
Chief Operating Officer 2007
Notes:
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Reserves Committee.
(4) Messrs. Campbell and VanLoh are directors and officers of Quantum Energy Partners, which is the beneficial holder of 9,782,001
Sabretooth Common Shares.
Sabretooth’s directors and officers, as a group, own, directly and indirectly, an aggregate of 14,531,329 Common
Shares (including 9,782,001 Common Shares beneficially held by Quantum Energy Partners), or approximately
37.59% of the issued and outstanding Common Shares. In addition, the directors and officers of Sabretooth, as a
group, hold options to purchase 3,091,000 Sabretooth Common Shares.
The term of office of each director will expire at the next Annual General Meeting of shareholders.
Conflicts Of Interest
Circumstances may arise where members of the board of directors of Sabretooth are directors or officers of
corporations which are in competition to the interests of Sabretooth. A majority of the board of HFG and all of
HFG’s officers are directors and/or officers of Sabretooth. Sabretooth, which is the majority shareholder of HFG,
operates all of HFG’s assets and is active in the same areas as, and may from time to time directly compete with,
HFG.
No assurances can be given that opportunities identified by board members will be provided to Sabretooth. Pursuant
to the ABCA, directors who have an interest in a proposed transaction upon which the board of directors is voting
are required to disclose their interests and refrain from voting on the transaction unless otherwise permitted under
the ABCA. See "Risk Factors – Conflicts of Interest".
AUDIT COMMITTEE INFORMATION Members
The Corporation’s Audit Committee currently consists of three members, Vincent Chahley, Brent Perry and S. Wil
VanLoh, Jr. Each member of the Audit Committee is financially literate, meaning the member has the ability to
read and understand a set of financial statements that present a breadth and level of complexity that can be expected
to be raised with the Corporation’s financial statements and is considered to be independent for the purposes of
NI 52-110 as none of these individuals have a direct or indirect material relationship with the Corporation.
The following is a description of the education and the experience of each member of the Audit Committee.
- 33 -
Vincent J. Chahley, Chairman
Mr. Vincent Chahley is an independent businessman. Mr. Chahley became a director of the Corporation in 2007.
Prior thereto, he was a director of Bear Ridge and the Managing Director of Corporate Finance of Tristone Capital
Inc. from May 2001 to June 2005. Mr. Chahley holds a Bachelor of Commerce degree from the University of
Alberta and worked in the investment banking industry from 1985 to 2005, holding positions of Managing Director
and Partner. Mr. Chahley is also a director of Anderson Energy Ltd., Bellamont Exploration Ltd. and Pegasus Oil
and Gas Inc.
Brent Perry, Director
Mr. Perry has been a partner with Felesky Flynn LLP, a law firm, since 1983, a joint managing partner of such firm
since 2003, and was appointed Queen’s Counsel in 2000. His practice covers a broad spectrum of business and
personal tax planning, with a focus on financing, mergers and acquisitions, divestitures and corporate structuring.
Mr. Perry holds a Bachelor of Commerce and a Bachelor of Law degree from the University of Alberta.
S. Wil VanLoh, Jr, Director
Mr. Wil VanLoh is the co-founder and managing partner of Quantum Energy Partners, a $3 billion US private
equity firm based in Houston. Mr. VanLoh leads Quantum Energy Partners’ investment activities including
investment sourcing, due diligence, and transaction structuring. He is also a board member and Treasurer of
Houston Producer’s Forum and a member of the IPAA Finance Committee. He holds a Bachelors of Business
Administration degree in Finance from Texas Christian University.
Audit Committee Charter
The complete text of the Corporation’s Audit Committee charter is attached as Appendix B hereto. The primary
function of the Audit Committee is to assist the Board in fulfilling its oversight responsibilities in respect of the
Corporation’s financial reporting process and financial statements, including the adequacy, integrity and
effectiveness of internal financial and management controls and systems, and risk management, including the
adequacy, integrity and effectiveness of risk management systems and reporting. It performs this function by
serving as an independent and objective party to monitor the Corporation’s financial reporting process and internal
control system; reviewing and assessing audit efforts of the Corporation’s independent auditors; providing an
avenue of open communication among the Corporation’s independent auditors, financial and senior management
and Board of Directors; and reviewing the independence and performance of the independent auditor. The Audit
Committee has the authority to investigate any corporate activity in any area that the Committee considers necessary
or advisable and the authority to engage and obtain the advice of outside advisors if necessary to properly discharge
its functions, duties and responsibilities.
Audit Fees
The table below provides disclosure of the services provided by the Corporation’s external auditors in fiscal 2007
and fiscal 2008, dividing the services into the categories of work performed.
Type of Work 2008 Fees 2008 Percentage 2007 Fees 2007 Percentage
Audit Fees(1) $278,200 90% $172,500 73%
Tax Fees(2) 1,000 1% 12,100 5%
All Other Fees (3) 30,000 9% 51,000 22%
Total $309,200 100% $235,600 100%
Notes:
(1) "Audit Fees" include the aggregate professional fees paid to the external auditors for the audit of the annual consolidated financial
statements and other annual regulatory audits and filings. It also includes the aggregate fees paid to the external auditors for services
related to the audit services, including reviewing quarterly financial statements and management’s discussion and analysis thereon,
consulting with the Board and Audit Committee regarding financial reporting and accounting standards and assistance with
management information circular, service related to underwriter’s due diligence.
(2) "Tax Fees" include the aggregate fees paid to external auditors for tax compliance, tax advice, tax planning and advisory services,
including namely preparation of tax returns.
(3) "All Other Fees" include fees for assurance procedures in connection with filings statements and information circulars.
- 34 -
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
There are currently no outstanding legal proceedings that involve a claim for damages that exceeds 10% of the
current assets of the Corporation, exclusive of interest and costs, to which the Corporation or any subsidiary of the
Corporation is a party or of which any property of the Corporation is the subject matter, nor are any such
proceedings known to the Corporation to be contemplated.
During the year ended December 31, 2008 there were no penalties or sanctions imposed against the Corporation or
by a court relating to securities legislation or by a securities regulatory authority. In addition, there were (i) no other
penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered
important to a reasonable investor in making an investment decision, and (ii) the Corporation did not enter into any
settlement agreements between a court relating to a securities legislation or with a securities regulatory authority
during the year ending December 31, 2008.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
Management is not aware of any material interest, direct or indirect, of any director or executive officer of the
Corporation, a person or company that is the direct or indirect beneficial owner of, or who exercises control or
direction over, more than 10% of the Common Shares, or their respective associates or affiliates, in any transaction
within the three most recently completed financial years or during the current financial year that has materially
affected or would materially affect the Corporation or any of its subsidiaries.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Shares is Valiant Trust Company at its principal offices in Toronto
and Calgary.
MATERIAL CONTRACTS
The Corporation has not entered into any material contracts, except for contracts entered into by the Corporation in
the ordinary course of business other than the following:
• • • INTERESTS OF EXPERTS
Services Agreement;
Registration Rights Agreement; and
Escrow Agreement.
The only persons named as having prepared or certified a statement, report or valuation described or included in a
filing, or referred to in a filing, made by the Corporation under applicable continuous disclosure obligations during,
or relating to, the financial year ended December 31, 2008, and whose profession or business gives authority to the
statement, report or valuation, are GLJ, the independent petroleum consultants of the Corporation and Collins
Barrow Calgary LLP, the independent auditors of the Corporation.
As at the date hereof, the designated professionals of GLJ, as a group, beneficially own, directly or indirectly, less
than 1% of the outstanding securities of each class of the Corporation.
Collins Barrow Calgary LLP has advised management of the Corporation that they are independent of the
Corporation in accordance with the Rules of Professional Conduct of the Institute of Chartered Accountants of
Alberta.
ADDITIONAL INFORMATION
Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of the
Corporation’s securities and securities authorized for issuance under equity compensation plans will be contained in
the Management Information Circular and Proxy Statement of the Corporation relating to the Corporation’s 2009
annual general meeting. Additional financial information is provided on the System for Electronic Document
Analysis and Retrieval ("SEDAR") in the Corporation’s comparative financial statements and management’s
discussion and analysis for the year ended December 31, 2008.
- 35 -
Additional information relating to the Corporation may be found on SEDAR, which can be accessed at
www.sedar.com.
APPENDIX A FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
Management of Sabretooth Energy Ltd. (the "Company") are 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 consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2008,
the last day of the Company’s most recently completed financial year, using forecast
prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31, 2008, the last day of the
Company’s most recently completed financial year, using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the
independent qualified reserves evaluator is presented below.
The Reserves Committee of 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 Reserves Committee of 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, on the recommendation of the Reserves Committee, approved:
(a) the content and filing with securities regulatory authorities of the reserves data and other oil and
gas information;
(b) the filing of 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 judgements regarding future events, actual results will vary and the
variations may be material.
DATED this 20th day of March, 2009.
(Signed)
"Marshall Abbott"
Chief Executive Officer
(Signed)
"Joseph Eric McFarlane"
Chief Financial Officer
(Signed)
"Hank Swartout"
Director
(Signed)
"John H. Campbell, Jr."
Director
A-2
FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the board of directors of Sabretooth Energy Ltd. (the "Company"):
1. We have prepared an evaluation of the Company’s reserves data as at December 31, 2008. The reserves
data are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2008, 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 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, 2008, and identifies the respective portions thereof that we have audited, evaluated
and reviewed and reported on to the Company’s board of directors:
Net Present Value of Future Net Revenue
Independent (before income taxes, 10% discount rate - $M)
Qualified Reserves
Evaluator
Description and
Preparation Date of
Evaluation Report
Location of
Reserves
(Country or
Foreign
Geographic
Area) Audited Evaluated Reviewed Total
GU Petroleum Consultants February 24, 2009 Canada - 112,839 - 112,839
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been
determined and are in accordance with the COGE Handbook.
6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances
occurring after their respective preparation dates.
7. Because the reserves data are based on judgements regarding future events, actual results will vary and the
variations may be material. However, any variations should be consistent with the fact that reserves are
categorized according to the probability of their recovery.
EXECUTED as to our report referred to above:
GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 3, 2009
"Bryan M. Joa"
Bryan M. Joa, P. Eng.
Vice-President
A-3
FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the board of directors of HFG Holdings Inc. (the "Company"):
1. We have prepared an evaluation of the Company’s reserves data as at December 31, 2008. The reserves
data are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2008, 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 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, 2008, and identifies the respective portions thereof that we have audited, evaluated
and reviewed and reported on to the Company’s board of directors:
Net Present Value of Future Net Revenue
Independent (before income taxes, 10% discount rate - $M)
Qualified Reserves
Evaluator
Description and
Preparation Date of
Evaluation Report
Location of
Reserves (Country
or Foreign
Geographic Area) Audited Evaluated Reviewed Total
GU Petroleum Consultants January 27, 2009 Canada - 4,693 - 4,693
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been
determined and are in accordance with the COGE Handbook.
6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances
occurring after their respective preparation dates.
7. Because the reserves data are based on judgements regarding future events, actual results will vary and the
variations may be material. However, any variations should be consistent with the fact that reserves are
categorized according to the probability of their recovery.
EXECUTED as to our report referred to above:
GLJ Petroleum Consultants Ltd., Calgary, AIberta, Canada, February 6, 2009
"Bryan M. Joa"
Bryan M. Joa, P. Eng.
Vice-President
APPENDIX B AUDIT COMMITTEE TERMS OF REFERENCE SABRETOOTH ENERGY LTD. AUDIT COMMITTEE TERMS OF REFERENCE 1. Constitution
Pursuant to the Business Corporations Act (Alberta), the by-laws of Sabretooth Energy Ltd. (the
"Corporation") and a resolution of the Board of Directors of the Corporation (the "Board") dated August
20, 2007 and in intended compliance with applicable corporate and securities laws and the requirements of
the exchange upon which securities of the Corporation may be listed, these terms of reference are hereby
adopted as the terms of reference for the Audit Committee (the "Committee") of the Corporation which
Committee is delegated the powers and subject to the terms of reference hereinafter set forth.
2. Mandate
The mandate of the Committee shall be to assist the Board in fulfilling its oversight responsibilities in
respect of: (i) the adequacy, integrity and effectiveness of the Corporation’s financial reporting process and
financial statements, including without limitation the adequacy, integrity and effectiveness of internal
financial and management controls and systems; and the adequacy and integrity of the audit process; and
(ii) risk management for the Corporation, including without limitation the adequacy, integrity and
effectiveness of risk management systems and reporting, in addition to any mandate or function prescribed
by applicable law, regulation or rule to be discharged by a Committee constituted as the audit committee of
a corporation such as the Corporation.
3. Organization and Operation
(1) The Committee shall be comprised of a minimum of three (3) members of the Board.
(2) Each of the members of the Committee shall be "independent" and "financially literate" as
required by Multilateral Instrument 52-110 or any rule or instrument implemented in substitution
or addition thereto and to the extent practicable, the Committee shall include at least one member
who may reasonably be regarded as a financial expert.
(3) A majority of the members of the Committee shall be residents of Canada.
(4) The Committee shall have the power to appoint its chairman.
(5) Any member of the Committee or the auditors of the Corporation (the "auditors") may call a
meeting of the Committee upon not less than 48 hours’ notice to the other members of the
Committee.
(6) The auditors of the Corporation are entitled to receive notice of every meeting of the Committee
and at the expense of the Corporation, to attend and be heard thereat and, if so requested by a
member of the Committee, shall attend any meeting of the Committee held during the term of
office of the auditors.
(7) The Committee shall meet at least four times annually.
(8) A quorum for meetings of the Committee shall be a majority of its members, provided that a
majority of the members of the Committee comprising such quorum must be residents of Canada.
(9) Questions arising at any meeting of the Committee shall be decided by a majority of the votes
cast.
(10) The rules for calling, holding, conducting and adjourning meetings of the Committee shall be the
same as those governing meetings of the Board or as otherwise provided in the by-laws of the
Corporation.
(11) Except as set forth herein, the Committee may determine its own rules of procedure.
B-2
4. Duties and Responsibilities
In the discharge of its mandate, the Committee shall:
Corporate Information and Internal Control
(1) review and recommend for approval by the Board annual and quarterly financial statements, and
all financial information in any prospectus, offering memorandum, annual information form,
management’s discussion and analysis ("MD&A") or annual report of the Corporation;
(2) review and make recommendations with respect to information and control systems of the
Corporation;
(3) review and approve all major changes to information and control systems of the Corporation;
(4) review and approve spending authorities and approval limits of officers of the Corporation;
(5) review and approve all determinations made in respect of significant accounting and tax
compliance issues;
(6) review all significant financial, accounting and tax issues in connection with proposed nonrecurring
events such as mergers, acquisitions or divestitures;
(7) review and approve all press releases or other publicly circulated documents containing financial
information;
Auditors
(8) make recommendations to the Board in respect of the auditors to be nominated for the purpose of
preparing or issuing an audit report or performing other audit, review or attest services for the
Corporation, in respect of the terms of retainer of the auditors and, as determined desirable or
necessary, in respect of the replacement of the auditors (subject to securityholder notification and
approval);
(9) review the terms of the auditors’ engagement and make recommendations to the Board as to the
compensation of the auditors;
(10) oversee the work of auditors engaged for the purposes of preparing or issuing an audit report or
performing other audit, review or attest services for the Corporation, including the resolution of
disagreements between management and the auditors regarding financial reporting;
(11) annually, obtain and review a report by the auditors of the Corporation’s internal quality control
procedures and systems;
(12) review and make recommendations in respect of any material issues raised by any internal quality
control review (or peer review) of the Corporation or by any inquiry or investigation by
governmental or professional authorities;
(13) annually, evaluate the auditors’ qualifications, performance and independence;
(14) annually, to assure continuing auditor independence, consider the rotation of lead audit partner or
the auditor itself;
(15) where there is a change of auditor, review all issues related to the change, including information to
be included in the notice of change of auditors specified by National Instrument 5I-102 ("NI 51-"), and the planned steps for an orderly transition;
102
(16) review all reportable events, including disagreements, unresolved issues and consultations, as
defined in National Instrument NI 51-102, on a routine basis, whether or not there is a change of
auditors;
(17) pre-approve engagements for non-audit services provided by the auditors or their affiliates,
together with estimated fees and potential issues of independence;
(18) set hiring policies for partners, employees and former partners and employees of the present and
former auditors;
B-3
(19) at least annually, separately interview management and the auditors to discuss the relationship
between them, especially as regards to the competency, communication, access provided and
cooperation displayed in matters relating to the audit and the financial affairs of the Corporation;
(20) establish procedures for:
(a) the receipt, retention and treatment of complaints received by the Corporation regarding
accounting, internal accounting controls, or auditing matters; and
(b) the confidential, anonymous submission by employees of the Corporation of concerns
regarding questionable accounting or auditing matters;
(21) monitor changes to applicable laws, regulations and rules and industry standards and practices
with respect to financial reporting;
Audit
(22) review with management and the auditors the audit plan for the coming year;
(23) review with management and the auditors any proposed changes in major accounting policies, the
presentation and impact of significant risks and uncertainties, and key estimates and judgements of
management that may be material to financial reporting;
(24) separately interview management and the auditors regarding significant financial reporting issues
during the fiscal period and the method of resolution;
(25) review any problems experienced by the auditors in performing the audit, including any
restrictions imposed by management or significant accounting issues in which there was a
disagreement with management;
(26) review annual and quarterly financial statements with management and the auditors (including
disclosures under MD&A), in conjunction with the report of all significant variances between
comparative reporting periods;
(27) review and make recommendations as to the auditors’ report to management and management’s
response and subsequent remedy of any identified weaknesses;
Risk Management and Controls
(28) provide oversight in respect of risk management policies and practices, including the identification
of major business risks and the processes and other steps taken to mitigate such risks;
(29) review and make recommendations as to hedging strategies, policies, objectives and controls;
(30) review, not less than quarterly, a mark to market assessment of the Corporation’s hedge positions
and counter party credit risk and exposure;
(31) review the Corporation’s risk retention philosophy and resulting exposure to the Corporation;
(32) review the adequacy of insurance coverage;
(33) review loss prevention policies and programs in the context of competitive and operational
considerations;
(34) review and recommend for approval the annual operating and capital budgets of the Corporation
and any amendments thereto;
(35) annually, review authority limits for capital expenditures; and
(36) review all pending litigation involving the Corporation and assess the prospective exposure to the
Corporation.
Other Duties and Responsibilities
The responsibilities, practices and duties of the Committee outlined herein are not intended to be
comprehensive. The Board may, from time to time, charge the Committee with the responsibility of
reviewing other items of a financial or control nature or a risk management nature.
B-4
The Committee shall periodically report to the Board decisions taken in exercise of powers conferred
herein and the results of reviews undertaken and any associated recommendations.
5. Authority
The Committee shall have all power and authority necessary or desirable to fully and effectively discharge
its mandate hereunder and, in that connection and without limitation, the Committee may:
(1) investigate any corporate activity, in any area, that the Committee considers necessary or
advisable, and, for such purposes and the performance of its other responsibilities, the Committee
shall have unrestricted access to all personnel and records of the Corporation, the auditors and all
other advisors to the Corporation;
(2) make any recommendation to the Board, as it considers necessary or advisable, in respect of
matters within its mandate, provided however that where the Committee intends to make any such
recommendation, the recommendation shall first be presented to the Chairman of the Board and in
respect of financial matters, to the auditor for comment before being communicated to the Board,
unless the Committee concludes that such action would not be in the best interest of the
Corporation and/or the securityholders; and
(3) engage and obtain the advice of outside advisors if necessary to properly discharge its functions,
duties and responsibilities including, without limitation,
(a) to engage independent counsel and other advisors as it determines necessary to carry out
its duties;
(b) to set and pay the compensation for any advisors employed by the Committee; and
(c) to communicate directly with the auditors.
6. Limitation
The foregoing is (i) subject to and without limitation of the requirement that in exercising their powers and
discharging their duties the members of the Board act honestly and in good faith with a view to the best
interests of the Corporation; and (ii) subject to and not in expansion of the requirement that in exercising
their powers and discharging their duties the members of the Board exercise the care, diligence and skill
that a reasonably prudent person would exercise in comparable circumstances.
Dated for reference: August 20, 2007.
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