ANNUAL INFORMATION FORM
For the Year Ended December 31, 2011
Dated March 21, 2012
TABLE OF CONTENTS
Definitions ............................................................................................................................................................. 5
Abbreviations and Conversion ............................................................................................................................... 8
Special Note Regarding Forward Looking Statements ........................................................................................... 9
Surge Energy Inc. ..................................................................................................................................................10
General .................................................................................................................................................................. 10
Development of the Business ...............................................................................................................................11
General .................................................................................................................................................................. 11
2009 .................................................................................................................................................................. 11
2010 .................................................................................................................................................................. 11
The Recapitalization ............................................................................................................................................... 12
New Management Group ...................................................................................................................................... 12
Prospectus Financing ............................................................................................................................................. 12
Corinthian and Crystal Lake Acquisition ................................................................................................................ 12
Name Change ........................................................................................................................................................ 13
Valhalla Asset Acquisition ...................................................................................................................................... 13
Subscription Receipt Offering ................................................................................................................................ 13
2011 and 2012 to date ..................................................................................................................................... 13
Description of the Business ..................................................................................................................................14
Corporate Strategy ................................................................................................................................................ 14
Competition ........................................................................................................................................................... 15
Seasonal Factors .................................................................................................................................................... 15
Environmental Regulation ..................................................................................................................................... 15
Personnel ............................................................................................................................................................... 16
Principal Producing Properties..............................................................................................................................16
Statement of Reserves Data .................................................................................................................................17
Summary of Oil and Gas Reserves – Forecast Prices and Costs ............................................................................. 18
Net Present Value of Future Net Revenue – Forecast Prices and Costs ................................................................ 18
Additional Information Concerning Future Net Revenue – Forecast Prices and Costs (Undiscounted) ................ 19
Future Net Revenue by Production Group – Forecast Prices and Costs ................................................................ 19
Pricing Assumptions – Forecast Prices and Costs .................................................................................................. 19
Reconciliation of Changes in Reserves ................................................................................................................... 20
Additional Information Relating to Reserves Data ................................................................................................21
Undeveloped Reserves .......................................................................................................................................... 21
Significant Factors or Uncertainties Affecting Reserves Data ................................................................................ 21
Future Development Costs .................................................................................................................................... 22
Other Oil and Gas Information .............................................................................................................................22
Oil and Gas Wells ................................................................................................................................................... 22
Properties with no Attributed Reserves ................................................................................................................ 22
Additional Information Concerning Abandonment and Reclamation Costs ......................................................... 23
Tax Horizon ............................................................................................................................................................ 23
Costs Incurred ........................................................................................................................................................ 23
Drilling Activity ....................................................................................................................................................... 23
Planned Capital Expenditures ................................................................................................................................ 23
Production Estimates ............................................................................................................................................. 24
Production History ................................................................................................................................................. 24
Average Daily Production Volume .................................................................................................................... 24
Prices Received, Royalties Paid, Production Costs and Netback- Crude Oil ..................................................... 24
Prices Received, Royalties Paid, Production Costs and Netback- Natural Gas ................................................. 25
Prices Received, Royalties Paid, Production Costs and Netback- Combined .................................................... 25
Production Volume by Field................................................................................................................................... 25
2
Share Capital ........................................................................................................................................................25
Common Shares ..................................................................................................................................................... 25
Preferred Shares .................................................................................................................................................... 26
Dividend Policy .....................................................................................................................................................26
Escrowed Securities ..............................................................................................................................................26
Market for Securities ............................................................................................................................................26
Directors and Officers ...........................................................................................................................................27
Corporate Cease Trade Orders .............................................................................................................................. 29
Bankruptcies .......................................................................................................................................................... 29
Penalties or Sanctions ............................................................................................................................................ 29
Conflicts of Interest ............................................................................................................................................... 30
Audit Committee ..................................................................................................................................................30
Composition of the Audit Committee, Charter and Review of Services ................................................................ 30
Education and Experience of Members ................................................................................................................. 30
External Auditor Service Fees ................................................................................................................................ 31
Industry Conditions ..............................................................................................................................................32
Pricing and Marketing – Oil ................................................................................................................................... 32
Pipeline Capacity .................................................................................................................................................... 32
The North American Free Trade Agreement ......................................................................................................... 32
Provincial Royalties and Incentives ........................................................................................................................ 33
General ............................................................................................................................................................. 33
Alberta .............................................................................................................................................................. 33
British Columbia ............................................................................................................................................... 34
Land Tenure ........................................................................................................................................................... 35
Environmental Regulation ..................................................................................................................................... 36
Risk Factors ..........................................................................................................................................................36
Operational Risks ................................................................................................................................................... 36
Sour Natural Gas .................................................................................................................................................... 37
Fracing ................................................................................................................................................................... 37
Reserve Estimates .................................................................................................................................................. 37
Reserve Replacement ............................................................................................................................................ 38
Possible Failure to Realize Anticipated Benefits of Recent and Future Acquisitions ............................................. 38
Availability of Services ........................................................................................................................................... 38
Risks Associated with Acquisitions ........................................................................................................................ 38
Market Conditions ................................................................................................................................................. 38
Industry Regulation and Competition .................................................................................................................... 39
Volatility of Oil and Gas Prices and Markets .......................................................................................................... 39
Variations in Foreign Exchange Rates and Interest Rates ...................................................................................... 39
Price Volatility of Publicly Traded Securities .......................................................................................................... 40
Substantial Capital Requirements; Liquidity .......................................................................................................... 40
Issuance of Debt .................................................................................................................................................... 40
Environmental Concerns ........................................................................................................................................ 40
Abandonment and Reclamation Costs .................................................................................................................. 41
Third Party Credit Risk ........................................................................................................................................... 41
Delay in Cash Receipts and Credit Worthiness of Counterparties ......................................................................... 41
Dilution .................................................................................................................................................................. 41
Net Asset Value ...................................................................................................................................................... 41
Reliance on Management ...................................................................................................................................... 42
Permits and Licenses ............................................................................................................................................. 42
Title to Properties .................................................................................................................................................. 42
Aboriginal Claims ................................................................................................................................................... 42
Corporate Matters ................................................................................................................................................. 42
3
Failure to Maintain Listing of the Common Shares ............................................................................................... 42
Structure of the Corporation ................................................................................................................................. 42
Changes in Legislation ........................................................................................................................................... 42
Legal Proceedings And Regulatory Actions ...........................................................................................................43
Interest of Management and Others in Material Transactions .............................................................................43
Auditor, Transfer Agent and Registrar ..................................................................................................................43
Interest of Experts ................................................................................................................................................43
Material Contracts ................................................................................................................................................44
Additional Information .........................................................................................................................................44
4
DEFINITIONS
Unless the context indicates otherwise, the following terms shall have the meanings set out below when used in this Annual
Information Form. Certain other terms and abbreviations used herein, but not defined herein, are defined in NI 51-101 or the
COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the
COGE Handbook.
“2008 Bid” means the normal course issuer bid announced by the Corporation in June 2008 through the facilities of the TSXV
to acquire for cancellation up to 864,329 Common Shares;
“771129” means 771129 Alberta Ltd., a corporation organized under the ABCA and the Corporation’s wholly-owned
subsidiary;
“744997” means 744997 Alberta Ltd., a corporation organized under the ABCA and a predecessor to the Corporation by
amalgamation;
“ABCA” means the Business Corporations Act, R.S.A. 2000, c. B-9, as amended;
“AIF” means this Annual Information Form;
“Audit Committee” means the audit committee of the Corporation
“Board of Directors” or “Board” means the board of directors of the Corporation;
“Breaker” means Breaker Energy Ltd., a publicly traded oil and natural gas company acquired by NAL Oil & Gas Trust in
December 2009;
“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;
“Common Shares” means the common shares of the Corporation;
“Corinthian” means Corinthian Energy Corp. originally incorporated under the ABCA and amalgamated with a wholly-owned
subsidiary of the Corporation to form Breaker Resources Ltd.;
“Corinthian Acquisition” means the indirect acquisition by the Corporation on July 9, 2010 of all of the issued and
outstanding shares of Corinthian;
“Corinthian Acquisition Agreement” means the agreement entered into by the Corporation and Corinthian dated June 21,
2010 whereby the Corporation agreed to acquire all of the issued and outstanding common shares of Corinthian for
consideration of 0.4 Common Shares of the Corporation for every one common share of Corinthian for a total consideration
of approximately 16 million Common Shares;
“Corinthian Shares” means common shares of Corinthian;
“Corporation” or “Surge” means Surge Energy Inc., a corporation amalgamated under the ABCA;
“Credit Facility” means the $150 million extendible revolving term credit facility of the Corporation with a Canadian chartered
bank bearing interest at bank rates;
“Crystal Lake” means Crystal Lake Resources Inc. originally incorporated under the ABCA and amalgamated with a wholly-
owed subsidiary of the Corporation to form Breaker Resources Ltd;
“Crystal Lake Acquisition” means the indirect acquisition by the Corporation on July 19, 2010 of all of the issued and
outstanding shares of Crystal Lake;
5
“FT Units” means units issued pursuant to a private placement that took place in conjunction with the Recapitalization, with
each unit consisting of one Common Share issued on a “flow-through” basis in accordance with the Tax Act and one
Performance Warrant;
“NAFTA” means the North American Free Trade Agreement;
“NI 51-101” means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;
“Offering” means the private placement offering of 8,001,000 Subscription Receipts at a price of $5.25 per Subscription
Receipt completed of October 20, 2010;
“Partnership” means Zapata Limited Partnership, an Alberta limited partnership which was dissolved on January 2, 2011;
“Performance Warrant” means a Common Share purchase warrant entitling the holder to purchase one Common Share at a
price of $5.17 for a period of five years, issued pursuant to the private placement that took place in conjunction with the
Recapitalization;
“Preferred Shares” means the preferred shares of the Corporation;
“Recapitalization” means the change of officers and directors and the private placement of the Corporation conducted
pursuant to the Recapitalization Agreement;
“Recapitalization Agreement” means the reorganization and investment agreement dated March 24, 2010 among the
Corporation and P. Daniel O'Neil, Maxwell Lof, Daniel C. Brown and Paul Colborne;
“Sproule” means Sproule Associates Limited, independent oil and gas reservoir engineers;
“Sproule Report” means the independent engineering report dated February 29, 2012 and effective December 31, 2011
prepared by Sproule evaluating the oil, NGL and natural gas reserves attributable to the properties of the Corporation;
“Subscription Receipt Agreement” means the subscription receipt agreement dated October 20, 2010 between the
Corporation, Olympia Trust Company as escrow agent and a syndicate of underwriters governing the terms and conditions of
the Subscription Receipts;
“Subscription Receipts” means the subscription receipts of the Corporation that were issued pursuant to the Offering and the
Subscription Receipt Agreement;
“Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c.l. (5th Supp.), as amended, including the regulations promulgated
thereunder;
“Transitional Program” means the optional five-year transitional royalty program announced by the Alberta Government on
November 19, 2008 and November 24, 2008;
“TSX” means the Toronto Stock Exchange;
“TSXV” means the TSX Venture Exchange;
“Units” means units issued pursuant to a private placement that took place in conjunction with the Recapitalization, with
each unit consisting of one Common Share and one Performance Warrant;
“Valhalla Asset Acquisition” means the acquisition of the Valhalla Assets by the Corporation from the Vendor pursuant to the
Valhalla Purchase Agreement which was completed on November 1, 2010;
“Valhalla Assets” has the same meaning as is ascribed to the term “Assets” in the Valhalla Purchase Agreement;
6
“Valhalla Purchase Agreement” means the definitive agreement of purchase and sale dated September 22, 2010 between
the Corporation and the Vendor relating to the acquisition by the Corporation of the Valhalla Assets; and
“Vendor” means the vendors of the Valhalla Assets pursuant to the Valhalla Purchase Agreement.
7
ABBREVIATIONS AND CONVERSION
In this Annual Information Form, the abbreviations set forth below have the following meanings:
Oil and Natural Gas Liquids
Natural Gas
bbl
bbls
Mbbls
MMbbls
Mstb
bbl/d
NGLs
stb
Other
AECO
API
°API
BOE
BOE/d
m3
MBOE
$000s
M$
MM$
WTI
Barrel
Barrels
thousand barrels
million barrels
1,000 stock tank barrels
barrels per day
natural gas liquids
standard tank barrels
Mcf
MMcf
Mcf/d
MMcf/d
MMBtu
Bcf
GJ
thousand cubic feet
million cubic feet
thousand cubic feet per day
million cubic feet per day
million British Thermal Units
billion cubic feet
gigajoule
a natural gas storage facility located at Suffield, Alberta
American Petroleum Institute
an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a
specified gravity of 35.1° API or greater is generally referred to as light crude oil. Liquid petroleum with a
specified gravity of 25.8° to 35° API or greater is generally referred to as medium crude oil. Liquid petroleum
with a specified gravity of 25.7° API or lower is generally referred to as heavy crude oil.
barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas. BOEs may be misleading, particularly if
used in isolation. A BOE conversion ratio of 1 BOE for 6 Mcf is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead
barrel of oil equivalent per day
cubic metres
1,000 barrels of oil equivalent
thousands of dollars
thousands of dollars
millions of dollars
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of
standard grade
8
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS
Certain statements contained in this Annual Information Form constitute forward-looking statements. The use of any of the
words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” 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. The Corporation believes the expectations reflected in those forward-looking statements are reasonable, but no
assurance can be given that these expectations will prove to be correct. Such forward-looking statements included in this
Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual
Information Form.
In particular, this Annual Information Form may contain forward-looking statements pertaining to the following:
the size of the oil and natural gas reserves;
the performance characteristics of the Corporation’s oil and natural gas properties;
oil and natural gas production levels;
projections of market prices and costs;
supply and demand for oil and natural gas;
expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and
development;
treatment under governmental regulatory regimes and tax laws; and
capital expenditure programs and the allocation of such capital;
With respect to forward looking statements contained in this Annual Information Form, the Corporation has made
assumptions regarding:
oil and natural gas production levels;
commodity prices;
availability of labour and drilling equipment;
timing and amount of capital expenditures;
general economic and financial market conditions; and
government regulation in the areas of taxation, royalty rates and environmental protection;
The 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:
liabilities inherent in oil and natural gas operations;
volatility in market prices for oil and natural gas;
uncertainties associated with estimating oil and natural gas reserves;
competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;
geological, technical, drilling, completion and processing problems;
changes in legislation, including changes in tax laws and incentive programs relating to the oil and gas industry; and
incorrect assessments of the value of acquisitions and exploration and development programs;
the other factors discussed under “Risk Factors”.
Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied
assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably
produced in the future.
Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this
Annual Information Form are expressly qualified by this cautionary statement. The Corporation does not undertake any
obligation to publicly update or revise any forward-looking statements other than as required under applicable securities
laws.
9
General
SURGE ENERGY INC.
The Corporation is a Calgary, Alberta based, public company whose Common Shares are listed on the TSX under the symbol
“SGY”. The Corporation was incorporated on January 26, 1998 under the ABCA as “Zapata Capital Inc.” and completed its
initial public offering of 1,000,000 Common Shares on August 21, 1998 under the Alberta Stock Exchange’s junior capital pool
program. On June 18, 1999, the Corporation acquired all of the issued and outstanding shares of 744997, a private
corporation, as the Corporation’s major transaction under the Alberta Stock Exchange’s junior capital pool program and
amalgamated with 744997 on that date under the name “Zapata Energy Corporation”. On June 25, 2010, the Corporation
changed its name to “Surge Energy Inc.” by way of articles of amendment. On December 31, 2010, the Corporation
amalgamated with its wholly owned subsidiary, Breaker Resources Ltd. by way of articles of amalgamation and continued
under the name “Surge Energy Inc.”. On October 21, 2011, the Common Shares commenced trading on the TSX and ceased
trading on the TSXV.
The Corporation is an independent Calgary, Alberta based oil and gas company which acquires interests in petroleum and
natural gas rights, that explores for, develops, produces and markets petroleum and natural gas reserves primarily in Western
Canada and the Northern United States. The Corporation’s strategy for growth is based on positioning the Corporation in
early stage oil resource plays that have the following key criteria: significant oil in place per section with low recovery factor
to date, significant undeveloped land, available infrastructure, high working interest, operatorship, all-season access and
drilling inventory that provides a definable high rate of return. The Corporation plans to utilize its proven expertise and
experience to build core areas which can deliver top quartile corporate performance.
Management of the Corporation believes in controlling the timing and costs of its projects wherever possible. Accordingly,
the Corporation seeks to become the operator of its properties. Further, to minimize competition within its geographic areas
of interest, the Corporation strives to maximize its working interest ownership in its properties.
To achieve sustainable and profitable growth, the Corporation intends to maintain a balance between exploration,
exploitation, development drilling for oil and gas reserves, and making asset and corporate acquisitions that meet the
Corporation’s business parameters.
The Corporation has the following direct and indirect wholly-owned subsidiaries: 771129 Alberta Ltd., 1413942 Alberta Ltd.,
Surge Energy USA Inc. (North Dakota) and Surge Oil Inc. (Alberta). The Corporation, 771129 Alberta Ltd. and 1413942 Alberta
Ltd. are the general partners of Surge General Partnership. The corporate structure of the Corporation and its subsidiaries is
as set forth in the diagram below:
10
The head office of the Corporation is located at 2100, 635 – 8th Avenue S.W., Calgary, Alberta T2P 3M3. The registered office
of the Corporation is located at 1900, 215 – 9th Avenue S.W., Calgary, Alberta, T2P 1K3.
General
DEVELOPMENT OF THE BUSINESS
The Corporation is an independent Calgary, Alberta based oil and gas company which acquires interests in petroleum and
natural gas rights, that explores for, develops, produces and markets petroleum and natural gas reserves primarily in Western
Canada and the Northern United States. The Corporation’s strategy for growth is based on positioning the Corporation in
early stage oil resource plays that have the following key criteria: significant oil in place per section with low recovery factor
to date, significant undeveloped land, available infrastructure, high working interest, operatorship and drilling inventory that
provides a definable high rate of return. The Corporation plans to utilize its proven expertise and experience to build core
areas which can deliver top quartile corporate performance.
Significant developments of the Corporation over the last three completed financial years are as set forth below:
2009
Between December 2009 and January 2010, the Corporation completed a private placement of an aggregate total of
1,344,399 units and 757,000 Common Shares issued on a “flow-through” basis in accordance with the Tax Act. Each unit
consisted of one Common Share and one Common Share purchase warrant (with each whole warrant exercisable into one
Common Share at a price of $4.00 per Common Share until December 23, 2010).
In 2009, the Corporation drilled or participated in drilling 17 gross (13.6 net) wells resulting in four gross (0.6 net) gas wells, 11
gross (11 net) oil wells, one gross (one net) standing well and one gross (one net) abandoned well. In 2009, the Corporation
purchased and cancelled 36,000 Common Shares pursuant to the 2008 Bid at an average cost of $1.83 per Common Share.
2010
On March 24, 2010, the Corporation entered in the Recapitalization Agreement. On April 13, 2010, the then existing directors
and officers of the Corporation resigned and were replaced by the current directors and officers of the Corporation, with the
exception of Murray Smith and Colin Davies, who subsequently joined the Board. The Corporation concurrently completed a
non-brokered private placement pursuant to which it issued 1,787,500 Common Shares at a price of $4.40 per Common
Share, 1,394,317 Units at a price of $4.40 per Unit and 681,819 FT Units at a price of $4.40 per FT Unit, for total proceeds of
approximately $17.0 million. Each Unit consists of one Common Share and one Performance Warrant entitling the holder to
purchase one Common Share at a price of $5.17 for a period of five years, subject to certain conditions. Each FT Unit consists
of one Common Share issued on a “flow-through” basis in accordance with the Tax Act and one Performance Warrant.
All of the Common Shares, Units and FT Units issued pursuant to the non-brokered private placement were subject to a
contractual escrow arrangement under which one-third of the securities were released from escrow each six months
following the date of issuance. All such escrowed securities have now been released from escrow.
Subsequent to the Recapitalization and concurrent non-brokered private placement, the Corporation changed its name to
Surge Energy Inc., completed three equity bought deal financings (details outlined below), completed three private company
acquisitions, one asset acquisition, increased its bank line from $50 to $90 million, graduated to the TSX and increased its
proved plus probable reserves from 9.9 to 21.2 million BOE.
As mentioned above, the Corporation completed two equity bought deal financings in 2010, subsequent to the
Recapitalization. On May 5, 2010, the Corporation completed a short form prospectus offering of 6,945,000 Common Shares
at a price of $7.20 per Common Share for aggregate gross proceeds of approximately $50,004,000. In conjunction with the
Valhalla Asset Acquisition, the Corporation issued an aggregate of 8,001,000 Subscription Receipts at a price of $5.25 per
Subscription Receipt for gross proceeds of $42,005,250.
11
During 2010, the Corporation drilled a total of 22 gross (21.5 net) wells resulting in 10 development wells in southeast
Alberta, three horizontal multi-frac wells at Windfall, five horizontal multi-frac wells at Waskada, two water injectors, and two
exploratory wells for an overall success rate of 91 percent.
The Recapitalization
On March 24, 2010, the Corporation entered into the Recapitalization Agreement. The Recapitalization Agreement provided
for the transactions described immediately above.
New Management Group
In conjunction with the completion of the non-brokered private placement on April 13, 2010, the then existing directors and
officers of the Corporation were replaced by the current directors and officers of the Corporation, with the exception of
Murray Smith and Colin Davies, who subsequently joined the Board. The names and principal occupations of each of such
directors and officers are set forth in the material change report of the Corporation dated March 29, 2010, which is
incorporated by reference in this AIF.
Each member of the Board of Directors, with the exception of P. Daniel O’Neil who is the President and Chief Executive
Officer of the Corporation and James Pasieka, who is a partner of Heenan Blaikie LLP, which law firm provides legal services to
the Corporation, is independent of the Corporation as defined under National Instrument 58-101 – Disclosure of Corporate
Governance Practices. The Audit Committee of the Board of Directors is comprised of Keith Macdonald, Murray Smith and
Peter Bannister, each of whom is independent of the Corporation as defined under National Instrument 52-110 – Audit
Committees.
The Recapitalization is described in greater detail in the material change reports of the Corporation dated March 29, 2010
and April 16, 2010.
Subsequent to the Re capitalization, Murray Smith and Colin Davies joined the Board of Directors of the Corporation (on June
25 and July 9, 2010 respectively).
Prospectus Financing
On May 5, 2010, the Corporation completed a short form prospectus offering of 6,945,000 Common Shares at a price of $7.20
per Common Share for aggregate gross proceeds of approximately $50,004,000. The financing was concluded on a bought
deal basis with a syndicate of underwriters led by National Bank Financial Inc. and including FirstEnergy Capital Corp.,
Macquarie Capital Markets Canada Ltd., GMP Securities L.P., CIBC World Markets Inc., Cormark Securities Inc., Peters & Co.
Limited and Wellington West Capital Markets Inc. Proceeds of the offering were used for the expansion of the capital
program, repayment of debt and general corporate purposes.
Corinthian and Crystal Lake Acquisition
On July 9, 2010, pursuant to the Corinthian Acquisition Agreement, the Corporation completed the Corinthian Acquisition.
The Corinthian Acquisition was approved by the shareholders of Corinthian. Upon completion of the Corinthian Acquisition,
one director of Corinthian, Colin Davies joined the Board of Directors of the Corporation. The Corinthian Acquisition
Agreement, among other things, provided for a mutual non-completion fee of up to $3.5 million in the event the Corinthian
Acquisition was not completed in certain circumstances.
Through the Corinthian Acquisition, the Corporation acquired light oil and natural gas reserves, which included two high
impact light oil core areas: one in Alberta and one in southwest Manitoba. The producing properties were greater than 90
percent operated with high working interests, had 3D & 2D seismic coverage, maintained control of key producing
infrastructure and were associated with nearly 80,000 acres of net undeveloped land.
12
In addition to the Corinthian Acquisition, on July 19, 2010 the Corporation also completed an acquisition of a private oil and
gas company, Crystal Lake Resources Ltd, for total consideration of 288,639 Common Shares. The assets that were acquired
pursuant to the Crystal Lake Acquisition were producing approximately 40 BOE per day at the time of the Crystal Lake
Acquisition, are synergistic with the Corporation’s southern Alberta assets and provided the Corporation with five unbooked
horizontal well locations targeting oil in the Sawtooth Formation.
The Corinthian Acquisition and the Crystal Lake Acquisition are described in greater detail in the material change report of the
Corporation dated June 23, 2010. In addition, please see the business acquisition report of the Corporation dated September
22, 2010 for further particulars concerning the Corinthian Acquisition.
Name Change
At a meeting of Shareholders held on June 25, 2010, the Corporation changed its name from Zapata Energy Corporation to
Surge Energy Inc. and the Common Shares started trading on the TSXV under the ticker symbol “SGY” on June 30, 2010.
Valhalla Asset Acquisition
On November 1, 2010, the Corporation completed the acquisition of the Valhalla Assets from the Vendor for total
consideration of $75 million, subject to adjustments. The Valhalla Assets consisted of a high working interest, operated
property producing approximately 726 BOE per day in the Valhalla South area located in western Alberta.
For further particulars regarding the Valhalla Asset Acquisition, see the material change report of the Corporation dated
October 1, 2010 and the business acquisition report dated November 10, 2010.
Subscription Receipt Offering
In conjunction with the Valhalla Asset Acquisition, the Corporation completed the Offering, pursuant to which the
Corporation issued an aggregate of 8,001,000 Subscription Receipts at a price of $5.25 per Subscription Receipt for gross
proceeds of $42,005,250. Pursuant to the Offering, the Subscription Receipts were offered by way of private placement in the
provinces of British Columbia, Alberta, Saskatchewan, Manitoba, Ontario and Nova Scotia.
Each Subscription Receipt entitled the holder thereof to receive, for no additional consideration and without further action,
one Common Share, upon the earlier to occur of: (i) four months and a day from the closing date of the Offering, and (ii) the
date that a receipt was issued for a prospectus qualifying the distribution of the Common Shares underlying the Subscription
Receipts. The escrowed funds were released from escrow on November 1, 2010 following the satisfaction of the escrow
release conditions pursuant to the Subscription Receipt Agreement. Immediately following the closing of the Valhalla Asset
Acquisition, the escrowed funds were used to pay down a portion of the outstanding amount of the Credit Facility that was
drawn down to fund the balance of the purchase price for the Valhalla Assets on this date.
On November 22, 2010, a receipt was issued by the securities commissions in all Province of Canada, except Québec,
qualifying the distribution of the Common Shares underlying the Subscription Receipts and such Common Shares were issued
in accordance with the terms of the Subscription Receipts and the Subscription Receipt Agreement.
The Valhalla Asset Acquisition and the Offering are described in greater detail in the material change report of the
Corporation dated October 1, 2010 and the business acquisition report dated November 10, 2010.
2011 and 2012 to date
USA Acquisitions
On March 30, 2011 and May 13, 2011, respectively, the Corporation completed two light oil asset acquisitions in North
Dakota through its wholly owned subsidiary, Surge Energy USA Inc. Through the two acquisitions, the Corporation acquired
approximately 100 barrels per day (2010 exit rate) of light oil production, 6,000 net acres of highly prospective land in the
Spearfish light oil resource play and greater than 100,000 acres of other high working interest, undeveloped land for total
consideration of $20.9 million in cash.
13
Credit Line
On May 16, 2011, the Corporation confirmed an increase in the Credit Facility from $90 million to $120 million. Subsequently,
on September 12, 2011, the Corporation confirmed a further increase to the Credit Facility from $120 million to $150 million.
Prospectus Financing
On October 12, 2011, the Corporation completed a short form prospectus bought deal financing pursuant to which 6,897,000
Common Shares were issued at a price of $8.70 per Common Share for aggregate gross proceeds of approximately $60
million. Net proceeds from the financing were used to temporarily reduce bank indebtedness owing under the Credit Facility,
and to use the availability created thereunder to fund ongoing exploration and development activities, potential land and
asset acquisitions and general corporate purposes.
TSX Graduation
On October 21, 2011, the Common Shares commenced trading on the facilities of the TSX after the Corporation graduated to
the TSX from the TSXV.
Pradera Acquisition
On December 15, 2011, the Corporation entered into an agreement (the “Pradera Acquisition Agreement”) with Pradera
Resources Inc. (“Pradera”) dated effective December 15, 2011 providing for the acquisition of all of the issued and
outstanding shares of Pradera (the “Pradera Acquisition”). The Pradera Acquisition closed on January 6, 2012. For further
particulars regarding the Pradera Acquisition, see the material change report of the Corporation dated December 19, 2011.
The reserves acquired in the Pradera Acquisition are not included in the 2011 reserve data disclosed in this AIF, as the
acquisition closed in 2012.
The completion of the Pradera Acquisition added approximately 1,200 bbls per day (100 percent light oil) of Slave
Point/Gilwood light oil assets to the Corporation’s portfolio. Total consideration of the acquisition was approximately $106
million, consisting of 7.9 million Common Shares and approximately $33 million in cash including the assumption of net debt.
Through the Pradera Acquisition, the Corporation acquired light oil production in its early stage of primary development.
Current production is 99 percent operated, has an average working interest of approximately 96 percent and consists of
approximately 900 bbls per day from the Slave Point Formation and 300 bbls per day from the Gilwood Formation. As of
October 31, 2011, Pradera’s independent reserves report, as prepared by Sproule, recognized Total Proved Plus Probable
Reserves of 4.57 million barrels (100 percent light oil) which did not include any potential incremental oil recovery from
waterflood opportunities.
The Pradera Acquisition was considered to be a “significant acquisition” under applicable securities laws. The Corporation will
be filing a business acquisition report with respect thereto within the prescribed time period.
Corporate Strategy
DESCRIPTION OF THE BUSINESS
The Corporation’s business plan is to build a company that targets per share growth through the early identification, capture,
and cost-effective exploitation of high impact oil resource plays. To accomplish this, the Corporation intends to place high
priority on positioning the Corporation in early stage oil resource plays that have the following key criteria: significant oil in
place per section with a low recovery factor to date, significant undeveloped land, available infrastructure, high working
interest, operatorship and that provide a definable high rate of return drilling inventory. The Corporation plans to utilize its
proven expertise and experience to build core areas which can deliver top quartile corporate performance.
14
To achieve sustainable and profitable growth, the Corporation intends to utilize its skills in identifying and capturing oil
resource plays and then cost effectively exploiting those reserves. To achieve this, the Corporation may make asset and
corporate acquisitions or enter into agreements that meet the Corporation’s business parameters.
Management of the Corporation believes in controlling the timing and costs of its projects wherever possible. Accordingly,
the Corporation seeks to become the operator of its properties. Further, to minimize competition within its geographic areas
of interest, the Corporation strives to maximize its working interest ownership in its properties.
In reviewing potential drilling or acquisition opportunities, the Corporation gives consideration to the following criteria:
(a)
(b)
(c)
(d)
risk capital to secure or evaluate the opportunity;
the potential return on the project, if successful;
the likelihood of success; and
risked return versus cost of capital.
In general, the Corporation pursues a portfolio approach in developing a large number of opportunities with a balance of risk
profiles in an attempt to generate sustainable high levels of growth. It should be noted that the Board of Directors of the
Corporation may, in its discretion, approve asset or corporate acquisitions or investments that do not conform to the
guidelines discussed above based upon the Board’s consideration of the qualitative aspects of the subject properties,
including risk profile, technical upside, reserve life and asset quality.
In addition, the management team of the Corporation, as described below under “Directors and Officers”, is continually
assessing the assets and operations of the Corporation, including its existing land base, facilities, reserves, prospects and
personnel. While the Corporation has prepared a budget for 2012 based on guidance for such year, the Corporation may
further evaluate its existing reserves, drilling prospects, prevailing commodity prices and capital expenditure program, among
other items, and may change its budget as the year progresses.
The Corporation currently plans to pursue the development of its proven and probable undeveloped reserves within the next
two years through ordinary course capital expenditures. However, the Corporation may choose to accelerate or delay
development depending on a number of circumstances, including the existence of higher priority expenditures and prevailing
commodity prices and cash flow.
Competition
The oil and natural gas industry is competitive in all its phases. 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 resource companies which have greater financial resources, staff and facilities than those
of the Corporation. Competitive factors in the distribution and marketing of oil and natural gas include price and methods
and reliability of delivery. The Corporation believes that its competitive position is equivalent to that of other oil and gas
issuers of similar size and at a similar stage of development.
Seasonal Factors
The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to
be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
Environmental Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and
federal legislation. Compliance with such legislation can require significant expenditures or result in operational restrictions.
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, all of which might have a significant negative impact on
15
earnings and overall competitiveness. See below under the headings “Industry Conditions - Environmental Regulation” and
“Risk Factors – Environmental Concerns”.
The Corporation is obligated to abandon, retire and reclaim wells and wellsites in compliance with applicable environmental
laws and regulations. As of December 31, 2011, the Corporation has recorded an asset retirement obligation of $37.5 million.
The Corporation anticipates that the expenditures necessary to satisfy the asset retirement obligation will be incurred over a
period of 50 years, with the majority of the expenditures being incurred from years one to 28. Other than asset retirement
obligations and ordinary course operational expenditures necessary to ensure environmental compliance, the Corporation is
not aware of any environmental protection requirement that will impact its capital expenditures, earnings or competitive
position in a manner disproportionate to that of its peers in its area of operations.
Personnel
As at December 31, 2011, the Corporation had 58 head office employees and three field employees.
PRINCIPAL PRODUCING PROPERTIES
The Corporation’s principal oil and natural gas producing properties are located in Alberta and southwest Manitoba. A
description of those properties, as at December 31, 2011, is provided below.
Valhalla South, Western Alberta
The Valhalla South property is located in north Western Alberta, approximately 40 kilometers northwest of Grand Prairie
(TWP 74, Range 8, W6M). This operated property consists of an average working interest of approximately 94 percent in
approximately 9,920 gross (9,306 net) undeveloped acres as at December 31, 2011. The majority of production in this
property was from the new horizontal oil wells producing from an extensive tight sand, with up to 50 meters of gross light oil
pay in the Triassic Doig Formation. The Valhalla Assets included 16 gross (12.7 net) producing vertical wells, and 7 gross (6.2
net) producing horizontal wells as at December 31, 2011.
The Corporation plans to drill approximately 7 gross (5.46 net) horizontal multi-frac wells at Valhalla South in the Doig
Formation in 2012. At December 31, 2011 the Corporation has identified approximately 40 gross (30.9 net) horizontal multi-
frac oil wells.
Windfall, Western Alberta
The Corporation’s Windfall assets are located in Western Alberta near Whitecourt (TWP 59, Range 15, W5M). At December
31, 2011, this operated property consisted of approximately 20,960 gross (20,960 net) undeveloped acres with a working
interest of 100 percent. The production in this property was from nine horizontal multi-frac wells and nine vertical wells. The
Windfall battery was upgraded in the first quarter of 2011 to accommodate the new volumes.
At December 31, 2011, the Corporation identified over 47 gross (47 net) horizontal multi-frac drilling locations. The
Corporation plans to implement a waterflood pilot on the core lands in second quarter of 2012.
Waskada, Pierson and Goodlands, Southwest Manitoba
In southwest Manitoba, the Corporation has accumulated a land position at Waskada, Pierson and Goodlands, providing it
with access to the Spearfish (Amaranth) light oil resource play.
At December 31, 2011, the Corporation had approximately 9,874 gross (9,874 net) undeveloped acres of land across
Waskada, Pierson and Goodlands. Additionally, the Corporation identified approximately 124 gross (111 net) horizontal
multi-frac drilling locations with an average working interest of approximately 90 percent. As of December 31, 2011, the
Waskada field was producing from 14 new horizontal multi frac wells. Of the 14 wells drilled as of December 31, 2011, 5 gross
(5 net) were drilled in the fourth quarter of 2010 and 9 gross (9 net) wells were drilled in the third and fourth quarters of
2011.
16
The Corporation successfully drilled, completed, and tied-in 9 gross (9 net) Spearfish horizontal multi-frac oil wells and 1
vertical water disposal well at Waskada during the third and fourth quarters in 2011. In addition, a new 100 percent working
interest oil treating and water disposal facility, along with a 4.2 kilometer gathering system were constructed and
commissioned during the same time period. This new infrastructure will significantly reduce operating costs and increase the
netbacks of the Corporation’s Spearfish oil production. There are 12 gross (12 net) Spearfish horizontal multi-frac wells
budgeted for 2012. Plans are also in place to commence a waterflood pilot in the first quarter of 2013.
Silver Lake, South East Alberta
At Silver Lake, in South East Alberta, the Corporation held approximately 67,425 gross (65,440 net) acres of undeveloped land
at December 31, 2011. The Corporation has interests in 158 gross (151 net) oil wells and 22 gross (18 net) gas wells producing
from the Dina, Lloydminster, Cummings, Rex, Sparky and Viking Formations. Another 117 gross (102 net) shut-in wells are
being evaluated for optimization and recompletion potential. In addition, the Corporation operates seven oil batteries and an
oil blending facility, providing a strong infrastructure base for future development in the area. The Corporation continues to
add to its land base through acquisitions and farmin agreements in the area.
The Corporation completed a successful nine well drilling program in 2011 at Silver Lake (100 percent working interest). The
Corporation plans to apply horizontal drilling technologies in 2012 to take advantage of horizontal oil well royalty holidays
now available, as well as to optimize pool depletion strategies. The Corporation will be expanding its existing pressure
maintenance schemes and implementing new waterflood projects. Additional enhanced recovery methods will also be
evaluated.
In addition to the Corporations assets at Silver Lake, Surge has various working interests in 72,643 gross (68,064 net) acres of
undeveloped land in South East Alberta. The Corporation has 31 gross (27 net) gas wells and 4 gross (4 net) oil wells in the
area producing from the Belly River, Bow Island, Mannville and Mississippian Formations. Another 23 gross (17 net) wells are
shut-in and are being assessed for production opportunities.
STATEMENT OF RESERVES DATA
In accordance with NI 51-101 – Standards for Disclosure for Oil and Gas Activities, Sproule Associates Limited prepared the
Sproule Report. The Sproule Report evaluated, as at December 31, 2011, the oil, NGL and natural gas reserves attributable to
the properties of the Corporation. The Sproule Report is dated February 29, 2012.
The tables below are a summary of the oil, NGL and natural gas reserves attributable to the properties of the Corporation and
the net present value of future net revenue attributable to such reserves as evaluated in the Sproule Report based on
forecast price and cost assumptions. The tables summarize the data contained in the Sproule Report and, as a result, may
contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add
exactly.
The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general
and administrative costs, but after providing for estimated royalties, production costs, development costs, other income,
future capital expenditures and well abandonment costs for only those wells assigned reserves by Sproule. It should not be
assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by
Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for
future production and other matters are summarized herein. The recovery and reserve estimates of oil, NGL and natural gas
reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein.
The Sproule Report is based on certain factual data supplied by the Corporation and Sproule’s opinion of reasonable practice
in the industry. The extent and character of ownership and all factual data pertaining to petroleum properties and contracts
(except for certain information residing in the public domain) were supplied by the Corporation to Sproule. Sproule accepted
this data as presented and neither title searches nor field inspections were conducted.
17
Summary of Oil and Gas Reserves – Forecast Prices and Costs
Net Present Value of Future Net Revenue – Forecast Prices and Costs
18
Light and Medium Crude OilHeavy Crude OilNatural Gas LiquidsNatural GasLight and Medium Crude OilHeavy Crude OilNatural Gas LiquidsNatural GasMbblsMbblsMbblsMMcfMbblsMbblsMbblsMMcfProvedDeveloped Producing3,848.8 2,224.1 648.1 25,924.0 3,127.0 1,828.8 441.7 22,941.0 Developed Non-Producing228.0 260.4 98.7 2,965.0 189.7 215.9 66.2 2,503.0 Undeveloped4,097.3 302.3 726.5 19,641.0 3,241.5 241.7 526.5 16,125.0 Total Proved8,174.1 2,786.8 1,473.3 48,530.0 6,558.2 2,286.4 1,034.4 41,569.0 Probable4,847.3 1,008.1 904.4 29,548.0 3,746.3 819.7 605.4 24,526.0 Total Proved plus Probable13,021.4 3,794.9 2,377.7 78,078.0 10,304.6 3,106.1 1,639.8 66,095.0 Gross ReservesNet Reserves($M)0%5%10%15%20%ProvedDeveloped Producing399,597 319,641 269,838 235,575 210,478 Developed Non-Producing35,125 28,018 23,134 19,605 16,952 Undeveloped235,772 171,790 131,284 103,668 83,776 Total Proved670,494 519,450 424,256 358,848 311,206 Probable477,011 256,964 163,365 114,376 85,131 Total Proved plus Probable1,147,505 776,414 587,621 473,224 396,336 ($M)0%5%10%15%20%ProvedDeveloped Producing383,967 309,303 262,607 230,285 206,460 Developed Non-Producing26,253 21,212 17,777 15,302 13,440 Undeveloped175,210 125,081 93,365 71,789 56,301 Total Proved585,430 455,597 373,750 317,376 276,201 Probable354,365 189,744 119,807 83,230 61,404 Total Proved plus Probable939,795 645,340 493,557 400,606 337,605 Before Future Income Tax Expenses and Discounted atAfter Future Income Tax Expenses and Discounted atProvedDeveloped ProducingDeveloped Non-ProducingUndevelopedTotal ProvedProbableTotal Proved plus Probable25.24 17.64 22.54 Discounted at 10%/year ($/BOE)29.26 26.02 19.60 Unit Value before Income Tax
Additional Information Concerning Future Net Revenue – Forecast Prices and Costs (Undiscounted)
Future Net Revenue by Production Group – Forecast Prices and Costs
Notes:
(1)
(2)
(3)
Including solution gas and other by-products.
Including by-products, but excluding solution gas from oil wells.
Based on net reserves volumes.
Pricing Assumptions – Forecast Prices and Costs
Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2011 in the Sproule
Report in estimating reserves data using forecast prices and costs. The weighted average historical prices received by the
Corporation for 2011 are also reflected in the table below.
19
(Undiscounted) ($M)RevenueRoyaltiesOperating CostsDevelopment CostsAbandonment and Other costsFuture net revenue before income taxesFuture income taxesFuture net revenue after income taxesTotal Proved1,422,035 257,520 365,612 115,410 12,999 670,494 85,063 585,430 Total Proved plus Probable2,399,142 445,567 642,257 140,143 23,671 1,147,504 207,709 939,796 ProvedLight and Medium Crude Oil (1)Heavy OilNatural Gas (2)Proved plus ProbableLight and Medium Crude Oil (1)Heavy OilNatural Gas (2)Per Unit Future Net Revenue Before Income Taxes and Discounted at 10%(3) ($BOE)Future Net Revenue Before Income Taxes and Discounted at 10% ($M)319,325 12,401 452,698 21,953 24.95 8.40 22.67 8.24 92,531 36.54 112,971 32.90 Natural GasYearWTI Cushing Oklahoma 40˚ API (US$/bbl)Edmonton Par Price 40˚ API ($/bbl)Cromer Medium 29.3˚ API ($/bbl)AECO Gas Price ($/MMBtu)Pentanes plus FOB Field Gate ($/bbl)Butanes FOB Field Gate ($/bbl)Inflation rates (%/Yr)Exchange rate ($US/$Cdn)2011 (Surge Actual)95.0095.1687.863.72104.1270.931.51.01201298.0796.8790.093.16103.5772.202.01.01201394.9093.7587.193.78100.2369.872.01.01201492.0090.8984.524.1397.1767.742.01.01201597.4296.2389.505.53102.8971.732.01.01201699.3798.1691.295.65104.9473.162.01.012017101.35100.1293.115.77107.0474.632.01.012018103.38102.1294.985.90109.1876.122.01.012019105.45104.1796.886.01111.3777.642.01.012020107.56106.2598.816.14113.5979.192.01.012021109.71108.38100.796.27115.8780.782.01.01Medium and Light Crude OilNGL
Reconciliation of Changes in Reserves
The following table sets forth a reconciliation of the Corporation’s gross reserves as at December 31, 2011, derived from the
Sproule Report using forecast prices and cost estimates, reconciled to the gross reserves of the Corporation as at December
31, 2010. The additional reserves associated with royalty interest reserves, representing 3,715.3 MBOE and 6,140.6 MBOE on
a proved and proved plus probable basis, respectively, are not included in the following tables.
20
Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasBOE(Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)ProvedBalance at December 31, 20104,519.3 2,955.3 843.3 36,248.0 14,359.2 Extensions4,325.1 367.2 869.1 23,724.7 9,515.5 Technical Revisions and Improved Recovery(101.3) (93.6) 68.3 (610.3) (228.3) Acquisitions241.0 - - 6.0 242.0 Dispositions(45.0) - (199.0) (5,680.0) (1,190.7) Production(765.0) (442.1) (108.4) (5,158.4) (2,175.2) Balance at December 31, 20118,174.1 2,786.8 1,473.3 48,530.0 20,522.5 Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasBOE(Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)ProbableBalance at December 31, 20102,328.5 1,308.3 397.2 16,920.0 6,854.0 Extensions2,768.7 186.1 487.6 13,720.5 5,729.2 Technical Revisions and Improved Recovery(237.9) (486.3) 92.6 1,096.5 (448.8) Acquisitions- - - - - Dispositions(12.0) - (73.0) (2,189.0) (449.8) Balance at December 31, 20114,847.3 1,008.1 904.4 29,548.0 11,684.6 Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasBOE(Mbbls)(Mbbls)(Mbbls)(MMcf)(MBOE)Proved plus ProbableBalance at December 31, 20106,847.8 4,263.6 1,240.5 53,168.0 21,213.2 Extensions7,093.8 553.3 1,356.7 37,445.2 15,244.7 Technical Revisions and Improved Recovery(339.2) (579.9) 160.9 486.2 (677.2) Acquisitions241.0 - - 6.0 242.0 Dispositions(57.0) - (272.0) (7,869.0) (1,640.5) Production(765.0) (442.1) (108.4) (5,158.4) (2,175.2) Balance at December 31, 201113,021.4 3,794.9 2,377.7 78,078.0 32,207.0
ADDITIONAL INFORMATION RELATING TO RESERVES DATA
Undeveloped Reserves
The following table sets forth the volumes of proved undeveloped reserves that were first attributed in each of the three
most recent financial years and, in the aggregate, before that time:
The following table sets forth the volumes of probable undeveloped reserves that were first attributed in each of the three
most recent financial years and, in the aggregate, before that time:
Proved undeveloped reserves are generally those reserves related to infill wells that have not yet been drilled or wells further
away from gathering systems requiring relatively high capital to bring on production. Probable undeveloped reserves are
generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to
production. This also includes the probable undeveloped wedge from the proved undeveloped locations.
The Corporation currently plans to pursue the development of its proven and probable undeveloped reserves within the next
two years through ordinary course capital expenditures. However, the Corporation may choose to delay development
depending on a number of circumstances, including the existence of higher priority expenditures and prevailing commodity
prices and cash flow.
Significant Factors or Uncertainties Affecting Reserves Data
The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological,
geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing
development activities and production performance becomes available and as economic conditions impacting oil and gas
prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and
economic conditions.
As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed
and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes
in well performance, prices, economic conditions and governmental restrictions.
Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential
science. As a result, subjective decisions, new geological or production information and a changing environment may impact
21
Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasProved(Mbbls)(Mbbls)(Mbbls)(MMcf)Prior to 2009697.0 84.9 36.5 4,042.9 2009- 254.7 2.5 103.0 20101,201.5 84.6 263.3 6,839.0 20113,343.7 302.3 721.5 19,281.0 Light and Medium Crude OilHeavy OilNatural Gas LiquidsNatural GasProbable(Mbbls)(Mbbls)(Mbbls)(MMcf)Prior to 20091,220.5 233.6 151.5 9,164.3 2009- 51.8 23.8 504.0 20101,023.9 236.4 136.2 3,932.0 20112,269.7 161.2 398.0 11,128.0
these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir
performance. Such revisions can be either positive or negative.
Future Development Costs
The table below sets out the total development costs deducted in the estimation in the Sproule Report of future net revenue
attributable to proved reserves and proved plus probable reserves (using forecast prices and costs).
The Corporation has four sources of funding available to finance its capital expenditure programs: internally generated cash
flow from operations, funds raised from the sale of non-core assets, debt financing when appropriate and new issues of
Common Shares, if available on favourable terms. The Corporation expects to fund the above future development costs
primarily through internally generated cash flow, funds raised from the sale of non-core assets and debt. There can be no
guarantee that the Board of Directors will allocate funding to develop all of the reserves attributed in the Sproule Report.
Failure to develop those reserves could have a negative impact on the Corporation’s future cash flow.
Oil and Gas Wells
OTHER OIL AND GAS INFORMATION
The following table sets forth the number and status of the Corporation's wells effective December 31, 2011.
Properties with no Attributed Reserves
The following table summarizes, effective December 31, 2011, the gross and net acres of unproved properties in which the
Corporation has an interest and also the number of net acres for which the Corporation's rights to explore, develop or exploit
will, absent further action, expire within one year.
22
Proved Reserves ($M)Proved plus Probable Reserves ($M)201262,752 72,752 201350,935 62,318 20141,669 4,428 201554 525 Remaining Years- 120 Total Undiscounted115,410 140,143 Forecast Prices and CostsGrossNetGrossNetGrossNetGrossNetAlberta252 208.89 160 116.04 302 250.79 172 132.45 Manitoba23 23.00 - - 12 12.00 - - British Columbia- - - - - - 1 0.54 North Dakota18 5.34 - - 9 0.65 - - Total293 237.23 160 116.04 323 263.44 173 132.99 OilNatural GasOilNatural GasProducing WellsNon-Producing Wells
Additional Information Concerning Abandonment and Reclamation Costs
The Corporation typically estimates well abandonment costs area by area. Such costs are included in the Sproule Report as
deductions in arriving at future net revenue. The expected total abandonment costs, net of estimated salvage value, included
in the Sproule Report for 271.98 net wells under the proved reserves category is $13.1 million undiscounted ($4.2 million
discounted at 10%), of which a total of $0.9 million is estimated to be incurred in 2012, 2013 and 2014. This estimate does not
include expected reclamation costs for surface leases. The Corporation will be liable for its share of ongoing environmental
obligations and for the ultimate reclamation of the properties held by it upon abandonment. Ongoing environmental
obligations are expected to be funded out of cash flow.
Tax Horizon
Based on planned capital expenditures and the forecast commodity pricing employed in the Sproule Report, the Corporation
estimates that it will be required to pay current income taxes before 2014.
Costs Incurred
The following table summarizes capital expenditures incurred by the Corporation during the year ended December 31, 2011.
Drilling Activity
The following table sets forth the gross and net exploration and development wells drilled by the Corporation based on rig
release date during the year ended December 31, 2011.
Planned Capital Expenditures
The Corporation has announced a planned capital expenditure budget of approximately $261 million for 2012, including
approximately $106 million in acquisitions. This spending will be largely weighted to drilling, completions, tie-ins and facilities
at approximately $125 million and will include land, seismic and other spending of approximately $30 million. The
Corporation is planning to drill 56 gross (48.3 net) wells in 2012 targeting high quality light oil, with the majority of the activity
at Waskada (12 gross, 12 net wells), North Dakota (17 gross, 9.84 net), Nipisi/Gift ( 9 gross, 9 net wells), Valhalla (7 gross, 5.46
net wells) and Silver Lake (12 gross, 12 net wells).
23
Gross AcresNet AcresNet Acres Expiring within One YearAlberta413,645 396,247 7,498 North Dakota91,258 88,087 10,301 Manitoba9,874 9,874 569 Total514,777 494,208 18,368 Proved PropertiesUnproved PropertiesProperty DispositionsExploration CostsDevelopment CostsTotal ($M)7,034 17,875 (9,848) 5,531 145,019 Property Acquisition CostsGrossNetGrossNetLight and Medium Oil2.00 2.00 33.00 30.36 Natural Gas- - - - Service - - 3.00 3.00 Dry- - - - Total2.00 2.00 36.00 33.36 Exploration WellsDevelopment Wells
Production Estimates
The following table discloses for each product type the total volume of production estimated by Sproule in the Sproule Report
for 2012 in the estimates of future net revenue from gross proved and gross proved plus probable reserves disclosed above.
Production History
The following table discloses, on a quarterly basis for the year ended December 31, 2011, certain information in respect of
production, product prices received, royalties paid, operating expenses and resulting netback for the Corporation.
Average Daily Production Volume
Prices Received, Royalties Paid, Production Costs and Netback- Crude Oil
24
Light and Medium OilNatural GasNatural Gas LiquidsBOE%(bbls/d)(Mcf/d)(bbls/d)(BOE/d)ProvedSilver1,039 641 12 1,158 14%Valhalla853 7,223 314 2,371 28%Waskada946 0 0 946 11%Other2,091 9,905 253 3,995 47%Total Proved4,929 17,769 580 8,470 100%Proved Plus ProbableSilver1,061 656 13 1,183 13%Valhalla1,425 11,830 514 3,911 44%Waskada977 0 0 977 11%Other1,744 5,751 62 2,764 31%Total Proved Plus Probable5,207 18,237 589 8,835 100%Mar 31, 2011Jun 30, 2011Sep 30, 2011Dec 31, 2011Natural Gas (Mcf/d)11,915 12,334 14,313 17,885 Light and Medium Crude Oil (bbls/d)2,876 2,811 3,478 4,052 NGL (bbls/d)214 184 303 482 Total (BOE/d)5,076 5,051 6,166 7,514 Three Months Ended($ per Bbl)Mar 31, 2011Jun 30, 2011Sep 30, 2011Dec 31, 2011Prices Received77.86 92.36 80.29 88.60 Royalties Paid(10.47) (11.59) (10.65) (10.67) Transportation Costs(2.97) (4.11) (2.03) (0.78) Production Costs(15.68) (14.97) (14.67) (14.52) Netback (1)48.73 61.69 52.95 62.63 Three Months Ended
Prices Received, Royalties Paid, Production Costs and Netback- Natural Gas
Prices Received, Royalties Paid, Production Costs and Netback- Combined
Note:
(1)
Netback is calculated by deducting royalties paid and production costs, including transportation costs, from prices
received, excluding the effects of hedging.
Production Volume by Field
The following table indicates the average daily net production from the Corporation’s important fields for the year ended
December 31, 2011.
SHARE CAPITAL
The Corporation is authorized to issue an unlimited number of Common Shares and an unlimited number of Preferred Shares
issuable in series. As at March 21, 2012, there were 71,032,967 Common Shares and no Preferred Shares issued and
outstanding.
Common Shares
The holders of Common Shares are entitled to: (i) one vote for each Common Share held at all meetings of shareholders of
the Corporation other than meetings of the holders of any class or series of shares meeting as a class or series; (ii) receive any
dividends declared by the Corporation on the Common Shares; and (iii) subject to the rights of shares ranking prior to the
Common Shares, to receive the remaining property of the Corporation on dissolution, after the payment of all liabilities.
25
($ per Mcf)Mar 31, 2011Jun 30, 2011Sep 30, 2011Dec 31, 2011Prices Received3.88 4.13 3.81 3.49 Royalties Paid(0.70) (0.97) (0.80) (0.26) Transportation Costs(0.30) (0.32) (0.38) (0.38) Production Costs(2.92) (2.93) (2.38) (2.48) Netback (1)(0.04) (0.09) 0.25 0.38 Three Months Ended($ per BOE)Mar 31, 2011Jun 30, 2011Sep 30, 2011Dec 31, 2011Prices Received56.64 64.83 58.19 61.93 Royalties Paid(8.02) (9.24) (8.38) (7.05) Transportation Costs(2.54) (3.25) (1.77) (1.41) Production Costs(16.73) (16.39) (12.14) (14.92) Netback (1)29.35 35.95 35.90 38.55 Three Months EndedFieldLight and Medium Oil & NGLs (bbls/d)Natural Gas (Mcf/d)Natural Gas Liquids (bbls/d)BOE (BOE/d)%Valhalla753 4,894 195 1,763 30%Silver and Sounding Lake1,194 669 13 1,318 22%Other1,360 8,569 90 2,878 48%Total3,307 14,133 297 5,959 100%
Preferred Shares
Preferred Shares may be issued in one or more series. The Board of Directors is authorized to fix the number of shares in each
series and to determine the designation, rights, privileges, restrictions and conditions attached to the shares of each series.
Preferred Shares are entitled to a priority over the Common Shares with respect to the payment of dividends and the
distribution of assets upon the liquidation, dissolution or winding-up of The Corporation.
DIVIDEND POLICY
The Corporation has not declared or paid any dividends on the Common Shares since its incorporation. Any decision to pay
dividends on the Common Shares will be made by the Board of Directors on the basis of the Corporation’s earnings, financial
requirements and other conditions existing at such future time.
None of the securities of the Corporation are subject to escrow.
ESCROWED SECURITIES
MARKET FOR SECURITIES
The Common Shares are listed and posted for trading on the TSX under the trading symbol “SGY” and have traded on such
stock exchange since October 21, 2011. The Common Shares previously traded on the TSXV under the same symbol. The
following table sets forth the reported market price ranges and the trading volumes for the Common Shares for the periods
indicated, as reported by the TSXV (prior to October 21, 2011) and the TSX (from October 21, 2011 to present).
Price Range ($)
Period
2011
January
February
March
April
May
June
July
August
September
October
November
December
2012
January
February
March 1-21
Low
7.30
8.00
7.87
7.75
7.91
8.98
9.51
8.11
7.35
6.31
8.25
8.65
8.71
9.41
9.77
Trading Volume
9,571,600
10,750,064
7,799,273
5,384,697
6,366,730
4,295,669
4,331,819
3,987,315
6,164,117
3,449,379
5,575,317
4,610,816
7,449,713
8,936,648
8,776,984
High
8.49
9.25
9.74
9.20
9.70
9.87
10.45
9.68
9.60
8.90
9.65
9.74
9.80
10.50
11.17
26
DIRECTORS AND OFFICERS
In conjunction with the completion of the non-brokered private placement on April 13, 2010, the then existing directors and
officers of the Corporation were replaced by the current directors and officers of the Corporation, with the exception of
Murray Smith and Colin Davies, who joined the Board of Directors on July 12, 2010 and July 9, 2010 respectively. The name,
municipality of residence, principal occupation for the prior five years and position with the Corporation of each of the
directors and officers of the Corporation are as follows:
Name and Residence
Position
Principal Occupation During Previous Five Years
P. Daniel O'Neil
Calgary, Alberta
Director,
President and Chief
Executive Officer
Paul Colborne(4)
Calgary, Alberta
Chairman of the
Board of Directors
Robert Leach (2)
Calgary, Alberta
Director
Peter Bannister(1) (3)
Calgary, Alberta
Director
Keith Macdonald(1)(3)(4)
Calgary, Alberta
Director
Director, President and Chief Executive Officer of the Corporation. Prior
thereto, President and Chief Executive Officer of Breaker Energy Ltd., a
publicly traded oil and natural gas company, from its formation in September
2004 until its acquisition by NAL Oil & Gas Trust in December 2009. Mr.
O’Neil is also a director of both Hyperion Exploration Corp and Cathedral
Energy Services.
President of StarValley Oil & Gas Ltd., a private oil and natural gas company,
since October 2006, Chairman of Legacy Oil and Gas Inc. and serves on the
board of directors of Crescent Point Energy Corp. and Cequence Energy Ltd.
Prior thereto, Mr. Colborne served as a director of Wildstream Exploration
Inc. prior to its sale in 2012, Chairman of TriStar Oil & Gas Ltd. until its sale in
2009 and a director of Breaker Energy Ltd. until its sale in 2009. Prior thereto,
Mr. Colborne was President and Chief Executive Officer of StarPoint Energy
Trust, a publicly traded oil and natural gas income trust, until its merger to
form Canetic Resources Trust in January 2006 and was Chairman of Seaview
Energy Ltd, and was a director of Westfire Energy Ltd. and Twin Butte Energy
Ltd.
President and Chief Executive Officer of Custom Truck Sales Ltd., a private
in Saskatchewan and
company operating Kenworth truck dealerships
Manitoba, and President of International Fitness Holdings, an operating arm
of a private equity firm operating 25 health clubs in Alberta. Mr. Leach was
formerly the Chairman of the Board of Breaker Energy Inc.
President of Destiny Energy Inc., a privately owned oil and gas company,
Chairman of Crescent Point Energy Corp., and also serves on the board of
directors of Cequence Energy Ltd. Prior thereto, Mr. Bannister served as a
director of Breaker Energy Ltd. until its sale in 2009. He was Vice-President
Exploration of Mission Oil and Gas Inc. until its sale in 2006 and Vice-
President Exploration of StarPoint Energy Inc., President of Impact Energy
Inc. and Vice-President of Corporate Development of Startech Energy Ltd.
prior to their respective corporate sales.
President of Bamako Investment Management Ltd., a private holding and
financial consulting company. Mr. Macdonald is also a director of Bellatrix
Exploration Ltd. and Rocky Mountain Dealerships Inc., which are listed on the
TSX. As well, he is a director of Madalena Ventures Inc. and Mountainview
Energy Ltd., which are listed on the TSX Venture Exchange, and other public
and private oil and gas companies.
27
Name and Residence
Position
Principal Occupation During Previous Five Years
James Pasieka(2)
Calgary, Alberta
Director
Murray Smith(1) (2)
Calgary, Alberta
Director
Colin Davies(3) (4)
Calgary, Alberta
Director
Partner of the national law firm Heenan Blaikie LLP since 2001. Mr. Pasieka
has served as an officer and director of a number of public energy
companies, chairman of the board of several oil and gas companies and was
formerly Corporate Secretary of Breaker Energy Ltd.
Mr. Smith is the president of a private consulting company, Murray Smith
and Associates and a director of CriticalControl Business Solutions Corp. and
serves on four private company boards. Prior thereto, Mr. Smith was an
Official Representative of the Province of Alberta to the United States of
America until 2007. Prior thereto, he was a member of the Legislative
Assembly in the Province of Alberta serving in four different Cabinet
portfolios – Energy, Gaming, Labour, and Economic Development from 1993
to 2005.
Mr. Davies is President & CEO and Director of Corinthian Exploration Corp., a
private company with oil and gas assets located in Alberta and North Dakota.
Prior thereto, Mr. Davies was President & CEO and Director of Corinthian
Energy Corp., a private oil and gas company that was founded in 2004 and
amalgamated with Surge Energy Inc. in July 2010.
Maxwell Lof
Calgary, Alberta
Chief Financial Officer Chief Financial Officer of the Corporation. Prior thereto, Chief Financial
Officer and Vice-President, Finance of Breaker Energy Ltd. from its formation
in September 2004 until its acquisition by NAL Oil & Gas Trust in December
2009.
Dan Brown
Calgary, Alberta
Chief Operating
Officer
Margaret Elekes
Calgary, Alberta
Vice-President, Land
Malcolm Adams
Calgary, Alberta
Tee Ong
Calgary, Alberta
Vice-President,
Corporate
Development
Vice-President,
Engineering
Kevin Angus
Calgary, Alberta
Vice President,
Exploration
Chief Operating Officer of the Corporation. Prior thereto, Chief Operating
Officer of Breaker Energy Ltd. from August 2009 until its acquisition by NAL
Oil & Gas Trust in December 2009. Prior thereto, Mr. Brown was the
Business Unit Team Lead at a major North American production company.
Vice-President, Land of the Corporation. Prior thereto, Consulting Landman
for Breaker Energy from its formation in September 2004 until its acquisition
by NAL Oil & Gas Trust in December 2009 and Consulting Landman with
Legacy Oil + Gas Inc. from December 2009 to March 2010.
Vice-President, Corporate Development of the Corporation. Prior thereto,
Mr. Adams was the Vice-President of ARC Financial Corp. from October 2001
to April 2010.
Vice-President, Engineering of the Corporation. Prior thereto, Mr. Ong has
held engineering positions with various oil and gas companies, with Daylight
Energy Ltd. being the most recent.
Vice President, Exploration of the Corporation. Prior thereto, Mr. Angus was
the Executive Vice-President and director of Pegasus Oil and Gas Inc. from
June 2006 to August 2009, Vice-President, Exploration at Mustang Resources
Inc. from June 2003 to July 2005 and President of KD Angus & Associates Ltd.
from 1997 to 2003.
28
Notes:
1.
2.
3.
4.
Member of the audit committee.
Member of the compensation committee.
Member of the reserves committee.
Member of the environment, health and safety committee.
As a group, the directors and executive officers of the Corporation beneficially own, control or direct, directly or indirectly,
2,635,063 Common Shares, representing approximately 4% of the outstanding Common Shares as at March 21, 2012.
Corporate Cease Trade Orders
To the knowledge of management of the Corporation, no director or executive officer of the Corporation is, or within the 10
years before the date of this AIF, has been, a director, chief executive officer or chief financial officer of any other issuer that:
a) was the subject of a cease trade or similar order or an order that denied the other issuer access to any exemptions
under Canadian securities legislation that lasted for a period of more than 30 consecutive days that was issued while
the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer;
or
b) was subject to a cease trade or similar order or an order that denied the relevant issuer access to any exemption
under securities legislation that lasted for a period of more than 30 consecutive days that was issued after the
director or executive officer ceased to be a director, chief executive officer or chief financial officer and which
resulted from an event that occurred while the person was acting in the capacity as director, chief executive officer
or chief financial officer.
Bankruptcies
To the knowledge of management of the Corporation, no director or executive officer, or any shareholder holding a sufficient
number of securities of the Corporation to affect materially the control of the Corporation, or a personal holding company of
any such person:
a)
is, at the date of this AIF or has been within the 10 years before the date of this AIF, a director or executive officer of
any company that, while that person was acting in that capacity or within a year of that person ceasing to act in that
capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was
subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver
manager or trustee appointed to hold its assets; or
b) has, within the 10 years before the date of this AIF, become bankrupt, made a proposal under any legislation relating
to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with
creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or
shareholder.
Penalties or Sanctions
To the knowledge of management of the Corporation, no director or executive officer, or any shareholder holding a sufficient
number of securities of the Corporation to affect materially the control of the Corporation, has:
a) been subject to any penalties or sanctions imposed by a court relating to Canadian securities legislation or by a
Canadian securities regulatory authority or has entered into a settlement agreement with the Canadian securities
regulatory authority; or
b) been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be
considered important to a reasonable investor in making an investment decision.
29
Conflicts of Interest
The directors and officers of the Corporation may participate in activities and investments in the oil and gas industry outside
the scope of their engagement or employment as directors or officers of the Corporation. As a result, the directors and
officers may become subject to conflicts of interest. The ABCA provides that, in the event that a director has an interest in a
contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall
refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the
extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA, the
written mandate of the Board of Directors and the Corporation’s corporate governance policies.
As at the date hereof, the Corporation is not aware of any existing or potential material conflicts of interest between the
Corporation and a director or officer of the Corporation.
Composition of the Audit Committee, Charter and Review of Services
AUDIT COMMITTEE
The members of the Audit Committee of the Board of Directors are Keith Macdonald (Chair), Murray Smith and Peter
Bannister.
The Audit Committee of the Board of Directors operates under a written charter that sets out its responsibilities and
composition requirements. A copy of the charter is attached to this AIF as Schedule “C”.
The Audit Committee charter requires all members of the Audit Committee to be financially literate and independent within
the meaning of applicable securities laws. All members of the Audit Committee meet these requirements.
The Audit Committee charter requires that any non-audit services by the Corporation’s auditors must be pre-approved by the
Audit Committee. The Audit Committee has passed a resolution providing the Chairman of the Audit Committee with
delegated authority to approve the provision of non-audit services by the Corporation’s auditors from time to time, provided
that: (i) such services are provided pursuant to a written engagement letter setting out the services to be provided and the
applicable fees; (ii) the provision of such services is otherwise in compliance with the Audit Committee’s charter; (iii) such
services could not be reasonably seen to result in the auditors performing any management function, auditing their own work
or serving in an advocacy role on behalf of the Corporation; (iv) the fees for such services do not exceed $50,000 per
engagement; and (v) the Chairman reports to the Committee at the next regularly scheduled meeting any approval of non-
audit services made pursuant to the authority delegated under the resolution. The Audit Committee also pre-approves all
audit services and the fees to be paid.
Education and Experience of Members
The education and experience of each director relevant to the performance of his duties as a member of the Audit Committee
are described below.
Keith Macdonald
Mr. Macdonald is currently the President of Bamako Investment Management Ltd., a private holding and financial consulting
company.
Mr. Macdonald is Chairman, President, CEO and director of EFL Overseas, Inc. as well as director of Bellatrix Exploration Ltd.,
Holloman Energy Corporation, Madalena Ventures Inc., Mountainview Energy Ltd., Rocky Mountain Dealerships Inc., WCSB
Oil and Gas Royalty Income 2010 Management Corp. and WCSB Oil and Gas Royalty Income 2010-II Management Corp. He
has served as chair and/or a member of the audit committee of each of those companies, as well as several other public oil
and gas companies for which he has been a director. Mr. Macdonald was also formerly a director of Breaker Energy Ltd. prior
to its sale in 2009.
30
From 1994 to January 1999 Mr. Macdonald was vice president of finance and a director of New Cache Petroleum Ltd. Mr.
Macdonald founded New Cache Petroleum Ltd. in 1988 and was its president until a merger in 1994.
Mr. Macdonald holds the Chartered Accountants designation, achieved in 1980, and a Bachelor of Commerce degree
(Accounting and Finance Major) from University of Calgary in 1978.
Murray Smith
Mr. Smith is the president of a private consulting company, Murray Smith and Associates and a director of Critical Control
Business Solutions and serves on two private company boards. Prior thereto, Mr. Smith was an Official Representative of the
Province of Alberta to the United States of America until 2007. Prior thereto, he was a member of the Legislative Assembly in
the Province of Alberta serving in four different Cabinet portfolios – Energy, Gaming, Labour, and Economic Development
from 1993 to 2005.
From 1998-2004 Mr. Smith Mr. Smith was a member of the Government of Alberta Treasury Board (responsible for the
annual budget for Alberta) and a contributing member to Alberta’s debt elimination in 2004.
Mr. Smith has a degree in Economics from the University of Calgary (1971) and is a graduate of the London Business School
Senior Executive Program (2000).
Peter Bannister
Mr. Bannister is currently the president of Destiny Energy Inc., a privately owned oil and gas company and is chairman of
Crescent Point Energy Corp., a TSX listed company. Until its sale in February of 2007, Mr. Bannister was Vice-President,
Exploration and a director of Mission Oil and Gas Inc., a TSX listed company. Prior to thereto, he was Vice-President,
Exploration of StarPoint Energy Inc. before its conversion into a royalty trust and President and a director of Impact Energy
Inc., both TSX listed companies. Mr. Bannister previously held the position of Vice-President of Corporate Development of
Startech Energy Inc. until it was acquired by ARC Resources Ltd. at the end of 2000 and also held positions as Vice-President,
Exploration and Development and a director of Boomerang Resources Ltd. and Laurasia Resources Limited, both publicly
traded oil and gas companies. Mr. Bannister served on the Audit Committee of Breaker Energy Ltd. until its sale in 2009.
Mr. Bannister graduated from the University of Calgary in 1981 with a Major in Geology and a Minor in Economics. He was
initially employed by Sproule Associates Limited as a senior geologist. Later, as a partner, he participated in exploration and
property evaluation throughout Western Canada, the United States and the United Kingdom. He spent a number of years
managing private capital and developing and executing drilling and acquisition opportunities for investors. Since 1993, Mr.
Bannister has been actively involved in publicly-traded oil and gas companies.
External Auditor Service Fees
KPMG LLP are the auditors of the Corporation. KPMG LLP have been the auditors of the Corporation since May 5, 2010. Prior
thereto, Collins Barrow Chartered Accountants LLP were the auditors of the Corporation.
The following table sets out the aggregate fees billed by Collins Barrow Chartered Accountants LLP to the Corporation in each
of the last two fiscal years.
Year Audit Fees(1) Audit-Related Fees Tax Fees(2) All Other Fees
2011 $nil
2010 $158,114
$nil
$11,346
$nil
$nil
$nil
$nil
Notes:
(1) Audit fees consist of fees for the audit of annual financial statements or services that are normally provided in connection with
statutory and regulatory filings or engagements. During fiscal 2010, the services provided in this category included quarterly
review fees.
(2) Fees for tax compliance, tax advice and tax planning.
31
The following table sets out the aggregate fees billed by KPMG LLP to the Corporation in each of the last two fiscal years.
Year Audit Fees(1) Audit-Related Fees Tax Fees(2) All Other Fees
2011 $293,500
2010 $242,500 $nil $nil $nil
$165,500
$54,500
$nil
Notes:
(1) Audit fees consist of fees for the audit of annual financial statements or services that are normally provided in connection with
statutory and regulatory filings or engagements. During fiscal 2010 and 2011, the services provided in this category included
quarterly review fees.
(2) Fees for tax compliance, tax advice and tax planning.
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 government and with respect to pricing and taxation of oil and natural gas by agreements among the
governments of Canada, Alberta, British Columbia and Manitoba, 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 operations of the
Corporation in a manner materially different than they would affect other oil and gas issuers 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 the jurisdictions in which the Corporation currently operates.
Pricing and Marketing – Oil
In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines
the price of oil. Such price depends in part on oil type and quality, price of competing fuels, distance to market, the value of
refined products, supply/demand balance and other contractual terms. Oil exporters are also entitled to enter into export
contracts and export oil provided that, for contracts that do not exceed one year in the case of light crude oil and two years in
the case of heavy crude oil, an export order is obtained from the National Energy Board prior to the export. Any export
pursuant to a contract of longer duration (to a maximum of 25 years) must be made pursuant to a National Energy Board
export license and Governor in Council approval.
Early in 2012, there has been widening and increased volatility in both the light oil pricing differential between WTI and
Edmonton Par and the medium/heavy oil pricing differential between WTI and Cromer/WCS/Hardisty. Western Canada and
North Dakota have seen significant growth in crude production volumes over recent years. This has resulted in pressure on
the pipeline take-away capacity, leading to apportionment on the main lines and, in turn, backed-up local feeder pipelines.
Additionally, the PADD II refineries have seen some recent unscheduled outages and are running at full capacity. These
factors have led to increased differentials. Reduced activity over spring breakup, the planned Seaway Pipeline reversal, a
reduction in PADD II refinery turnarounds and possible pipeline expansion projects are factors that may mitigate the
increased differentials and volatility.
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 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 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
32
allowed, provided that any export 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.
Provincial Royalties and Incentives
General
In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production
rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil,
natural gas, natural gas liquids and sulphur production. Royalties payable on production from lands other than Crown lands
are determined by negotiations between the mineral owner and the lessee, although production from such lands is also
subject to certain provincial taxes and royalties. Operations not on Crown lands and subject to the provisions of specific
agreements are also usually subject to royalties negotiated between the mineral owner and the lessee. These royalties are
not eligible for incentive programs sponsored by various governments as discussed below. Crown royalties are determined by
governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of
royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field
discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-
like interests are from time to time carved out of the working interest owner's interest through non-public transactions.
These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.
From time to time the governments of the western Canadian provinces have established incentive programs for exploration
and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits for the purpose of
encouraging oil and natural gas exploration or enhanced recovery projects. The programs are designed to encourage
exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and
reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and
would increase the net income and funds from operations of such producers. However, the trend in recent years has been for
provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive
programs are currently operative.
Alberta
In Alberta, the Crown royalty rates on conventional oil and natural gas fluctuate, depending on when a well was drilled, well
depth, well production volume and the price of oil and natural gas. On October 25, 2007, the Alberta Government introduced
a new royalty regime which became effective on January 1, 2009, and is applicable to all existing conventional oil and natural
gas wells in Alberta. The new royalty regime assesses the applicable royalty rate on a well by well basis using a sliding scale
which takes into account the price of oil and/or natural gas and the well’s production volumes.
Under the new Alberta royalty regime, the royalty reserved to the Alberta Crown on conventional oil production ranges from
zero percent to 50 percent and is capped at 50 percent once the price of conventional oil reaches Cdn $120 per barrel. The
royalty applicable to natural gas production under the new royalty regime ranges from five percent to 50 percent and is
capped at 50 percent once the price of natural gas reaches Cdn $16.59 per gigajoule. The new royalty regime has retained
the Natural Gas Deep Drilling Program and the Deep Oil Exploration Program. The new royalty regime also sets royalties for
natural gas liquids at 40 percent for pentanes and 30 percent for butanes and propane.
33
On November 19, 2008, and November 24, 2008, the Alberta Government announced details of an optional five-year
transitional royalty program (“Transitional Program”). The Transitional Program applies to conventional oil and natural gas
wells drilled to measured depths between 1,000 to 3,500 meters between November 19, 2008, and January 1, 2014. For each
well, the producer can make a one time election to produce the well under the Transitional Program or the new royalty
regime. As of January 1, 2014, all production subject to the Transitional Program will revert to the new royalty regime. The
Natural Gas Deep Drilling and Deep Oil Exploration programs are not available to wells producing under the Transitional
Program.
For conventional oil produced under the Transitional Program, the royalty reserved to the Alberta Crown is variable,
depending on the pool’s vintage (when the pool was discovered), oil density, well production volume, and the price of oil.
The royalty is capped at 35 percent, which maximum is reached at an oil price of approximately Cdn $30 per barrel,
depending on other factors such as production rates.
For natural gas produced under the Transitional Program, the royalty reserved to the Alberta Crown varies depending on the
vintage, production volume and the inflation adjusted price of gas less adjustments for the cost of processing the Crown’s
share of the gas. The royalty will vary between 15 percent to 35 percent, which maximum is reached at a natural gas price of
approximately Cdn $3.70 per gigajoule, depending on other factors such as production rates.
On March 3, 2009, the Government of Alberta announced an additional incentive program in respect of oil and gas wells
drilled on Alberta Crown lands. This program provides that, in respect of any wells drilled between April 1st, 2009 and April 1,
2011, the operator will receive (a) a drilling credit equal $200 of royalty per metre drilled on conventional oil and natural gas
wells and (b) a maximum royalty rate of five percent on such wells until the first to occur of twelve calendar months, 50,000
barrels of oil production or 500 million cubic feet (MMcf) of gas production.
In April 2010, the Government of Alberta announced an additional royalty incentive program relating to horizontal oil well
drilling projects. Horizontal oil wells drilled on or after May 1, 2010 qualify for the Horizontal Oil New Well Royalty Rate
program. This incentive program provides a reduced royalty rate on new horizontal oil wells for the first 18 to 48 months of
production, based on drilling depth, up to an established total production volume of 50,000 to 100,000 BOE. (BOE cap is
calculated at 10:1).
British Columbia
Oil produced from Crown leases in British Columbia is subject to a Crown royalty which varies from zero percent to 40
percent. B.C. Crown royalty rates depend on the volume produced monthly, the vintage of the oil (whether it was produced
from a pool discovered before or after October 31, 1975), whether the oil is considered third tier or produced from a well
shut-in for at least 36 months immediately preceding January 1, 1981, meets locational requirements, and which resumed
production on or after such date and the viscosity of oil produced. Oil produced from the discovery of pools discovered after
June 30, 1974 may be exempt from the payment of a royalty for the first 36 months of production up to a certain monthly
production threshold and thereafter is subject to royalty payments. Subject to the minimum royalties described in the
following sentence, the royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the
greater of the amount obtained by the producer and a prescribed minimum price. Natural gas produced in association with
oil has a minimum royalty of eight percent while the royalty in respect of other natural gas may not be less than nine percent.
Natural gas wells drilled after May 1998 have a maximum royalty rate of 27 percent. Natural gas wells producing less than a
specified daily volume of gas may be eligible for a reduction in the applicable royalty rate.
Manitoba
In Manitoba, the royalty amount payable on oil produced from Crown lands depends on the classification of the oil produced
as “old oil” (produced from a well drilled prior to April 1, 1974 that does not qualify as new oil or third tier oil), “new oil” (oil
that is not third tier oil and is produced from a well drilled on or after April 1, 1974 and prior to April 1, 1999, from an
abandoned well re-entered during that period, from an old oil well as a result of an enhanced recovery project implemented
during that period, or from a horizontal well), “third tier oil” (oil produced from a vertical well drilled after April 1, 1999, an
abandoned well re-entered after that date, an inactive vertical well activated after that date, a marginal well that has
undergone a major workover, or from an old oil well or a new oil well as a result of an enhanced recovery project
implemented after that date), or “holiday oil” (oil that is exempt from any royalty or tax payable). Royalty rates are
calculated on a sliding scale and based on the monthly oil production from a spacing unit, or oil production allocated to a unit
34
tract under a unit agreement or unit order from the Minister. For horizontal wells, the royalty on oil produced from Crown
lands is calculated based on the amount of oil production allocated to a spacing unit in accordance with the applicable
regulations.
Royalties payable on natural gas production from Crown lands are equal to 12.5 percent of the volume of natural gas sold.
Producers of oil and natural gas from freehold lands in Manitoba are required to pay monthly freehold production taxes. The
freehold production tax payable on oil is calculated on a sliding scale based on the monthly production volume and the
classification of oil as old oil, new oil, third tier oil and holiday oil. Producers of natural gas from freehold lands in Manitoba
are required to pay a monthly freehold production tax equal to 1.2 percent of the volume sold. There is no freehold
production tax payable on gas consumed as lease fuel.
The Government of Manitoba maintains a Drilling Incentive Program (the “Program”) with the intent of promoting
investment in the sustainable development of petroleum resources. The Program provides the licensee of newly drilled wells,
or qualifying wells where a major workover has been completed, with a “holiday oil volume” pursuant to which no Crown
royalties or freehold production taxes are payable until the holiday oil volume has been produced. Under the Program, wells
drilled for purposes of injection (or wells converted to injection prior to producing predetermined volumes of oil) in an
approved enhanced oil recovery project earn a one-year holiday for portions of the project area.
The Program consists of the following components:
New Well Incentive provides licensees of newly drilled, non-horizontal wells drilled prior to January 1, 2014 with a
•
holiday oil volume to a maximum of 10,000 m3;
•
Deep Drilling Incentive provides licensees who drill a well to a total depth sufficient to penetrate the Devonian
Duperow formation with a holiday oil volume of 20,000 m3, and licensees who drill a well deeper than the Devonian Three
Forks formation can make a one-time assignment of up to 10,000 m3 of holiday oil volume earned through previous drilling
or major workovers to such well’s holiday oil volume;
•
Horizontal Well Initiative provides licensees of horizontal wells drilled prior to January 1, 2014 with a holiday oil
volume of 10,000 m3, and a horizontal leg drilled from an existing horizontal well on or after January 1, 2009 and prior to
January 1, 2014 will earn an additional holiday royalty volume of 3,000 m3;
•
Marginal Well Major Workover Incentive provides licensees of marginal wells where a major workover is completed
prior to January 1, 2014 with a holiday oil volume of 500 m3 ,with a marginal oil well defined as an abandoned well or a well
that was either not operated over the previous 12 months or produced oil at an average rate of less than 1 m3 per operating
day; and
Injection Well Incentive provides a one year exemption from the payment of Crown royalties or freehold production
•
taxes on production allocated to a unit tract in which a well is drilled or converted to water injection.
Further, holiday oil volumes earned by a newly drilled well or a marginal well that has undergone a major workover can be
transferred to a Holiday Oil Volume Account at the request of the licensee, the purpose of which is to optimize the value of
holiday oil volumes earned by providing a company with the flexibility of allocating holiday oil volumes earned among new
wells.
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.
35
Environmental Regulation
The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation.
Environmental legislation provides for restrictions and prohibitions on releases or emissions and regulation on the storage
and transportation of various substances produced or utilized in association with certain oil and gas industry operations and
can affect the location and operation of wells and facilities and the extent to which exploration and development is
permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of
provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to property
designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance
causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other
person in possession of the site. Compliance with such legislation can require significant expenditures and a breach of such
legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution
damage, the imposition of fines and penalties or the issuance of clean up orders.
Environmental legislation in the Province of Alberta is governed by the Environmental Protection and Enhancement Act
(Alberta) and the Oil and Gas Conservation Act (Alberta). 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.
Environmental legislation governing the oil and gas industry in the Province of Manitoba is, for the most part, set out in the
Oil and Gas Act which incorporates provisions related to the environment from The Environmental Act and The Surface Rights
Act. This legislation imposes obligations to protect, preserve and, where required, rehabilitate the environment and provides
penalties in the event of non-compliance.
In addition to existing environmental legislation, a number of federal and provincial governments have announced intentions
to regulate greenhouse gases and other air pollutants. These governments are currently developing the regulatory and policy
frameworks to deliver on their announcements. In most cases there are few technical details regarding the implementation
and coordination of these plans to regulate emissions. Additionally, it is anticipated that other federal and provincial
announcements and regulatory frameworks to address emissions will continue to emerge. As these federal and regional
programs are under development, the Corporation is unable to predict the total impact of the potential regulations upon its
business.
The operations of the Corporation are, and will continue to be, affected in varying degrees by laws and regulations regarding
environmental protection. The Corporation is committed to meeting its responsibilities to protect the environment and the
Corporation will be taking such steps as required to ensure compliance with the environmental legislation and regulations in
the jurisdictions in which it operates. The Corporation believes that it is reasonably likely that the trend towards stricter
standards in environmental legislation and regulation will continue and anticipates making increased expenditures of both a
capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment.
However, it is not currently possible to quantify any such increased expenditures and it is not anticipated that The
Corporation's competitive position will be adversely affected by current or future environmental laws and regulations
governing its oil and natural gas operations.
RISK FACTORS
An investment in Common Shares would be subject to certain risks. Investors should carefully consider the following risk
factors:
Operational Risks
Oil and natural gas exploration operations are subject to all the risks and hazards typically associated with such operations,
including hazards such as fire, explosion, blowouts and oil spills, each of which could result in substantial damage to oil and
natural gas wells, producing facilities, other property and the environment or in personal injury. In accordance with industry
practice, the Corporation is not fully insured against all of these risks, nor are all such risks insurable. Although the
36
Corporation maintains liability insurance in an amount which it considers adequate, 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 materially
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 premature decline of reservoirs and the invasion of water into producing
formations.
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 will not be the operator of its oil and natural gas properties, it 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. Payments from production generally flow through the operator and there is a risk of delay and additional
expense in receiving such revenues if the operator becomes insolvent. Although the Corporation intends to operate the
majority of its properties, there is no guarantee that it will remain operator of such properties or that the Corporation will
operate other properties it may acquire in the future.
In addition, the success of the Corporation will be largely dependent upon the performance of its management and key
employees. The Corporation does not have any key man insurance policies and, therefore, there is a risk that the death or
departure of any member of management or any key employee could have a material adverse affect on the company.
Sour Natural Gas
Some of the Corporation’s current or future properties include or may include wells that produce sour natural gas and
facilities that process sour natural gas. An accidental discharge or leak of sour natural gas can be fatal or cause serious injury.
The dangers associated with drilling for, producing, processing and transporting sour natural gas necessitate increased
environmental, health and safety compliance costs to the Corporation and any accidental discharge or leak of sour natural
gas could lead to significant liabilities to the Corporation. The Corporation has implemented policies and protocols to address
this risk, but it is not possible for any issuer to eliminate all of the risks associated with producing, processing and transporting
sour natural gas.
Fracing
The proliferation in certain jurisdictions in the United States of the use of hydraulic fracturing or “fracing” as a recovery
technique employed in natural gas drilling has given rise to increased public scrutiny of its environmental aspects, particularly
with respect to its potential impact on local aquifers. The Corporation utilizes fracing in a significant portion of the light oil
wells it drills and completes. Negative public perception of fracing may place pressure on governments in the jurisdictions
where the Corporation operates to implement additional regulatory requirements or limitations on the utilization of fracing,
which in turn could restrict the Corporation's operations and increase its costs.
Reserve Estimates
There are numerous uncertainties inherent in evaluating quantities of reserves and the net present value of future net
revenue to be derived therefrom, including many factors beyond the control of the Corporation. The reserves information
contained in the Sproule Report and set forth herein, including information respecting the net present value of future net
revenue from reserves, represents an estimate only. This estimate is based on number of assumptions relating to factors
such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital
expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties and other
government levies that may be imposed over the producing life of the reserves. These assumptions were based on price
forecasts in use at the date the Sproule Report was prepared and many of these assumptions are subject to change and are
beyond the control of the Corporation. Ultimately, the actual reserves attributable to the Corporation’s properties will vary
from the estimates contained in the Sproule Report and those variations may be material and affect the market price of the
Common Shares.
37
Reserve Replacement
The Corporation’s future oil and natural gas reserves and production and the cash flows to be derived therefrom are highly
dependent on successfully acquiring or discovering new 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 reserves will depend not only on the Corporation’s ability to develop any
properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or
prospects. There can be no assurance that the Corporation’s future exploration and development efforts will result in the
discovery and development of additional commercial accumulations of oil and natural gas.
Possible Failure to Realize Anticipated Benefits of Recent and Future Acquisitions
The Corporation has completed several asset and corporate acquisitions to strengthen its position in the oil and natural gas
industry and to create the opportunity to realize certain benefits including, among other things, potential cost savings.
Achieving the benefits of these and future acquisitions the Corporation may complete depends in part on successfully
consolidating functions and integrating operations, procedures and personnel 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 the Corporation. The integration of acquired businesses requires the dedication of substantial
management effort, time and resources, which may divert management’s focus and resources from other strategic
opportunities and from operational matters during this process. The integration process may result in the loss of key
employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the
Corporation’s ability to achieve the anticipated benefits of these and future acquisitions.
Availability of Services
The availability of the services necessary to drill and complete the types of horizontal oil wells that form a substantial portion
of the Corporation's planned exploration and development activities in 2012 has becoming increasingly constrained due to
increased demand and competition for such services. Such constraint may increase the costs of such services or result in the
delay of planned exploration and development activities.
Risks Associated with Acquisitions
Acquisitions of oil and natural gas properties or companies are based in large part on engineering, environmental and
economic assessments made by the acquiror, independent engineers and consultants. These assessments include a series of
assumptions regarding such factors as recoverability and marketability of oil and natural gas, environmental restrictions and
prohibitions regarding releases and emissions of various substances, future prices of oil and natural gas and operating costs,
future capital expenditures and royalties and other government levies which will be imposed over the producing life of the
reserves. Many of these factors are subject to change and are beyond the control of the Corporation. All such assessments
involve a measure of geologic, engineering, environmental and regulatory uncertainty that could result in lower production
and reserves or higher operating or capital expenditures than anticipated.
Although title and environmental reviews are conducted prior to any purchase of resource assets, such reviews cannot
guarantee that any unforeseen defects in the chain of title will not arise to defeat the Corporation’s title to certain assets or
that environmental defect or deficiencies do not exist.
Market Conditions
The trading price of securities of oil and gas companies is subject to substantial volatility, and such trading prices have been
particularly volatile in recent months. This volatility is often based on factors both related and unrelated to the financial
performance or prospects of the companies involved. The market price of the Common Shares could be subject to significant
fluctuations in response to variations in the Corporation’s operating results, financial condition, liquidity and other internal
factors. Factors that could affect the market price of the Common Shares that are unrelated to the Corporation’s
performance include domestic and global commodity prices and market perceptions of the attractiveness of particular
industries. The price at which the Common Shares will trade cannot be accurately predicted.
38
Industry Regulation and Competition
There is strong competition relating to all aspects of the oil and natural gas industry. The Corporation will actively compete
for capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs, service rigs and other equipment,
access to processing facilities and pipeline and refining capacity, and in all other aspects of its operations with a substantial
number of other organizations, many of which may have greater technical and financial resources than the Corporation.
Some of those organizations not only explore for, develop and produce oil and natural gas but also carry on refining
operations and market petroleum and other products on a world-wide basis and as such have greater and more diverse
resources on which to draw. The Corporation’s ability to increase reserves and production in the future will depend not only
on its ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or
prospects for exploratory drilling.
The marketability of oil and natural gas acquired or discovered will be affected by numerous factors beyond the control of the
Corporation. These factors include reservoir characteristics, market fluctuations, the proximity and capacity of oil and natural
gas pipelines and processing equipment and government regulation. Oil and natural gas operations (exploration, production,
pricing, marketing, transportation and royalty rates) are subject to extensive controls and regulations imposed by various
levels of government, including those described above under the heading “Industry Conditions”, which may be amended from
time to time. The Corporation’s oil and natural gas operations may also be subject to compliance with federal, provincial and
local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection
of the environment. 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.
Volatility of Oil and Gas Prices and Markets
The Corporation’s financial performance and condition are substantially dependent on the prevailing prices of oil and natural
gas which are unstable and subject to fluctuation. Fluctuations in oil or natural gas prices could have an adverse effect on the
Corporation’s operations and financial condition and the value and amount of its reserves. Prices for crude oil fluctuate in
response to global supply of and demand for oil, market performance and uncertainty and a variety of other factors which are
outside the control of the Corporation including, but not limited, to the world economy and the Organization of the
Petroleum Exporting Countries’ ability to adjust supply to world demand, government regulation, political stability and the
availability of alternative fuel sources. Natural gas prices are influenced primarily by factors within North America, including
North American supply and demand, economic performance, weather conditions and availability and pricing of alternative
fuel sources.
Decreases in oil and natural gas prices typically result in a reduction of the Corporation’s net production revenue and may
change the economics of producing from some wells, which could result in a reduction in the volume of the Corporation’s
reserves. Any further substantial declines in the prices of crude oil or natural gas could also result in delay or cancellation of
existing or future drilling, development or construction programs or the curtailment of production. All of these factors could
result in a material decrease in the Corporation’s net production revenue, cash flows and profitability causing a reduction in
its oil and gas acquisition and development activities. In addition, bank borrowings available to the Corporation will in part be
determined by the Corporation’s borrowing base. A sustained material decline in prices from historical average prices could
further reduce such borrowing base, therefore reducing the bank credit available and could require that a portion of its bank
debt be repaid.
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.
Variations in Foreign Exchange Rates and Interest Rates
The Corporation’s expenses will be denominated in Canadian dollars, while the price of oil and natural gas will generally be
denominated in U.S. dollars or impacted by the Canadian dollar to U.S. dollar exchange rate. As the exchange rate for the
Canadian dollar versus the U.S. dollar increases, the Corporation will generally receive fewer Canadian dollars for its
production. If the value of the Canadian dollar against the U.S. dollar increases, the financial results of the Corporation may
be negatively affected. The Corporation’s management may initiate certain hedges to mitigate these risks. Future fluctuations
39
in the Canadian/United States foreign exchange rate may impact the future value of the Corporation’s reserves as determined
by independent evaluators. In addition, variations in interest rates could result in a significant change in the amount the
Corporation will pay to service debt, potentially adversely affecting the value of the Common Shares.
Price Volatility of Publicly Traded Securities
In recent years, the securities markets in Canada and the United States have experienced a high level of price and volume
volatility, and the market price of securities of many companies, particularly those considered to be development stage
companies, have experienced wide fluctuations in price which have not necessarily been related to the operating
performance, underlying asset values or prospects of such companies. There can be no assurance that continual fluctuations
in price will not occur. It is likely that the market price for the Common Shares will be subject to market trends generally,
notwithstanding the financial and operational performance of the Corporation.
Substantial Capital Requirements; Liquidity
The Corporation may have to make substantial capital expenditures for the acquisition, exploration, development and
production of oil and natural gas reserves in the future. If 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 company.
Moreover, future activities may require the Corporation to alter its capitalization significantly. The inability of the company to
access sufficient capital for its operations could have a material adverse effect on its financial condition, results of operations
or prospects.
Issuance of Debt
From time to time the Corporation may enter into transactions to acquire assets or shares of other corporations. These
transactions may be financed partially or wholly through debt, which may increase debt levels above industry standards. The
Corporation’s articles and by-laws do not limit the amount of indebtedness it may incur. The level of the Corporation’s
indebtedness from time to time could impair its ability to obtain additional financing in the future on a timely basis to take
advantage of business opportunities that may arise.
Environmental Concerns
Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that the
Corporation may be in noncompliance with an environmental law, regulation, permit, licence, or other regulatory approval,
possibly unintentionally or without knowledge. Such risks may expose the Corporation to fines or penalties, third party
liabilities or to the requirement to remediate, which could be material.
The operational hazards associated with possible blowouts, accidents, oil spills, natural gas leaks, fires, or other damage to a
well or a pipeline may require the Corporation to incur costs and delays to undertake corrective actions, could result in
environmental damage or contamination or could result in serious injury or death to employees, consultants, contractors or
members of the public, creating the potential for significant liability to the Corporation. Also, the occurrence of any such
incident, which is located in a populated area, could damage the Corporation's reputation in the surrounding communities
and make it more difficult for the Corporation to pursue its operations in those areas.
Compliance with environmental laws and regulations could materially increase the Corporation's costs. The Corporation may
incur substantial capital and operating costs to comply with increasingly complex laws and regulations covering the
protection of the environment and human health and safety. In particular, the Corporation may be required to incur
significant costs to comply with future federal or provincial greenhouse gas emissions reduction requirements or other
regulations, if enacted. Although it is not expected that the costs of complying with environmental legislation will have a
material adverse effect on the Corporation’s financial condition or results of operations, no assurance can be made that the
costs of complying with environmental legislation in the future will not have such an effect.
40
Although the Corporation maintains insurance consistent with prudent industry practice, it is not fully insured against certain
environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance
against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not
available on economically reasonable terms. Accordingly, the Corporation's properties may be subject to liability due to
hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other
reasons. It is also possible that changing regulatory requirements or emerging jurisprudence could render such insurance of
less benefit to the Corporation.
In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto
Protocol which requires participating countries, upon ratification, to reduce their emissions of carbon dioxide and other
greenhouse gases. Canada ratified the Kyoto Protocol in late 2002, and the Canadian federal government and various
Canadian provincial governments are currently evaluating other proposals and legislative measures that would achieve similar
objectives. However, until a detailed implementation plan is developed, it is difficult to determine what, if any, impact future
environmental laws and regulations may have on the Corporation’s environmental liabilities, on prices for oil and natural gas
or on other general economic factors which may affect the Corporation’s financial position and results. It is possible that the
Corporation could face increased operating costs in order to comply with emissions legislation.
Abandonment and Reclamation Costs
The Corporation will be responsible for compliance with terms and conditions of environmental and regulatory approvals and
all laws and regulations regarding abandonment and reclamation in respect of its properties, which abandonment and
reclamation costs may be substantial. A breach of such legislation or regulations may result in the imposition of fines and
penalties, including an order for cessation of operations at the site until satisfactory remedies are made.
Third Party Credit Risk
The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future
joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail
to meet their contractual obligations to the Corporation, such failures could have a material adverse effect on the
Corporation. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture
partner’s willingness to participate in the Corporation’s ongoing capital program, potentially delaying the program and the
results of such program until the Corporation finds a suitable alternative partner.
Delay in Cash Receipts and Credit Worthiness of Counterparties
In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the Corporation’s
properties, and by the operator to the Corporation, payments between any of such parties may also be delayed by
restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering
system, blowouts or other accidents, recovery by the operator of expenses incurred in the operation of the Corporation’s
properties or the establishment by the operator of reserves for such expenses. In addition, the insolvency or financial
impairment of any counterparty owing money to the Corporation, including industry partners and marketing agents, could
prevent the Corporation from collecting such debts.
Dilution
Common Shares, including rights, warrants, special warrants, subscription receipts and other securities to purchase, to
convert into or to exchange into Common Shares, may be created, issued, sold and delivered on such terms and conditions
and at such times as the Board may determine. In addition, the Corporation may issue additional Common Shares from time
to time pursuant to the Corporation’s stock option plan. The issuance of these Common Shares would result in dilution to
holders of Common Shares.
Net Asset Value
The Corporation’s net asset value will vary depending upon a number of factors beyond the control of the Corporation’s
management, including oil and natural gas prices. The trading price of the Common Shares is also determined by a number of
41
factors which are beyond the control of management and such trading price may be greater than or less than the net asset
value of the Corporation.
Reliance on Management
Shareholders will be dependent on the management of the Corporation in respect of the administration and management of
all matters relating to the Corporation and its properties and operations. Investors who are not willing to rely on the
management of the Corporation should not invest in Common Shares.
Permits and Licenses
The operations of the Corporation may require licenses and permits 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.
Title to Properties
Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas
producing properties or the commencement of drilling wells as determined appropriate by management, such reviews do not
guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat a claim of the Corporation which
could result in a reduction of the revenue received by the Corporation.
Aboriginal Claims
Aboriginal peoples have claimed aboriginal title and rights to resources and various properties in western Canada. Such
claims, in relation to any of the Corporation’s lands, if successful, could have an adverse effect on its operations.
Corporate Matters
To date, the Corporation has not paid any dividends on its outstanding Common Shares. Certain of the directors and officers
of the Corporation are also directors and officers of other oil and gas companies involved in natural resource exploration and
development, and conflicts of interest may arise between their duties as officers and directors of the Corporation, as the case
may be, and as officers and directors of such other companies.
Failure to Maintain Listing of the Common Shares
The Common Shares are currently listed for trading on the facilities of the TSX. The failure of the Corporation to meet the
applicable listing or other requirements of the TSX in the future may result in the Common Shares ceasing to be listed for
trading on the TSX, which would have a material adverse affect on the value of the Common Shares. There can be no
assurance that the Common Shares will continue to be listed for trading on the TSX.
Structure of the Corporation
From time to time, the Corporation may take steps to organize its affairs in a manner that minimizes taxes and other
expenses payable with respect to the operation of the Corporation and its subsidiaries. If the manner in which the
Corporation structures its affairs is successfully challenged by a taxation or other authority, the Corporation and the holders
of Common Shares may be adversely affected.
Changes in Legislation
It is possible that the Canadian federal and provincial government or regulatory authorities could choose to change the
Canadian federal income tax laws, royalty regimes, environmental laws or other laws applicable to oil and gas companies and
that any such changes could materially adversely affect the Corporation, its shareholders and the market value of the
Common Shares.
42
LEGAL PROCEEDINGS AND REGULATORY ACTIONS
There are no legal proceedings involving claims for damages for which the potential exposure is more than 10% of the
Corporation's current assets to which the Corporation is or was a party or in respect of which any of its properties are or were
subject during the year ended December 31, 2011, nor are there any such proceedings known to the Corporation to be
contemplated.
During the year ended December 31, 2011, there were (i) no penalties or sanctions imposed against the Corporation by a
court relating to securities legislation or by a securities regulatory authority; (ii) no other penalties or sanctions imposed by a
court or regulatory body against the Corporation that it believes would likely be considered important to a reasonable
investor in making an investment decision; and (iii) no settlement agreements entered into by the Corporation with a court
relating to securities legislation or with a securities regulatory authority.
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
In connection with the Recapitalization, on April 13, 2010, the current directors and officers of the Corporation, with the
exception of Murray Smith and Colin Davies, purchased 20,452 Common Shares at a price of $4.40 per Common Share,
1,099,413 Units at a price of $4.40 per Unit and 661,951 FT Units at a price of $4.40 per FT Unit. Each Unit consists of one
Common Share and Performance Warrant while each FT Unit consists of one Common Share issued on a “flow-through” basis
in accordance with the Tax Act and one Performance Warrant.
James Pasieka, a director of the Corporation, is a partner of Heenan Blaikie LLP, which law firm renders legal services to the
Corporation.
Except as disclosed above or as may be disclosed elsewhere in this AIF, none of the directors, executive officers or principal
shareholders of the Corporation, and no associate or affiliate of any of them, has or has had any material interest in any
transaction or any proposed transaction which has materially affected or is reasonably expected to materially affect the
Corporation or any of its affiliates.
AUDITOR, TRANSFER AGENT AND REGISTRAR
The auditor of the Corporation is KPMG LLP who has been the auditor since May 5, 2010.
The transfer agent and registrar for the Common Shares is Olympia Trust Company at its principal offices in Calgary, Alberta
and Toronto, Ontario.
INTEREST OF EXPERTS
The Sproule Report and certain reserves estimates contained in filings made by the Corporation under National Instrument
51-102 – Continuous Disclosure Requirements during the year ended December 31, 2011 were prepared by Sproule. As at
the date of this Annual Information Form, the directors, officers, employees and consultants of Sproule who participated in
the preparation of the Sproule Report or such reserves estimates or who were in a position to directly influence the
preparation or outcome of the preparation of the Sproule Report or such reserves estimates, as a group, owned, directly or
indirectly, less than 1% of the outstanding Common Shares.
Certain audit reports contained in filings made by the Corporation under National Instrument 51-102 – Continuous Disclosure
Requirements during the year ended December 31, 2009 were prepared by Collins Barrow Calgary LLP. KPMG LLP were
43
appointed auditors of the Corporation on May 5, 2010. KPMG LLP are independent of the Corporation pursuant to the rules
of professional conduct of the Institute of Chartered Accountants of Alberta. The previous auditors of the Corporation,
Collins Barrow Calgary LLP, were independent of the Corporation pursuant to the rules of professional conduct of the
Institute of Chartered Accountants of Alberta for the period during which they were the auditors of the Corporation.
MATERIAL CONTRACTS
The Corporation has not entered into any contracts or agreements during the most recently completed financial year or prior
to the most recently completed financial year but which remain in effect which would be considered to be material to the
Corporation except as set forth below:
1.
2.
the Pradera Acquisition Agreement;
the underwriting agreement dated September 20, 2011 between the Corporation and a syndicate of underwriters
with respect to a prospectus offering which was completed on October 12, 2011 as more particularly described
under the heading “Development of the Business – 2011 and 2012 to date - Prospectus Financing”; and
3.
the Reorganization Agreement.
Copies of such agreements are available on SEDAR at www.sedar.com or may be requested by contacting the Corporation c/o
Suite 2100, 635 – 8th Avenue S.W., Calgary, Alberta T2P 3M3, telephone (403) 930-1010.
ADDITIONAL INFORMATION
Additional
information concerning the Corporation may be found under the Corporation’s profile on SEDAR at
www.sedar.com. Additional information, including information concerning 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 information circular of the Corporation for the annual general and special
meeting of the holders of Common Shares scheduled for May 10th, 2012. Additional financial information is provided in the
Corporation’s comparative financial statements and management’s discussion and analysis for the year ended December 31,
2011.
44
SCHEDULE “A”
REPORT ON RESERVES DATA BY SPROULE ASSOCIATES LIMITED
45
46
47
48
SCHEDULE “B”
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Terms to which a meaning is ascribed in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities have
the same meaning herein.
Management of Surge Energy Inc. (the “Corporation”) is responsible for the preparation and disclosure of information with
respect to the Corporation’s oil and gas activities in accordance with securities regulatory requirements. This information
includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at
December 31, 2011, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated and reviewed the Corporation’s reserves data. The report of the
independent qualified reserves evaluator is presented in Schedule “A” to the Annual Information Form of the Corporation for
the year ended December 31, 2011 (the “AIF”).
The Reserves Committee of the Board of Directors of the Corporation has:
(a)
(b)
reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluator,
Sproule Associates Limited (“Sproule”);
met with Sproule to determine whether any restrictions affected the ability of Sproule to report without reservation;
and
(c)
reviewed the reserves data with management and with Sproule.
The Reserves Committee of the Board of Directors has reviewed the Corporation’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:
(d)
(e)
(f)
the content and filing with securities regulatory authorities of Form 51-101F1, incorporated into the AIF, containing
reserves data and other oil and gas information;
the filing of Form 51-101F2, which is the report of Sproule on the reserves data; and
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. However, any variations should be consistent with the fact that reserves are categorized according to the
probability of their recovery.
(signed) “P. Daniel O’Neil”
P. Daniel O’Neil, President & Chief Executive Officer
(signed) “Maxwell Lof”
Maxwell Lof, Vice-President, Finance and Chief Financial Officer
(signed) "Peter Bannister”
Peter Bannister, Director & Chairman of the Reserves Committee
(signed) "Paul Colborne"
Paul Colborne, Director & Chairman of the Board of Directors
March 21, 2012
49
SCHEDULE “C”
AUDIT COMMITTEE CHARTER
SURGE ENERGY INC.
AUDIT COMMITTEE CHARTER
Role and Objective
The Audit Committee is a committee of the Board of Directors of Surge Energy Inc. (the “Corporation”) to which the Board
has delegated its responsibility for oversight of the nature and scope of the annual audit, management’s reporting on internal
accounting standards and practices, financial information and accounting systems and procedures, financial reporting and
statements and recommending, for Board approval, the audited consolidated financial statements and other mandatory
disclosure releases containing financial information of the Corporation. The objectives of the Audit Committee are as follows:
1.
2.
3.
4.
5.
to assist directors in fulfilling their legal and fiduciary obligations (especially for accountability) in respect of the
preparation and disclosure of the financial statements of the Corporation and related matters;
to oversee the audit efforts of the external auditors of the Corporation;
to maintain free and open means of communication among the directors, the external auditors, the financial and
senior management of the Corporation;
to satisfy itself that the external auditors are independent of the Corporation; and
to strengthen the role of the outside directors by facilitating in depth discussions between directors on the
Committee, management and external auditors.
The function of the Committee is one of oversight of management and the external auditors in the execution of their
responsibilities. Management is responsible for the preparation, presentation and integrity of the financial statements of the
Corporation, maintaining appropriate accounting and financial reporting principles and policies and implementing
appropriate internal controls and procedures. The external auditors are responsible for planning and carrying out a proper
audit of the annual financial statements of the Corporation and reviewing the interim financial statements of the Corporation
prior to their filing with securities regulatory authorities and other procedures.
Composition of the Committee
1.
2.
3.
The Audit Committee shall consist of at least three directors. The Board shall appoint one member of the Audit
Committee to be the Chair of the Audit Committee.
Each director appointed to the Audit Committee by the Board must be independent. A director is independent if the
director has no direct or indirect material relationship with the Corporation. A material relationship means a
relationship which could, in the view of the Board, reasonably interfere with the exercise of the director's
independent judgment. In determining whether a director is independent of management, the Board shall make
reference to National Instrument 52-110 – Audit Committees or the then current legislation, rules, policies and
instruments of applicable regulatory authorities.
Each member of the Audit Committee shall be “financially literate”. In order to be financially literate, a director must
be, at a minimum, able to read and understand financial statements that present a breadth and complexity of
accounting issues generally comparable to the breadth and complexity of issues expected to be raised by the
Corporation's financial statements.
4.
A director appointed by the Board to the Audit Committee shall be a member of the Audit Committee until replaced
by the Board or until his or her resignation.
Meetings of the Committee
1.
2.
The Audit Committee shall convene a minimum of four times each year at such times and places as may be
designated by the Chair of the Audit Committee and whenever a meeting is requested by the Board, a member of
the Audit Committee, the auditors, or a senior officer of the Corporation. Meetings of the Audit Committee shall
correspond with the review of the quarterly financial statements and management discussion and analysis of the
Corporation.
Notice of each meeting of the Audit Committee shall be given to each member of the Audit Committee. The auditors
shall be given notice of each meeting of the Audit Committee at which financial statements of the Corporation are to
be considered and such other meetings as determined by the Chair and shall be entitled to attend each such meeting
of the Audit Committee.
3.
Notice of a meeting of the Audit Committee shall:
(a)
(b)
(c)
(d)
be in writing;
state the nature of the business to be transacted at the meeting in reasonable detail;
to the extent practicable, be accompanied by copies of documentation to be considered at the meeting;
and
be given at least two business days prior to the time stipulated for the meeting or such shorter period as the
members of the Audit Committee may permit.
4.
5.
6.
7.
8.
A quorum for the transaction of business at a meeting of the Audit Committee shall consist of a majority of the
members of the Audit Committee. However, it shall be the practice of the Audit Committee to require review, and, if
necessary, approval of certain important matters by all members of the Audit Committee.
A member or members of the Audit Committee may participate in a meeting of the Audit Committee by means of
such telephonic, electronic or other communication facilities, as permits all persons participating in the meeting to
communicate adequately with each other. A member participating in such a meeting by any such means is deemed
to be present at the meeting.
In the absence of the Chair of the Audit Committee, the members of the Audit Committee shall choose one of the
members present to be Chair of the meeting. In addition, the members of the Audit Committee shall choose one of
the persons present to be the Secretary of the meeting.
The Chairman of the Board, senior management of the Corporation and other parties may attend meetings of the
Audit Committee; however the Audit Committee (i) shall meet with the external auditors independent of
management as necessary, in the sole discretion of the Committee, but in any event, not less than quarterly; and (ii)
may meet separately with management.
Minutes shall be kept of all meetings of the Audit Committee and shall be signed by the Chair and the Secretary of
the meeting.
Duties and Responsibilities of the Committee
1.
2.
3.
4.
It is the responsibility of the Audit Committee to oversee the work of the external auditors, including resolution of
disagreements between management and the external auditors regarding financial reporting. The external auditors
shall report directly to the Audit Committee.
The Audit Committee shall, in the exercise of its powers, authorities and discretion so authorized, conform to any
regulations or restrictions that may from time to time be made or imposed upon it by the Board or the legislation,
policies or regulations governing the Corporation and its business.
It is the responsibility of the Audit Committee to satisfy itself on behalf of the Board that the Corporation’s system of
internal controls over financial reporting and disclosure controls and procedures are satisfactory for the purpose of:
(a)
(b)
identifying, monitoring and mitigating the principal risks;
ensuring compliance with legal, ethical and regulatory requirements;
and to review with the external auditors their assessment of the internal controls over financial reporting and the
disclosure controls of the Corporation, their written reports containing recommendations for improvement, and
management’s response and any follow-up to any identified weaknesses.
It is the responsibility of the Audit Committee to review the annual financial statements of the Corporation and, if
deemed appropriate, recommend the financial statements to the Board for approval. This process should include
but be not to be limited to:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
reviewing and accepting, if appropriate, the annual audit plan of the external auditors of the Corporation,
including the scope of audit activities, and monitor such plan’s progress and results during the year;
reviewing changes in accounting principles, or in their application, which may have a material impact on the
current or future years’ financial statements;
reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;
reviewing the methods used to account for significant unusual or non-recurring transactions;
ascertaining compliance with covenants under loan agreements;
reviewing disclosure requirements for commitments and contingencies;
reviewing adjustments raised by the external auditors, whether or not included in the financial statements;
reviewing unresolved differences between management and the external auditors;
obtain explanations of significant variances with comparative reporting periods;
review of business systems changes and implications;
review of authority and approval limits;
review the adequacy and effectiveness of the accounting and internal control policies of the Corporation
and procedures through inquiry and discussions with the external auditors and management;
(m)
confirm through private discussion with the external auditors and the management that no management
restrictions are being placed on the scope of the external auditors’ work;
(n)
review of tax policy issues; and
(o)
review of emerging accounting issues that could have an impact on the Corporation.
5.
It is the responsibility Audit Committee to review the interim financial statements of the Corporation and, if deemed
appropriate, to recommend the financial statements to the Board for approval and to review all related
management discussion and analysis. The Audit Committee must be satisfied that adequate procedures are in place
for the review of the Corporation’s disclosure of all other financial information and shall periodically assess the
accuracy of those procedures.
6.
The Audit Committee shall have the authority to:
(a)
(b)
(c)
(d)
inspect any and all of the books and records of the Corporation, its subsidiaries and affiliates;
discuss with the management and senior staff of the Corporation, its subsidiaries and affiliates, any affected
party and the external auditors, such accounts, records and other matters as any member of the Audit
Committee considers necessary and appropriate;
engage independent counsel and other advisors as it determines necessary to carry out its duties; and
to set and pay the compensation for any advisors employed by the Audit Committee.
7.
With respect to the appointment of external auditors by the Board, the Audit Committee shall:
(a)
(b)
(c)
(d)
(e)
recommend to the Board the appointment of the external auditors;
review the performance of the external auditors and make recommendations to the Board regarding the
replacement or termination of the external auditors when circumstances warrant;
oversee the independence of the external auditors by, among other things, requiring the external auditors
to deliver to the Audit Committee, on a periodic basis, a formal written statement delineating all
relationships between the external auditors and the Corporation and its subsidiaries;
recommend to the Board the terms of engagement of the external auditor, including the compensation of
the auditors and a confirmation that the external auditors shall report directly to the Committee; and
when there is to be a change in auditors, review the issues related to the change and the information to be
included in the required notice to securities regulators of such change.
8.
9.
10.
Audit Committee shall review annually with the external auditors their plan for their audit and, upon completion of
the audit, their reports upon the financial statements of the Corporation and its subsidiaries.
The Audit Committee must pre-approve all non-audit services to be provided to the Corporation or its subsidiaries by
external auditors. The Audit Committee may delegate, to one or more members, the authority to pre-approve non-
audit services, provided that the member report to the Audit Committee at the next scheduled meeting and such
pre-approval and the member comply with such other procedures as may be established by the Audit Committee
form time to time.
The Audit Committee shall review the risk management policies and procedures of the Corporation (i.e. hedging,
litigation and insurance), including the annual review of insurance coverage and make appropriate recommendations
to the Board with respect thereto.
11.
The Audit Committee shall establish and maintain procedures for:
(a)
the receipt, retention and treatment of complaints received by the Corporation regarding accounting
controls, or auditing matters; and
(b)
the confidential, anonymous submission by employees of the Corporation of concerns regarding
questionable accounting or auditing matters.
12.
13.
14.
The Audit Committee shall review and approve the Corporation’s hiring policies regarding employees and former
employees of the present and former external auditors or auditing matters.
The Audit Committee shall periodically report the results of reviews undertaken and any associated
recommendations to the Board.
The Audit Committee shall assess, on an annual basis, the adequacy of this Mandate and the performance of the
Audit Committee.