exh1-1.htm

ANNUAL INFORMATION FORM

(Except as otherwise noted the

information herein is given

as at December 31, 2010)

March 25, 2011

TABLE OF CONTENTS

Page

ABBREVIATIONS	1
CONVERSIONS	1
DEFINITIONS	2
GLOSSARY OF TECHNICAL TERMS	5
CURRENCY	8
FORWARD-LOOKING INFORMATION	8
SHARE CONSOLIDATION	11
SONDE RESOURCES CORP.	12
GENERAL DEVELOPMENT OF THE BUSINESS	13
DESCRIPTION OF THE BUSINESS	16
PRINCIPAL PROPERTIES	22
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	24
RISK FACTORS	32
INDUSTRY CONDITIONS	41
DIVIDENDS	43
DESCRIPTION OF SHARE CAPITAL	43
MARKET FOR SECURITIES	45
PRIOR SALES	45
ESCROWED SECURITIES	45
DIRECTORS AND OFFICERS	45
AUDIT COMMITTEE	48
LEGAL AND REGULATORY PROCEEDINGS	49
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	50
TRANSFER AGENT AND REGISTRAR	50
MATERIAL CONTRACTS	50
INTERESTS OF EXPERTS	50
ADDITIONAL INFORMATION	50

APPENDIX "A" REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	A1
APPENDIX "B" REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	B1
APPENDIX "C" CHARTER OF THE AUDIT COMMITTEE OF SONDE RESOURCES CORP.	C2

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ABBREVIATIONS

In this Annual Information Form, the following abbreviations have the meanings set forth below.

Oil, Natural Gas Liquids and Natural Gas

bbl	barrel
Mbbl	thousand barrels
MMbbl	million barrels
bbl/d	barrel or barrels per day
Mcf	thousand cubic feet
MMcf	million cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
MMBtu	million British Thermal Units
MMscf/d	million standard cubic feet per day of gas
Bcf	billion cubic feet
Tcf	trillion cubic feet
GJ	gigajoule

Other
AECO	a natural gas storage facility located at Suffield, Alberta
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28 °API or higher is generally referred to as light crude oil
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead
BOE/d	barrels of oil equivalent per day
m3	cubic metres
MBOE	1,000 barrels of oil equivalent
$M	thousands of dollars
$MM	millions of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
3D	three dimensional seismic

CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
Mcf	1,000 m3 of gas	0.028
1,000 m3 of gas	Mcf	35.493
bbl	m3 of oil	0.158
m3 of oil	bbl	6.290
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
GJ	MMBtu	0.950

DEFINITIONS

In this Annual Information Form, the following words and phrases have the meanings specified below, unless the context otherwise requires.

"7th of November Block" means the "7th of November" Block, covering approximately 310,799 hectares (768,000 acres) located approximately 121 kilometres (75 miles) offshore the Mediterranean Gulf of Gabes as described in and subject to the terms of the EPSA.

"7th of November Block JOA" means the joint operating agreement dated July 5, 2010 between the Company and Sahara in respect of the 7th of November Block.

"7th of November Block Participation Agreement" means the Participation Agreement dated July 5, 2008 between the Company and Sahara in respect of the 7th of November Block.

"ABCA" means the Business Corporations Act (Alberta), including the regulations promulgated thereunder, as amended from time to time.

"Arrangement" means the plan of arrangement under section 192 of the CBCA involving the Company, Challenger and the Challenger Shareholders.

"Arrangement Agreement" means the Arrangement Agreement dated June 18, 2009 between the Company and Challenger in respect of the Arrangement.

"BG" means BG International Limited, a wholly-owned subsidiary of BG Group PLC.

"BG Arbitration" means the BG arbitration proceedings against the Company in accordance with the provisions of the Block 5(c) JOA, alleging various breaches of the Block 5(c) JOA by the Company as initiated on February 9, 2009.

"BG Sale Agreement" means the Sale Agreement dated June 30, 2009 between the Company and BG in respect of the purchase of a 45% interest in Block 5(c) by BG.

"Block 5(c)" means the "Intrepid" Block 5(c), covering approximately 32,383 hectares (80,041 acres) located approximately 97 kilometres (60 miles) off the east coast of Trinidad in the Columbus Basin as described in and subject to the terms of the PSC.

"Block 5(c) Participation Agreement" means the Participation Agreement dated November 17, 2004 between the Company and Challenger in respect of Block 5(c) as amended and restated by the Amended and Restated Participation Agreement dated December 30, 2005 and as further amended and ratified by two Amendment and Ratification to Amended and Restated Participation Agreements dated August 11, 2007 and made effective August 1, 2007 and August 11, 2007.

"Block 5(c) JOA" means the Block 5(c) JOA dated August 11, 2007 between the Company, BG and Challenger in respect of Block 5(c).

"Board" means the board of directors of the Company.

"Bridge Facility" means the interim short-term $14,000,000 bridge facility entered into with Challenger on September 23, 2008.

"Sonde" or the "Company" means Sonde Resources Corp. and all of its subsidiaries, unless the context otherwise requires.

"CBCA" means the Canada Business Corporations Act, including the regulations promulgated thereunder, as amended from time to time.

"CCAA" means the Companies' Creditors Arrangement Act, including the regulations promulgated thereunder, as amended from time to time.

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"CCAA Proceedings" means the proceedings commenced by the Company, Canadian Superior Trinidad and Tobago Limited (now Sonde Resources Trinidad and Tobago Limited) and Seeker under the CCAA pursuant to an order of the Court dated March 5, 2009.

"Centrica" means Centrica Resources Limited.

"Challenger" means Challenger Energy Corp.

"Challenger CCAA Proceedings" means the proceedings commenced by Challenger and Challenger Energy Trinidad and Tobago Ltd. under the CCAA pursuant to an order of the Court dated February 27, 2009.

"Challenger Meeting" means the annual and special meeting of Challenger Shareholders held on August 7, 2009.

"Challenger Shareholders" means the former holders of Challenger Shares and "Challenger Shareholder" means any one of them.

"Challenger Shares" means the common shares in the capital of Challenger.

"Crown Lands" means leases granted by a Canadian Provincial authority.

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook.

"Common Shares" means the common shares in the capital of the Company.

"Compromise Agreement" means the Compromise Agreement dated July 30, 2009 between the Company and BG.

"COP 15" means the United Nation's Framework Convention on Climate Change 15th session of the Conference of Parties.

"COP 16" means the United Nation's Framework Convention on Climate Change 16th session of the Conference of the Parties.

"Court" means the Court of Queen's Bench of Alberta.

"EPSA" means the Exploration and Production Sharing Agreement dated August 27, 2008 between the Company and Joint Oil.

"ETAP" means Entreprise Tunisienne d'Activities Petrolicres.

"Exploration and Production License" means the Exploration and Production License granted on July 27, 2007 to the Company and its joint venture partner by MEEI in respect of MG Block.

"Federal Plan" means the Framework as amended by the Update.

"Framework" means the 'Regulatory Framework for Air Emissions' paper released by the Government of Canada on April 26, 2007.

"Financial Advisor" means Jennings Capital Inc.

"GHG emissions" or "GHGs" means, collectively, carbon dioxide, methane, nitrous oxide and other emissions.

"GLJ" means GLJ Petroleum Consultants Ltd.

"GLJ Report" means the report dated March 9, 2011 prepared by GLJ evaluating the oil, NGL and natural gas reserves attributable to the properties of the Company effective December 31, 2010.

"Independent Committee" means the independent committee of the Board.

"Interim Order" means the order of the Court dated July 10, 2009 ordering the Challenger Meeting and setting out certain declarations and directions in respect of the Arrangement and the holding of the Challenger Meeting.

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"Joint Oil" means the Joint Exploration, Production, and Petroleum Services Company that is owned equally by the Tunisian government via ETAP and the Libyan government via Libya Oil Holdings.

"Libyan Sanctions" means the United Nations sanctions imposed on February 26, 2011 on the Libyan government and the consequent actions of the Canadian Government pursuant to the Special Economic Measures Act (Canada).

"LNG Project" means the proposed development of a LNG regasification project in U.S. federal waters offshore New Jersey.

"Mariner Block" means the "Mariner" Block, covering approximately 11,246 hectares (27,790 acres) located approximately 9 kilometres (5.6 miles) northeast of Sable Island, offshore Nova Scotia as described in and subject to the terms of the Mariner Exploration License 2409.

"MEEI" means the Trinidad and Tobago Ministry of Energy and Energy Industries.

"MG Block" means the "Mayaro/Guayaguayare" Block, covering approximately 23,522 hectares (58,080 acres) located approximately 6.4 kilometres (4 miles) off the east coast of Trinidad in the Columbus Basin as described in and subject to the terms of the Exploration and Production License.

"Monitor" means Hardie & Kelly Inc., the monitor appointed by the Court in the CCAA Proceedings.

"NI 51-101" means National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.

"NI 51-102" means National Instrument 51-102, Continuous Disclosure Obligations.

"Niko" means Niko Resources Ltd.

"Niko Sale Agreement" means the Sale Agreement dated December 21, 2010 between the Company and Niko in respect of the purchase of the Company’s interests in Block 5(c) and the assumption of certain liabilities in respect of the MG Block by Niko.

"NYSE Amex" means NYSE Amex LLC.

"OPEC" means the Organization of the Petroleum Exporting Countries.

"Options" means the options to acquire Common Shares issued under the stock option plan of the Company.

"Palo Alto" means Palo Alto Investors, LLC.

"Preferred Shares" means the preferred shares in the capital of the Company.

"PSC" means the Production Sharing Contract dated July 20, 2005 between the Company and the Government of the Republic of Trinidad and Tobago in respect of Block 5(c).

"Receiver" means Deloitte & Touche Inc.

"Receivership" means the appointment of the Receiver over the 70% participating interest in Block 5(c) not owned by BG.

"Receivership Order" means the February 11, 2009 order of the Court appointing Deloitte & Touche Inc. as receiver and manager of the 70% participating interest in Block 5(c) not owned by BG.

"Rights Plan" means the shareholder rights plan of the Company.

"Rights Plan Agreement" means the Shareholder Rights Plan Agreement dated June 3, 2010 between the Company and Valiant Trust Company.

"ROFR" means a right of first refusal.

"Sahara" means Canadian Sahara Inc.

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"Scotia Waterous" means Scotia Waterous (USA) Inc.

"SEC" means the United States Securities and Exchange Commission.

"Seeker" means Seeker Petroleum Ltd.

"Settlement Agreement" means the Settlement Agreement dated August 10, 2009 between the Company and Palo Alto.

"Series A Preferred Shares" means the Series A, 5% U.S. cumulative redeemable preferred shares in the capital of the Company.

"Series B Preferred Shares" means the Series B, 5% U.S. cumulative redeemable preferred shares in the capital of the Company.

"Shareholders" means the holders of Common Shares and "Shareholder" means any one of them.

"Stay" means the stay of all claims and actions against the assets of the Company, with the exception of the BG Arbitration, the Receivership and any steps taken by BG to respond to any steps taken to assert in any tribunal or court of competent jurisdiction or otherwise, the Company's rights in respect of its participating interest as described in the Block 5(c) JOA.

"Swap Agreement" means the "Mariner" Block Swap Agreement dated August 27, 2008 between the Company and Joint Oil in respect of the Mariner Block.

"Trinidad Sale Agreement" means the Purchase and Sale Agreement dated May 21, 2009 between the Company and Centrica relating to an interest in Block 5(c) approved by the Court on June 4, 2009.

"TSX" means the Toronto Stock Exchange.

"TSXV" means the TSX Venture Exchange.

"Update" means the 'Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions' paper released by the Government of Canada on March 10, 2008.

"U.S." or "United States" means the United States of America, its territories and possessions, any state of the United States, and the District of Columbia.

"West Coast" means West Coast Opportunity Fund, LLC.

GLOSSARY OF TECHNICAL TERMS

In this Annual Information Form, the following technical terms and acronyms have the meanings specified below.

"CBM" means coal based methane.

"crude oil" or "oil" as described in the COGE Handbook means a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

"development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a)

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

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(b)	drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;
(c)	acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
(d)	provide improved recovery systems.

"developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

"developed producing reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

"exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a)	costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");
(b)	costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
(c)	dry hole contributions and bottom hole contributions;
(d)	costs of drilling and equipping exploratory wells; and
(e)	costs of drilling exploratory type stratigraphic test wells.

"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.

"field" means a defined geographical area consisting of one or more pools.

"future net revenue" means the estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using constant prices or forecast prices and costs.

"future prices and costs" means future prices and costs that are:

(a)	generally accepted as being a reasonable outlook of the future;
(b)	if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Company is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"gross" means:

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(a)	in relation to the Company's interest in production or reserves, its "company gross reserves", which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company;
(b)	in relation to wells, the total number of wells in which the Company has an interest; and
(c)	in relation to properties, the total area of properties in which the Company has an interest.

"LNG" means liquefied natural gas.

"natural gas" as described in the COGE Handbook, means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

"natural gas liquids" or "NGL" as described in the COGE Handbook, means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

"net" means:

(a)	in relation to the Company's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves;
(b)	in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and
(c)	in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.

"operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

"possible reserves" are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

"probable reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"production" means the cumulative quantity of petroleum that has been recovered at a given date.

"property" includes:

(a)	fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;
(b)	royalty interests, production payments payable in oil or gas, and other non-operating interests in properties operated by others; and
(c)	an agreement with a foreign government or authority under which the Company participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).

but does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.

"proved property" means a property or part of a property to which reserves have been specifically attributed.

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"proved reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"reservoir" means a porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.

"service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.

"undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

"unproved property" means a property or part of a property to which no reserves have been specifically attributed.

"well abandonment costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the well site.

Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

CURRENCY

All dollar amounts set forth in this Annual Information Form are expressed in Canadian dollars, except where otherwise indicated. References to Canadian dollars or "$" are to the currency of Canada and references to U.S. dollars or "US$" are to the currency of the United States.

The following table sets forth: (i) the exchange rate in effect at the end of each of the periods indicated; (ii) the average of exchange rates in effect on the first business day of each month during such periods; and (iii) the high and low exchange rates during each such periods, in each case based on the Bank of Canada noon buying rate for one Canadian dollar as expressed in U.S. dollars.

	Year ended December 31
	2010	2009	2008
Rate at end of period	US$1.0054	US$0.9564	US$0.8166
Average rate during period	US$0.9674	US$0.8757	US$0.9381
High	US$0.9278	US$0.9748	US$1.0289
Low	US$1.0054	US$0.7698	US$0.7711

FORWARD-LOOKING INFORMATION

Certain information included in this Annual Information Form and the documents incorporated by reference herein constitutes forward-looking information under applicable securities legislation. Such forward-looking information is provided for the purpose of providing information about management's current expectations and plans relating to the

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future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this Annual Information Form and the documents incorporated by reference herein include, but is not limited to, information with respect to:

●	obtaining MEEI approval of the Niko Sale Agreement and closing the transactions contemplated therein;
●	volume and product mix of the Company's oil and gas production;
●	future oil and gas prices and interest rates in respect of the Company's commodity risk management programs;
●	future liquidity, creditworthiness and financial capacity;
●	volumes and estimated value of the Company's oil and gas reserves;
●	future results from operations and operating metrics;
●	the life of each of the Company's reserves;
●	future interest rates;
●	future costs, expenses and royalty rates;
●	future development, exploration and other expenditures;
●	the amount and timing of future asset retirement obligations, and
●	the Company's tax pools.

Furthermore, information relating to "reserves" is deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described can be recovered and profitable in the future. The assumptions relating to the reserves of the Company are discussed under "Statement of Reserves Data and Other Oil and Gas Information".

Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this Annual Information Form and the documents incorporated by reference herein, assumptions have been made regarding and are implicit in, among other things:

●	the ability to obtain MEEI approval of the Niko Sale Agreement and close the transactions contemplated therein;
●	the ability of the Company to implement a plan of development for the 7th of November Block;
●	the ability of the Company to obtain financing on acceptable terms;
●	field production rates and decline rates;
●	the ability of the Company to secure adequate product transportation;
●	the impact of increasing competition in or near the Company's properties;
●	the timely receipt of any required regulatory approvals;
●	the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner to develop its business;

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●	the Company's ability to operate the properties in a safe, efficient and effective manner;
●	the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;
●	the timing and costs of pipeline, storage and facility construction and expansion;
●	future oil and natural gas prices;
●	currency, exchange and interest rates;
●	the regulatory framework regarding royalties, taxes and environmental matters; and
●	the ability of the Company to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

By its nature, forward-looking information is subject to a number of risks and uncertainties, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks set forth under "Risk Factors" in this Annual Information Form, "Risk Management" in the financial statements of the Company for the year ended December 31, 2010 and "Risk Management" and "Risk Assessment" in the management discussion and analysis of the Company for the year ended December 31, 2010. The Company is exposed to several operational risks inherent in exploiting, developing, producing and marketing crude oil and natural gas. These risks include but are not limited to:

●	the failure to obtain MEEI approval of the Niko Sale Agreement and to close the transactions contemplated therein;
●	the unknown impact of the turmoil in Tunisia and Libya on the Company’s rights and obligations for the development of the 7th of November Block;
●	the unknown impact of the Libyan Sanctions on the Company's obligations and development of the 7th of November Block;
●	the unsettled and volatile political and security situations in Libya and Tunisia;
●	sufficient liquidity for future operations;
●	cost of capital risk to carry out the Company's operations;
●	economic risk of finding and producing reserves at a reasonable cost;
●	reliance on reserve estimates for the year as well as on acquisitions;
●	financial risk of marketing reserves at an acceptable price given market conditions;
●	fluctuations in commodity prices, foreign exchange and interest rates;
●	operational matters related to non-operated properties;
●	delays in business operations, pipeline restrictions, blowouts;
●	debt service and indebtedness may affect the market price of the Common Shares;
●	the continued availability of adequate debt and equity financing and cash flow to fund planned expenditures;
●	unforeseen title defects;
●	aboriginal land claims;
●	increased competition and the lack of availability of qualified personnel or management;

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●	loss of key personnel;
●	ability to attract key personnel, including the hiring of a Chief Financial Officer;
●	uncertainty of government policy changes;
●	the risk of carrying out operations with minimal environmental impact;
●	operational hazards and availability of insurance;
●	industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced;
●	general economic, market and business conditions;
●	competitive action by other companies;
●	the ability of suppliers to meet commitments;
●	stock market volatility;
●	obtaining required approvals of regulatory authorities;
●	creditworthiness of counterparties; and
●	failure to realize anticipated benefits of the Arrangement.

The forward-looking information contained in this Annual Information Form and the documents incorporated by reference herein are made as of the date of such documents and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by applicable securities laws. The forward-looking information contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement.

SHARE CONSOLIDATION

On June 3, 2010, the Company consolidated the Common Shares on a five-for-one basis. As such, unless otherwise specifically stated, information contained herein in respect of the Company's share capital which is: (i) as of a date that is prior to June 3, 2010, is presented on a pre-consolidation basis; and (ii) as of a date that is on or after June 3, 2010, is presented on a post-consolidation basis.

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SONDE RESOURCES CORP.

General

The Company was incorporated pursuant to the provisions of the ABCA as "297272 Alberta Ltd." on March 21, 1983. Subsequently, the articles of the Company have been amended as follows:

·	on April 17, 1993 to change the name of the Company to "KapaIua Gold Mines Ltd." and to remove the private company restrictions;
·	on November 16, 1993 to change the name of the Company to "Prize-Energy Inc." and to consolidate the issued and outstanding Common Shares on a one-for-five basis;
·	on January 19, 1999 to permit the appointment of additional directors between annual meetings of Shareholders and to restate the articles in a consolidated form;
·	on August 24, 2000 to change the name of the Company to "Canadian Superior Energy Inc." and to consolidate the issued and outstanding Common Shares on a one-for-two basis;
·	on January 31, 2006 to add the Series A Preferred Shares to the authorized share capital of the Company;
·	on February 3, 2010 to add the Series B Preferred Shares to the authorized share capital of the Company; and
·	on June 3, 2010 to change the name of the Company to "Sonde Resources Corp." and to consolidate the issued and outstanding Common Shares on a one-for-five basis.

The Company is a reporting issuer, or the equivalent, in the provinces of British Columbia, Alberta, Saskatchewan, Ontario, Quebec, Manitoba, Nova Scotia and Newfoundland. The Common Shares are listed and posted for trading on the TSX and the NYSE Amex (the successor exchange to the American Stock Exchange) under the symbol "SOQ".

The head office of the Company is located at 3200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6 and its registered office is located at 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2. In addition, the Company has offices located in Drumheller, Alberta; and Gammarth, Tunis, Tunisia. In 2011, the Company has closed or is closing its offices in Jersey City New Jersey, St. Clair, Port of Spain, Trinidad and Tobago.

Inter-Corporate Relationships

The percentage of votes attaching to all voting securities of the material subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by the Company, as well as the jurisdiction where the subsidiary was incorporated, continued, formed or organized, as the case may be, is set forth below.

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GENERAL DEVELOPMENT OF THE BUSINESS

General

The Company is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada , offshore Trinidad and Tobago (subject to obtaining MEEI approval to close the transactions contemplated in the Niko Sale Agreement), and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Company also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities.

Three Year History

The following is a description of the general development of the business of the Company over the last three financial years. For a description of the business of the Company, see "Description of the Business".

2008

On January 14, 2008, the Company announced the successful flow testing of the first zone of the "Victory" well, the first well drilled by the Company offshore Trinidad on Block 5(c).

On January 28, 2008, the Company announced the successful flow testing of the second zone of the "Victory" well, the first well drilled by the Company offshore Trinidad on Block 5(c).

On February 5, 2008, Messrs. Thompson and Snethun were appointed as the Chief Financial Officer of the Company and the Vice President, Western Canada of the Company, respectively.

On March 26, 2008, the Company acquired Seeker by way of a plan of arrangement under section 192 of the CBCA, for consideration of approximately $51.6 million, including assumed net debt of approximately $8.5 million. Approximately 7,651,866 Common Shares were issued and $22.2 million cash was paid in exchange for all of the issued and outstanding common shares of Seeker. The acquisition of Seeker was a significant acquisition for which disclosure was required under Part 8 of NI 51-102. A Business Acquisition Report on Form 51-102F4 was filed on June 4, 2008 in respect of the acquisition, a copy of which is available on SEDAR at www.sedar.com.

On May 20, 2008, the Company announced its participation in the LNG Project. The LNG Project was to be conducted by a 50/50 joint venture between the Company and Global LNG Inc. Under the terms of the joint venture agreement, the Company agreed to advance the first US$10.0 million of the pre-construction costs for the LNG Project. On August 13, 2009, the Company executed an agreement as a result of which the Company became the 100% owner of the LNG Project (through, its subsidiary, Liberty Natural Gas LLC) and became responsible for 100% of the ongoing costs.

On July 5, 2008, the Company entered into the 7th of November Block Participation Agreement with Sahara pursuant to which the parties agreed to jointly participate (on a 50/50 basis) in the acquisition of the exclusive right to explore for, develop and produce crude oil and natural gas from the 7th of November Block located offshore of Libya and Tunisia. Under the terms of the 7th of November Block Participation Agreement, upon execution of the EPSA granting such exploration, development and production rights, the Company was to use reasonable efforts to transfer a 50% participating interest in the EPSA to Sahara. Sahara's participating interest was to be held in trust by the Company until Sahara was recognized as a party to the EPSA. Sahara was obligated to pay its share of the project costs incurred after July 5, 2009.

On August 13, 2008, the Company announced the successful flow testing of the "Bounty" well, the second well drilled by the Company offshore Trinidad on Block 5(c).

On August 27, 2008, the Company entered into the EPSA with Joint Oil. Under the terms of the EPSA, the Company was named the operator of the 7th of November Block.

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Nova Scotia. If at the end of August 2011, no well is drilled on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million.

On September 3, 2008, the Company completed a private placement of 8,750,000 units, each unit comprised of one Common Share and one-half of a Common Share purchase warrant at a price of US$4.00 per unit for gross proceeds of approximately US$35.0 million. Each Common Share purchase warrant entitled the holder to purchase a Common Share for a period of one year at a price of US$4.75 per Common Share. By September 3, 2009, all of the outstanding Common Share purchase warrants issued as part of the private placement had expired.

On September 23, 2008, the Company entered into a Bridge Facility with Challenger to enable Challenger to close on a $30 million equity financing. On December 31, 2008, Challenger defaulted on repayment of the Bridge Facility.

On December 4, 2008, Craig McKenzie resigned as the Chief Executive Officer of the Company and as a member of the Board. Michael Coolen was appointed as the Chief Executive Officer of the Company.

On December 5, 2008, the Company completed a private placement of 10,323,581 Common Shares issued on a "flow-through" basis at a price of $1.55 per Common Share for gross proceeds of approximately $16.0 million.

2009

From February 2009 through September 2009, the Company and Challenger were involved in the CCAA Proceedings which are described in detail elsewhere in this Annual Information Form. See "Description of the Business - Bankruptcy and Similar Procedures."

On February 10, 2009, the Company announced its proposal to monetize a 25% or larger interest in Block 5(c) and its related discoveries, subject to acceptable terms and conditions, and subject to all required approvals.

On February 17, 2009, the Company received a demand letter from Canadian Western Bank for repayment of all amounts outstanding under the Company's $45.0 million credit facility with Canadian Western Bank by February 23, 2009.

On February 23, 2009, the Company advised that it had reached an accommodation with Canadian Western Bank whereby the demand for repayment of all amounts outstanding under the Company's credit facility with Canadian Western Bank was extended to February 27, 2009 (further extended on March 2, 2009 to March 12, 2009). The credit facility had been permanently reduced the previous week from $45.0 million to $37.5 million with a payment of approximately $7.5 million made to Canadian Western Bank by the Company from the sale of certain Western Canadian properties.

On March 3, 2009, the Company announced the successful flow testing of the "Endeavour" well, the third well drilled by the Company offshore Trinidad on Block 5(c).

On April 24, 2009, Messrs. Noval and Coolen ceased to be the Executive Chairman of the Board and the President, Chief Executive Officer and Chief Operating Officer of Corporation, respectively. Jake Harp was appointed Interim Chairman of the Board.

On April 30, 2009, Leif Snethun was appointed as the Chief Operating Officer of the Company.

On June 30, 2009, the Company entered into the BG Sale Agreement with respect of the purchase of its 45% interest in Block 5(c) by BG. For more information with respect to the BG Sale Agreement, see "Bankruptcy and Similar Procedures".

On September 9, 2009, the annual and special meeting of the Shareholders was held at which time the Shareholders approved the Arrangement and elected Messrs. Brittain, Chronister, Funk, Roach, Turnbull and Watkins as directors.

On September 14, 2009, Marvin Chronister was appointed as the Chairman of the Board.

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On September 15, 2009, the Company paid all amounts outstanding including accrued interest owed on its $37.5 million credit facility with Canadian Western Bank and obtained a new $25.0 million demand revolving credit facility with National Bank of Canada. See "Description of the Business - Bankruptcy and Similar Procedures - CCAA Proceedings".

On September 15, 2009, pursuant to the CCAA Proceedings, the Company acquired Challenger, by way of the Arrangement, for consideration of approximately $77.8 million, including assumed net debt of approximately $54.4 million. Approximately 27,728,346 Common Shares were issued in exchange for all of the issued and outstanding Challenger Shares. The Company also assumed 9,925,000 Challenger Share purchase warrants which were exercisable at a proportionally adjusted exercise price for Common Shares based on the same exchange ratio by which the Common Shares were issued for Challenger Shares under the Arrangement. By March 6, 2010, 9,725,000 Challenger Share purchase warrants assumed by the Company had expired or were exercised. For more information with respect to the Arrangement, see "Description of the Business - Bankruptcy and Similar Procedures".

On October 28, 2009, National Bank of Canada increased the Company's demand revolving credit facility from $25.0 million to $40.0 million. The credit facility is subject to its next scheduled review in April 2011.

On December 21, 2009, the Company announced that due to the current industry environment and market conditions, the Company allowed the Mayflower Exploration License 2406 and the Marauder Exploration License 2415, both offshore Nova Scotia, to lapse in favour of focusing on Trinidad and Tobago, Western Canada and North Africa. The Company extended the Mariner Exploration License 2409 until December 31, 2010.

2010

On January 18, 2010, James H.T. Riddell was appointed as a member of the Board.

On January 19, 2010, the Company completed a private placement of 114,424,238 Common Shares at a price of $0.52 per Common Share for gross proceeds of approximately $59.5 million.

On February 3, 2010, the Company converted the entire issued and outstanding Series A Preferred Shares in the aggregate principal amount of US$15,000,000 owned by West Coast for an equal number of Series B Preferred Shares and 2,500,000 Common Share purchase warrants. Each Common Share purchase warrant entitles West Coast to purchase a Common Share until December 31, 2011 at a price of US$0.65 per Common Share. For a description of the Series A Preferred Shares and the Series B Preferred Shares, see "Description of Share Capital - Series A Preferred Shares" and "Description of Share Capital - Series B Preferred Shares". For more information with respect to the conversion of the Series A Preferred Shares, see the Material Change Report of the Company dated February 4, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein.

On July 5, 2010, the Company and Sahara finalized the 7th of November Block JOA. In addition, the two parties entered into a clarification agreement which, among other matters, gave Sahara until September 15, 2010 to pay its share of costs, plus interest, incurred after April 1, 2010. Sahara's failure to pay its share of costs, plus interest, when due would constitute a default under the terms of the 7th of November Block JOA.

On September 16, 2010, the Company, as operator under the 7th of November Block JOA, the Company issued a Notice of Default to Sahara due to Sahara's failure to pay when due its share of joint account expenses associated with the 7th of November Block. Under the terms of the 7th of November Block JOA, a formal default period began 5 business days after issuance of that notice and Sahara had until October 15, 2010, to pay all outstanding joint account expenses associated with its 50% working interest in the 7th of November Block.

On September 24, 2010, Robb Thompson announced his decision to resign as the Chief Financial Officer of the Company to pursue other interests.

On October 20, 2010, the Company announced that Sahara had failed to cure its default under the 7th of November Block JOA and that the Company was therefore exercising its option to require that Sahara completely withdraw from the 7th of November Block, thereby forfeiting its 50% working interest to the Company. In response, Sahara filed for creditor protection under the Bankruptcy and Insolvency Act (Canada), with the intention of making a proposal to its creditors (including the Company).

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On October 21, 2010 Messrs. Schanck, Dirks and Barkwell were appointed the President and Chief Executive Officer, Chief Operating Officer, and Interim Chief Financial Officer of the Company, respectively.

On November 21, 2010, the Company announced that the Court had ruled in the Company's favour, dismissing the creditor protection previously afforded Sahara and lifting the stay protecting Sahara. As a result, Sahara was notified that Sonde was exercising its option to require that Sahara completely withdraw from the 7th of November Block, thereby forfeiting its 50% working interest to the Company.

On December 15, 2010, Jack W. Schanck was appointed as a member of the Board.

On December 21, 2010, the Company entered into the Niko Sale Agreement in respect of the purchase of its interests in Block 5(c) and the assumption of certain liabilities in respect of the MG Block by Niko. For more information with respect to the Niko Sale Agreement, see "Principal Properties - International - Offshore Trinidad and Tobago".

In December 2010, the Mariner Exploration License 2409 expired and at the end of August 2011, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million.

Recent Developments

On January 11, 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North -1 well on the 7th of November Block. The well has been temporarily abandoned while the Company evaluates the recoverable reserve scenarios, development options and cost estimates for the field's development.

On February 24, 2011, the Company announced that it had sold its subsidiary, Liberty Natural Gas LLC, which owned a 100% working interest in the LNG Project to an entity related to West Face Capital Inc. for US$1.0 million and an entitlement to receive a deferred cash consideration of US$12.5 million payable upon Liberty Natural Gas LLC's first successful gas delivery. The sale had an effective date of February 22, 2011.

On February 25, 2011, the Company closed on an acquisition/development demand note for $20 million secured by the Company's Western Canada development plans with a variable rate of interest (4.25% as of the date hereof). Repayment and the acquisition/development demand is scheduled to commence May 2011 at $0.6 million per month. The initial drawdown for the acquisition/development demand note was in March 2011.

On February 14, 2011, the Company entered into a commodity hedging contract which sets a floor of $4.11 based on the AECO index on 5,000 GJ per day of natural gas from March 1, 2011 until December 31, 2011 and a floor of US$100 on 250 bbl/d of crude oil from March 1, 2011 until December 31, 2012 based on the WTI index. The Company will receive the difference if either commodity goes below the contract price and remit to seller the amount that exceeds the contract price monthly.

Significant Acquisitions

The Company did not complete any significant acquisitions during the year ended December 31, 2010 for which disclosure was required under Part 8 of NI 51-102.

DESCRIPTION OF THE BUSINESS

General

The Company is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada offshore Trinidad and Tobago (subject to obtaining MEEI approval to close the transactions contemplated in the Niko Sale Agreement) and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Company also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities.

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Competitive Conditions

The oil and natural gas industry is intensely competitive in all its phases. The Company 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 Company's competitors include resource companies which have greater financial resources, staff and facilities than those of the Company. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Company 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. See "Risk Factors - Competition".

Cycles

The development of oil and gas reserves is dependent on access to areas where exploration and production is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.

Environmental Protection

The oil and gas industry is subject to environmental regulations pursuant to applicable legislation. Such legislation provides for restrictions and prohibitions on release or emission of various substances produced in association with certain oil and gas industry operations, and requires that well and facility sites be abandoned and reclaimed to the satisfaction of environmental authorities. As at December 31, 2010, the Company recorded an obligation on its balance sheet of $15.3 million for well abandonment costs. The Company maintains an insurance program consistent with industry practice to protect against losses due to accidental destruction of assets, well blowouts, pollution and other operating accidents or disruptions. The Company also has operational and emergency response procedures and safety and environmental programs in place to reduce potential loss exposure. No assurance can be given that the application of environmental laws to the business and operations of The Company will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect The Company's financial condition, results of operations or prospects. See "Risk Factors – Environmental Risks" and "Industry Conditions".

Employees

The Company has a total of 35 full-time staff, 8 staff members in its Drumheller, Alberta office, three staff members in its St. Clair, Port of Spain, Trinidad and Tobago office, and two consultants in its Gammarth, office.

Foreign Operations

In addition to its Canadian operations, The Company is engaged in the exploration for oil and natural gas in offshore Trinidad and Tobago (subject to obtaining MEEI approval to close the transactions contemplated in the Niko Sale Agreement) and North Africa. International oil and gas operations are subject to inherent risks and uncertainties which are beyond the control of the Company, particularly those associated with exploring for, and developing, economic quantities of hydrocarbons, volatile commodity prices, political risks, foreign exchange rates, issues relating to global supply and demand, government regulations, and environmental matters. The Company's international exploration ventures may entail certain political and technical business risks. The Company's strategy is to mitigate such risks by aligning itself with partners and engaging personnel and consultants that have international experience. The Company continues to monitor the recent turmoil in Libya and Tunisia and the Libyan Sanctions and their effect on the Company’s interests in North Africa. See "Risk Factors - Foreign Political and Security Issues", "Risk Factors - Foreign Operations", "Risk Factors - Foreign Legal Systems" and "Risk Factors - Foreign Currency Rates".

Bankruptcy and Similar Procedures

CCAA Proceedings

On February 8, 2009, BG served the Company with a default notice under the provisions of the Block 5(c) JOA, alleging various breaches of the Block 5(c) JOA by the Company. On February 9, 2009, BG initiated the BG Arbitration. On February 11, 2009, upon application of BG, the Receiver was appointed with respect to the 70%

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participating interest in Block 5(c) not owned by BG. Pursuant to the Receivership Order, the Receiver, in conjunction with BG, would operate Block 5(c). On April 21, 2009, BG took over as the operator of Block 5(c).

On February 12, 2009, Challenger received notification that BG had obtained an order appointing the Receiver. On February 27, 2009, Challenger obtained an order for protection under the CCAA. This order commenced the Challenger CCAA Proceedings and allowed Challenger to remain in possession and control of its property, carry on its business and retain employees and other service providers. Extensions to the initial order commencing the Challenger CCAA Proceedings were granted on March 23, 2009, April 20, 2009, June 4, 2009 and July 10, 2009 and protection for Challenger under the CCAA was extended to September 5, 2009.

On February 18, 2009, the Company served Challenger and BG with a default notice under the provisions of the Block 5(c) JOA alleging various breaches of the Block 5(c) JOA by one or both of BG and Challenger. A further default notice was served on Challenger by the Company on March 24, 2009 with respect to Challenger's obligations under the Block 5(c) Participation Agreement. In addition, on March 24, 2009, the Company served Challenger with a default notice under the Bridge Facility and the Block 5(c) JOA. The foregoing default notices issued against Challenger were stayed in accordance with the terms of the Challenger CCAA Proceedings.

On March 4, 2009, the Company filed an application with the Court for an order allowing the Company to prepare a plan of arrangement under the CCAA, and staying all claims and actions against the Company and its assets. On March 5, 2009, the application of the Company for an initial order granting protection under the CCAA was successful. The result of this successful application was that the Company was permitted to prepare a plan of arrangement, and all claims and actions against the assets of the Company, with the exception of the BG Arbitration, the Receivership and any steps taken by BG to respond to any steps taken to assert in any tribunal or court of competent jurisdiction or otherwise and the Company's rights in respect of its participating interest as described in the Block 5(c) JOA, were stayed. The initial order permitted the Company to remain in possession and control of its property, carry on its business and retain employees and other service providers. While this initial order was in effect, worked with the court-appointed Monitor and continued to implement a plan of arrangement for its creditors, which included the initiative to sell an undivided 45% interest in Block 5(c). The Company advised the Court that such a sale would allow the Company to restructure in an organized manner and emerge from the CCAA Proceedings in due course.

On March 11, 2009, the Company announced that the NYSE Amex had halted the trading of the Common Shares. In addition, the NYSE Amex advised the Company of its intention to file a delisting application with the SEC due to its determination that the Company had continuing listing deficiencies.

On March 25, 2009, the Court granted an order under the CCAA to extend the CCAA Proceedings. The extension of the March 5, 2009 initial order allowed the Company to continue to prepare a plan of arrangement for its creditors and continued the Stay. Further extensions of the CCAA Proceedings were granted on May 4, 2009, June 4, 2009 and July 23, 2009. The Stay expired on September 15, 2009.

On April 2, 2009, the Independent Committee retained the Financial Advisor. Under the terms of the engagement agreement between the parties, the Financial Advisor agreed to assist the Independent Committee in exploring and reviewing alternatives potentially available to the Company including, but not limited to, a sale of the Company, a recapitalization, an equity injection or a sale of certain assets with a view to the Company's successful emergence from the CCAA Proceedings.

On April 22, 2009, the Company attended a hearing with the NYSE Amex regarding its intention to file a delisting application with the SEC. Following the hearing, the NYSE Amex advised the Company that it had decided to withdraw its proposed delisting application and that the Common Shares would continue to be halted from trading for an interim period pending the resolution of the CCAA Proceedings.

On May 7, 2009, the Company announced that the NYSE Amex had reassessed its previous decision to halt the trading of the Common Shares. The NYSE Amex stated that the reassessment was based on its review of the May 4, 2009 order under the CCAA to extend the CCAA Proceedings and the filing of the Company's audited financial statements and related documents. The Common Shares resumed trading on the NYSE Amex on May 6, 2009.

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On July 10, 2009, the Court approved an Arrangement Agreement contemplating the Arrangement wherein the Company would acquire all the issued and outstanding Challenger Shares by the issuance of 0.51 Common Shares in exchange for each Challenger Share.

On July 27, 2009, the Company announced that the NYSE Amex had notified the Company that it continued to remain below certain continued listing standards as set forth in section 1003(a) (iv) of the NYSE Amex LLC Company Guide and that the NYSE Amex extended the date for compliance from July 31, 2009 to September 30, 2009.

On August 10, 2009, the Company entered into the Settlement Agreement with Palo Alto, a Shareholder, which as of the date of the Settlement Agreement held 9.3% of the Common Shares then outstanding. The provisions of the Settlement Agreement became effective upon approval of the Monitor and the Court in the CCAA Proceedings. Notable provisions of the Settlement Agreement were as follows:

·	the Company would nominate Messrs. Brittain, Chronister, Funk, Roach, Turnbull and Watkins (of whom the first four were proposed by Palo Alto) for election as directors and solicit proxies for their election at the annual and special meeting of the Shareholders to be held on September 9, 2009;
·	within 30 days of the Company emerging from CCAA protection, the Company would reimburse Palo Alto for recruitment costs of up to US$200,000 and legal costs of up to US$510,000; and
·	Palo Alto would vote its Common Shares in favour of the election of the nominees listed above and would withdraw its meeting requisition.

On August 17, 2009, the Company filed the Arrangement with the Court. The purpose of the Arrangement was to affect a compromise and settlement of all affected claims in order to allow the Company to restructure its affairs for the benefit of all stakeholders, with a view to expediting the recovery of amounts owed to obtain payment in full for the affected creditors. The details of the Arrangement are summarized as follows:

·	The Company would acquire all of the Challenger Shares pursuant to the terms of the Arrangement Agreement, including its 25% interest in Block 5(c);
·	The Receivership proceedings would be terminated;
·	BG would acquire a 45% interest in Block 5(c) from the Company for US$142.5 million;
·	BG would withhold two amounts from the purchase price, the first amount was the Receiver's claim of US$52.0 million plus costs (as contemplated in the Compromise Agreement) and the second amount was US$20.0 million to be held in escrow by BG as operator under the Block 5(c) JOA;
·	The Company would pay to the Monitor an amount sufficient to fund the affected creditors' pool and disputed claims reserve; and
·	The Company would enter into a new revolving credit facility and security agreement with a Canadian chartered bank for $25.0 million.

On September 9, 2009, the annual and special meeting of the Shareholders was held at which time the Shareholders voted in favour of the Arrangement Agreement and elected Messrs. Brittain, Chronister, Funk, Roach, Turnbull and Watkins as directors. The Challenger Shareholders approved the Arrangement Agreement on August 7, 2009.

On September 11, 2009, the creditors approved the Arrangement under the CCAA. On September 14, 2009, the Arrangement was sanctioned by the Court. The Arrangement was implemented following the various transactions that were completed on September 15, 2009. Accordingly, the Company emerged from CCAA protection.

On October 28, 2009, the Company announced that the TSX had completed its review of the Common Shares and determined that the Company had met the TSX's original listing requirements.

On November 30, 2009, the NYSE Amex advised the Company that it had resolved all continued listing deficiencies.

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Background to the Arrangement

On September 29, 2008, the Board appointed a special committee to deal with issues concerning Challenger's ability to fund its obligations under the Block 5(c) Participation Agreement.

On February 8, 2009, the Board resolved that the Company pursue the sale of a 25% interest or more in Block 5(c) and by an agreement dated February 19, 2009, the Company retained Scotia Waterous as its agent to facilitate such sale. Forty-three different companies were contacted from Scotia Waterous' offices in Calgary, Houston, London and Beijing, many of which companies executed confidentiality agreements and then had access to a virtual data room. Many of the interested parties also had detailed technical and commercial meetings with the Company and Scotia Waterous personnel. As a result of this process, several indicative proposals were received by Scotia Waterous by the due date, being March 23, 2009. Those parties submitting indicative bids were requested to make firm offers by no later than April 22, 2009 and two firm bids were received on that date from two large well capitalized international companies.

On April 1, 2009, the Board appointed the Independent Committee to direct, oversee, monitor and otherwise facilitate the Company's exploration and evaluation of various strategic alternatives to maximize value for the Shareholders and address the interests of the Company's creditors and other stakeholders. The Independent Committee retained the Financial Advisor as its financial advisor on April 2, 2009.

On April 6, 2009, the Independent Committee met with the Financial Advisor and various counsel. Counsel was instructed to pursue negotiations with respect to the sale of an interest in Block 5(c). The Financial Advisor was directed to conduct a limited auction process with respect to the Company's Western Canadian assets. The previously constituted special committee charged with dealing with issues between the Company and Challenger was dissolved and the Independent Committee assumed its mandate.

On April 23, 2009, the Independent Committee resolved to instruct the Financial Advisor to proceed, inter alia, with completing an analysis for an appropriate exchange ratio for a merger with Challenger, finalizing the economic terms with Challenger and preparing a letter of intent.

In late April, 2009, informal discussions began between members of the special committee and the Independent Committee, along with the Financial Advisor and Peters & Co. Limited, financial advisor to Challenger, with respect to the acquisition by the Company of Challenger and all of the assets of Challenger, including, but not limited to, Challenger's interest in Block 5(c). On May 5, 2009, Challenger and the Company entered into a confidentiality agreement.

On May 22, 2009, the Financial Advisor advised the Independent Committee that, given the progress being made on the Block 5(c) sales process and recapitalization process and the bids received, it was not advisable to proceed with the sale of the Western Canadian assets at that time.

On May 26, 2009, Challenger and the Company signed a non-binding letter of intent to negotiate a formal agreement to effect the acquisition by the Company of Challenger, subject to the negotiation of definitive agreements, the satisfactory completion of due diligence and receipt of board approvals. Between May 5, 2009 and June 17, 2009, Challenger and the Company completed their respective financial and legal due diligence reviews of each other, and during this time they began negotiating the terms of the Arrangement Agreement. Between May 5, 2009 and June 18, 2009, members of the Independent Committee, along with the Financial Advisor, met on numerous occasions to discuss the terms of the proposed business combination with Challenger.

On June 2, 2009, the Company entered into an agreement of purchase and sale with Centrica, under which Centrica agreed to acquire from the Company a 45% interest in Block 5(c) for approximately US$142.5 million in cash. On May 22, 2009, the Board approved the sale and the transactions contemplated in the Trinidad Sale Agreement. The transactions were subject to the satisfaction of certain conditions including satisfaction of the ROFR held by other parties to the Block 5(c) JOA and to approvals of the Court and the Government of the Republic of Trinidad and Tobago. On June 30, 2009, BG sent a notice to the Company and to Challenger advising both parties that BG was electing to exercise its ROFR, as provided by the Block 5(c) JOA, to purchase the 45% interest in Block 5(c) that the Company has agreed to sell to Centrica. Following the receipt of the notice of exercise of the ROFR, BG and the Company entered into negotiations to finalize the terms of a sale agreement for the purchase of a 45% interest in Block 5(c) by BG. On June 30, 2009, the BG Sale Agreement was entered into.

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On June 11, 2009, the Independent Committee met formally to consider the Arrangement Agreement and the Independent Committee's recommendation to the Board. The Independent Committee was updated on the status of the Arrangement Agreement and reviewed the terms and conditions of the Arrangement Agreement including the exchange ratio.

After discussions and after reviewing: (i) the advice of the Financial Advisor, including their verbal fairness opinion; (ii) legal advice as to the terms of the Arrangement Agreement; (iii) the impact of the Arrangement Agreement and merger with Challenger on the Trinidad Sale Agreement; (iv) the alternatives available to the Company under the CCAA Proceedings; and (v) the impact on the Company if the CCAA Proceedings are not satisfied completely, the Independent Committee unanimously concluded that it recommend to the Board that the Board approve the proposed Arrangement.

On June 11, 2009, the Board, having received an oral fairness opinion from the Financial Advisor, approved the execution of the Arrangement Agreement.

On June 18, 2009, the board of directors of Challenger, on recommendation of special committee of the board of directors of Challenger and with the benefit of an oral opinion from Peters & Co. Limited, its financial advisor, as to the fairness of the Arrangement to the Challenger Shareholders, approved the execution of the Arrangement Agreement. The Arrangement Agreement was executed on June 18, 2009. The Arrangement was announced prior to the opening of markets on June 19, 2009.

On July 10, 2009 Challenger obtained the Interim Order.

On July 30, 2009, BG and the Company entered into the Compromise Agreement, under which the Company agreed to pay BG the Receiver's claim of US$52.0 million plus costs in full and complete satisfaction of all BG claims and actions against the Company and Challenger under the CCAA Proceedings and the Challenger CCAA Proceedings, respectively. In accordance with the Compromise Agreement, the settlement amount was set off against the US$142.5 million purchase price for the 45% interest in Block 5(c) under the BG Sale Agreement.

The Challenger Shareholders approved the Arrangement Agreement on August 7, 2009.

Social or Environmental Policies

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Company. To this end, the Company has instituted health and safety policies and programs and endeavours to conduct its operations in a manner that will minimize both adverse effects and consequences of emergency situations by:

·	complying with government regulations and standards, particularly relating to the environment, health and safety;
·	conducting operations consistent with industry codes, practises and guidelines;
·	ensuring prompt, effective response and repair to emergency situations and environmental incidents;
·	providing training to employees and contractors to ensure compliance with corporate safety and environmental rules and procedures; and
·	communicating openly with members of the public regarding its activities.

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The Company believes that all employees have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

PRINCIPAL PROPERTIES

A summary description of the Company's major producing and exploration properties is set out below. References to gross volumes refer to total production. References to net volumes refer to the Company's working interest share before the deduction of royalties payable to others.

Western Canada

The Company derives all of its production and cash flow from Western Canada. We are now summarizing regional data by cash generating units (“CGU”). Approximately 65% of the Company's production comes from the Drumheller area of Alberta (Southern Alberta CGU). The balance of production largely comes from the Kaybob/Windfall (Central Alberta CGU) and Boundary Lake/Eaglesham areas (Northern Alberta CGU).

No new wells were drilled in 2010; instead the Company concentrated on an extensive portfolio of suspended wells. The Company re-entered and re-completed 12 wells (all operated), and performed 19 additional work-over's, with an aggregate economic success rate of 89%. Despite the lack of drilling, this program effectively eliminated base decline in the third and fourth quarter. The Company ended the year at an average daily net production rate of approximately 2,800 BOE/d (83% natural gas), compared to average net production at December 31, 2009 of 2,897 BOD/d. In addition, The Company had approximately 700 gross BOE/d awaiting tie-in at year-end 2010.

At December 31, 2010, the Company held 446,222 gross / 316,760 net acres in Western Canada the majority of which is operated by the Company.

Drumheller

Drumheller contains a wide variety of low-moderate risk operated development opportunities for oil, Cretaceous tight gas sands, and Cretaceous CBM, vertically-stacked on a concentrated, high working interest land position. Of particular importance are operated positions in six oil pools, the largest of which are the Mannville I pool (lower Cretaceous Ellerslie sandstone) and the Michichi Detrital pool (lower Cretaceous Detrital sandstone). The Company is planning a multi-year re-development of these oil pools using horizontal drilling and multi-stage fracturing technology, and has identified 65 future horizontal oil infill locations.

In addition, the Company owns over 150 locations in the form of both producing and suspended vertical wells that hold potential for re-development of existing zones and development of new, principally shallower non-producing zones. The Company plans an aggressive work-over and re-development program targeting the Cretaceous Ellerslie, Glauconitic and Viking formations in these locations during 2011.

Kaybob/Windfall

The Company's Kaybob/Windfall area assets contain a series of vertically-stacked Cretaceous and Jurassic tight gas sand development opportunities, of principal importance being the Windfall Gething pool. The Company had good success proving the economic viability and a geographic limit of this liquids-rich gas play with two vertical re-entries in 2010, and is preparing to develop the pool using horizontal wells and multi-stage fracturing. The Company has identified 14 horizontal development locations on its acreage base and plans proof-of-concept drilling at two of these locations in 2011. In addition, the Company holds a number of attractive re-entry candidates targeting Jurassic Nordegg and Cretaceous Viking tight gas sands, and plans a modest re-development program targeting these wells in 2011.

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International

Offshore North Africa (Tunisia and Libya)

The Company acquired the Exploration and Production concession for the 768,000 acre 7th of November Block, offshore Tunisia and Libya, on August 27, 2008. The exploration work commitment for the first phase (four years) of the seven year exploration period includes three exploration wells, 500 square kilometres (311 square miles) of 3D seismic, and one appraisal well. The Company holds a 100% working interest in the concession.

The appraisal well obligation was satisfied by drilling the Zarat North-1, which was temporarily abandoned on January 11, 2011 while the Company evaluates the recoverable reserve scenarios, development options and cost estimates for the field’s development. The well was the third drilled on the large Zarat anticlinal feature, following two wells drilled by Marathon in 1992 and 1994, respectively. It encountered 240 net feet of gas/condensate and oil pay in the Eocene El Gueria limestone, with oil/water and gas/oil contacts at the same structural elevation found in the Marathon wells. Tested in three separate intervals, the Zarat North-1 flowed at sustained rates averaging eight MMcf/d of natural gas plus 750 bbl/d of condensate. The Company is currently evaluating the commercial development potential of the feature, as well as discussing unitization options with owners of an adjacent concession. In 2011, the Company will continue fulfilling its obligations to the concession by shooting approximately 600 square kilometres of new 3D seismic at Zarat North-1 and at one additional exploration lead, and preparation for two additional wells in early 2012. Both the governments of Tunisia and Libya are in political turmoil. During January, 2011, protests in Tunisia led to the overthrow of the government. Election of a new national constituent assembly is scheduled to take place on July 24, 2011 and while relative calm has been restored, uncertainty remains over the future direction of the country. Similarly, widespread protests over the government in Libya have occurred and a state of war exists between government and opposition forces. This has led to the cessation of oil production in the country, military intervention by Western forces and the imposition of Libyan Sanctions. While this turmoil has not had a direct impact on the Company’s 7th of November Block current activities it may significantly and adversely affect the Company including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, make payments to Joint Oil and the ability to attract joint venture partners or financing.

All of the activity related to this concession will be monitored by the Company to ascertain the impact if any of the turmoil in Tunisia and Libya and the impact, if any of the Libyan Sanctions.

Offshore Trinidad and Tobago

Offshore Nova Scotia, Canada

The Company relinquished Mariner Exploration License 2409 in December 2010, its remaining assets in Eastern Canada.

Pursuant to the Swap Agreement, Joint Oil was awarded an overriding royalty interest and optional participating interest in the Mariner Block as part of the contract to obtain the concession in the 7th of November Block. If at the end of August 2011, no well is drilled on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million. As the Mariner Block has now been relinquished, the Company will enter in discussions with Joint Oil to seek alternatives settlement options. No assurance can be given that the Company will succeed in mitigating its obligations. In addition, the Company will need to monitor the impact, if any, of the Libyan Sanctions on the foregoing.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

GLJ prepared the GLJ Report in accordance with NI 51-101. The GLJ Report evaluated, as at December 31, 2010, the oil, NGL and natural gas reserves attributable to the properties of the Company. All of the Company's reserves are located in the Canadian provinces of, Alberta, British Columbia and Saskatchewan.

The tables below are summaries of the oil, NGL and natural gas reserves of the Company and the net present value of future net revenue attributable to such reserves as summarized in the GLJ Report based on forecast price and cost assumptions. The tables summarize the data contained in the GLJ 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 the Company's 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 GLJ. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Company's reserves estimated by GLJ 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 the Company's oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The values shown for income taxes and future net revenue after income taxes were calculated on a stand-alone basis in the GLJ Report. The values shown may not be representative of future income tax obligations, applicable tax horizon or after tax valuation.

The GLJ Report is based on certain factual data supplied by the Company and GLJ's opinions of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company's petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Company to GLJ and accepted without any further investigation. GLJ accepted this data as presented and neither title searches nor field inspections were conducted.

Summary of Oil and Gas Reserves

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	NGLs	Natural Gas	Light and Medium Crude Oil	NGLs	Natural Gas
Reserve Category	Mbbls	Mbbls	MMcf	Mbbls	Mbbls	MMcf
Proved
Developed Producing	815	209	19,197	724	140	16,855
Developed Non-Producing	43	99	5,954	40	69	5,218
Undeveloped	10	3	4,187	9	2	3,871
Total Proved	868	312	29,339	774	211	25,943
Probable	812	183	18,773	672	122	16,535
Total Proved Plus Probable	1,680	495	48,112	1,445	333	42,478

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Summary of Net Present Value of Future Net Revenue

	Before Future Income Tax Expenses and Discounted at (%/year)
	0%	5%	10%	15%	20%
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	94,602	75,897	63,897	55,489	49,259
Developed Non-Producing	17,767	14,796	12,610	10,941	9,630
Undeveloped	7,760	4,690	2,814	1,641	893
Total Proved	120,128	95,382	79,320	68,071	59,782
Probable	91,939	61,926	44,827	34,133	26,972
Total Proved Plus Probable	212,067	157,308	124,148	102,204	86,754

	After Future Income Tax Expenses and Discounted at (%/year)
	0%	5%	10%	15%	20%
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	94,602	75,897	63,897	55,489	49,259
Developed Non-Producing	17,767	14,796	12,610	10,941	9,630
Undeveloped	7,760	4,690	2,814	1,641	893
Total Proved	120,128	95,382	79,320	68,071	59,782
Probable	91,939	61,926	44,827	34,133	26,972
Total Proved Plus Probable	212,067	157,308	124,148	102,204	86,754

Total Future Net Revenue (Undiscounted)

	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Future Income Tax Expenses	Future Income Tax Expenses	Future Net Revenue After Future Income Taxes Expenses
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved	268,327	29,478	100,578	11,226	6,917	120,128	-	120,128
Total Proved Plus Probable	486,936	58,398	186,339	21,457	8,675	212,067	-	212,067

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Future Net Revenue By Production Group

	Future Net Revenue Before Future Income Tax Expenses and Discounted at 10%/year(1)	Unit Value Before Future Income Tax Expenses and Discounted at 10%/year
Reserve Category and Product Group	(M$)	($/BOE)
Total Proved
Light and Medium Crude Oil	30,159	29.53
Associated Gas and Non-Associated Gas	46,716	13.01
Non-Conventional Oil and Gas Activities (CBM)	2,445	3.51
Total	79,320	14.94
Total Proved Plus Probable
Light and Medium Crude Oil	47,170	25.07
Associated Gas and Non-Associated Gas	71,622	12.69
Non-Conventional Oil and Gas Activities (CBM)	5,322	4.02
Total	124,148	14.02

Note:

(1)	Other revenue and costs not related to a specific production group have been allocated proportionately to production groups.

Summary of Pricing, Exchange Rate and Inflation Rate Assumptions

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2010 in estimating the Company's reserves data, using forecast prices and costs.

												Alberta NGLs
		Bank of Canada Average Noon Exchange Rate	NYMEX WTI Near Month Futures Contract Crude Oil at Cushing Oklahoma	ICE BRENT Near Month Futures Contract Crude Oil FOB North Sea	Light Sweet Crude Oil (40 API, 0.3%S) at Edmonton	Bow River Crude Oil Stream Quality at Hardisty	Lloyd Blend Crude Oil Stream Quality at Hardisty	WCS Crude Oil Stream Quality at Hardisty	Heavy Crude Oil Proxy (12 API) at Hardisty	Light Crude Oil (35 API, 1.2 %S) at Cromer	Medium Crude Oil (29 API, 2.0%S) at Cromer	Spec Ethane	Edmonton Propane	Edmonton Butane	Edmonton Pentanes Plus
Year	Infla- tion %	$US/$	$US/bbl	$US/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl
2011	2	0.98	88.00	88.50	86.22	75.87	74.58	74.98	68.79	84.07	82.78	13.66	54.32	67.26	90.54
2012	2	0.98	89.00	88.25	89.29	75.89	74.55	74.95	68.33	84.38	83.04	15.68	56.25	68.75	91.96
2013	2	0.98	90.00	88.50	90.92	75.10	73.73	74.13	67.03	85.01	83.64	17.62	57.28	70.01	92.74
2014	2	0.98	92.00	90.50	92.96	76.23	74.83	75.23	67.84	86.45	84.59	19.21	58.56	71.58	94.82
2015	2	0.98	95.17	93.67	96.19	78.88	77.44	77.84	70.23	89.46	87.54	20.79	60.60	74.07	98.12
Thereafter escalation rate of 2%

Year				Alberta Plant Gate				Saskatchewan Plant Gate			British Columbia
	Henry Hub NYMEX Near Month Contract	Midwest Price at Chicago	AECO/NIT Spot	Spot Constant [2011] $	ARP	Aggre- gator	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot Plant Gate	Sulphur FOB Vancouver	Alberta Sulphur at Plant Gate
	$US/ MMBtu	$US/ MMBtu	$/ MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$US/LT	$/LT
2011	4.50	4.60	4.16	3.92	3.89	3.78	3.37	3.79	4.13	4.25	3.96	3.80	140.00	99.86
2012	5.15	5.25	4.74	4.51	4.37	4.34	4.00	4.27	4.71	4.85	4.54	4.39	125.00	84.55
2013	5.75	5.85	5.31	5.06	4.91	4.88	4.59	4.81	5.28	5.40	5.11	4.95	125.00	84.55
2014	6.25	6.35	5.77	5.52	5.35	5.32	5.08	5.25	5.74	5.90	5.57	5.40	100.00	59.04
2015	6.75	6.85	6.22	5.97	5.80	5.76	5.57	5.70	6.19	6.40	6.02	5.86	100.00	59.04
Thereafter escalation rate of 2%

Notes:

(1)	Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate.
(2)	The plant gate price represents the price before raw gas gathering and processing charges are deducted.
(3)	AECO – C Spot refers to the one month price averaged for the year.

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The weighted average realized sales prices by the Company for the year ended December 31, 2010 was $3.07/Mcf for natural gas net of transportation and impact of the natural gas hedge, $71.86/bbl for light and medium crude oil and $55.67/bbl for NGLs.

Reconciliation of Corporation Gross Reserves by Product Type

The following table sets forth the changes the Company's reserve volume estimates made as at December 31, 2010 and the corresponding estimates as at December 31, 2009, using forecast prices and costs.

	Light and Medium Crude Oil			CBM			Natural Gas			NGLs			Total Oil Equivalent
	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mbbl)	(MBOE)	(MBOE)	(MBOE)
Dec. 31, 2009	868	939	1,807	5,106	4,270	9,376	24,222	12,438	36,660	281	147	428	6,037	3,870	9,907
Extensions and Improved Recovery	40	28	69	--	--	--	3,443	4,892	8,335	38	43	81	653	877	1,539
Technical Revisions	127	(155)	(27)	28	9	37	2,352	(2,290)	62	62	(5)	58	586	(540)	46
Discoveries	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Acquisitions	--	--	--	--	--	--	198	73	272	11	4	15	44	16	60
Dispositions	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Economic Factors	--	--	--	(346)	(149)	(495)	(906)	(508)	(1,413)	(14)	(6)	(20)	(223)	(115)	(338)
Production	(169)		(169)	(207)		(207)	(4,637)		(4,637)	(67)		(67)	(1,043)		(1,043)
Dec. 31, 2010	867	812	1,679	4,582	4,130	8,711	24,674	14,606	39,279	311	183	494	6,054	4,117	10,171

Proved Undeveloped Reserves

The following table sets forth the volumes of proved undeveloped reserves that were first attributed for each of the Company's product types for each of the most recent three financial years and, in the aggregate, before that time, using forecast prices and costs.

Financial Year End	Light and Medium Crude Oil	Natural Gas	NGLs
Financial Year End	(Mbbl)	(MMcf)	(Mbbl)
Prior to December 31, 2008	-	3,651	3
December 31, 2008	13	4,287	3
December 31, 2009	9	4,329	1
December 31, 2010	10	4,170	3

Proved undeveloped reserves are generally those reserves related to planned infill drilling locations. The Company's proved undeveloped reserves are forecasted to be developed during the next two years.

Probable Undeveloped Reserves

The following table sets forth the volumes of probable undeveloped reserves that were first attributed for each of the Company's product types for each of the most recent three financial years and, in the aggregate, before that time, using forecast prices and costs.

Financial Year End	Light and Medium Crude Oil	Natural Gas	NGLs
Financial Year End	(Mbbl)	(MMcf)	(Mbbl)
Prior to December 31, 2008	848	13,890	87
December 31, 2008	892	18,080	155
December 31, 2009	939	16,708	147
December 31, 2010	458	4,757	9

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Probable undeveloped reserves relate to wells to be drilled, tied in and brought on-stream in future. The Company's probable undeveloped reserves are forecasted to be developed during the following two to four years in accordance with the Company's development program and budget.

Significant Factors and 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, the subjective decisions, new geological or production information and a changing environment may impact 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 following table sets forth the development costs deducted in the estimation in the GLJ Report of future net revenue attributable to proved reserves and proved plus probable reserves, using forecast prices and costs.

	Total Proved	Total Proved Plus Probable
Year	(M$)	(M$)
2011	2,188	5,253
2012	1,079	2,011
2013	3,776	5,816
2014	3,995	8,160
2015	-	11
Remaining Years	190	206
Total for all years undiscounted	11,226	21,457

The Company expects to fund its future development from internally generated cash flow from operations, debt (where deemed appropriate) and new equity issues (if available on favourable terms). In addition, the Company may consider farm-out arrangements for certain projects. The Company does not expect that the cost of funding will make the development of a property uneconomic for the Company, nor is it expected that the cost of such funding will impact the Company's reserves or future net revenue.

- 28 -

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2010.

Location

Light and Medium Crude Oil

Natural Gas

	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net

British Columbia	-	-	-	--	2.0	1.1	5.0	1.2
Alberta	111.0	81.0	14.0	10.0	315.0	151.9	136.0	83.9
Saskatchewan	-	-	1.0	1.0	-	-	6.0	6.0
Trinidad and Tobago	-	-	-	-	-	-	3.0	0.8
Total	111.0	81.0	15.0	11.0	317.0	153.0	150.0	91.9

Properties With No Attributed Reserves

The following table summarizes the undeveloped gross and net acres of properties with no attributed reserves in which the Company has an interest and also the number of net acres for which the Company's rights to explore, develop or exploit will, absent further action, expire within one year.

Location	Gross Acres	Net Acres	Net Acres Expiring Within One Year
British Columbia	30,179	9,988	1,219
Alberta	194,587	158,181	46,443
Saskatchewan	30,881	30,881	9,865
Offshore Trinidad and Tobago	80,041	20,010	-
Offshore North Africa	768,000	768,000	-
Total	1,103,688	987,060	57,527

As at December 31, 2010, the estimated cost of the remaining work commitments on the 7th of November Block, Offshore Tunisia and Libya was approximately US$49.0 million to the Company. In Trinidad, BG currently holds US$20.0 million in escrow for the Company whereby the Company must maintain the lesser of US$20.0 million or 25% of the estimated capital expenditure requirements with respect of Block 5(c) through to the end of the second phase of the exploration period. Any draws made against the US$20.0 million are required to be replenished by the Company within 30 days of the draw date.

Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves

On December 21, 2010, the Company entered into the Niko Sale Agreement in respect of the purchase of its interests in Block 5(c) and the assumption of certain liabilities in respect of MG Block by Niko. The Offshore Trinidad and Tobago represents 100% of that undeveloped acreage.

On January 11, 2011, the Company announced the successful drilling and production testing with a 100% working interest of the Zarat North-1 well on the 7th of November Block. The Company safely evacuated it’s personnel and the rig and equipment without incident as the turmoil in Tunisia began. The well has been temporarily abandoned while the Company evaluates the recoverable reserve scenarios, development options and cost estimates for the field's development. During January, 2011, protests in Tunisia led to the overthrow of the government. Election of a new national constituent assembly is scheduled to take place on July 24, 2011 and while relative calm has been restored, uncertainty remains over the future direction of the country. Similarly, widespread protests over the government in Libya have occurred and a state of war exists between government and opposition forces. This has led to the cessation of oil production in the country, military intervention by Western forces and the imposition of Libyan Sanctions. While this turmoil has not had a direct impact on the Company’s 7th of November Block current activities it may significantly and adversely affect the Company including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, make payments to Joint Oil and the ability to attract joint venture partners or financing.

- 29 -

In the Drumheller area of Alberta, the Company is focusing its positions in six oil pools, the largest of which are the Mannville I pool (lower Cretaceous Ellerslie sandstone) and the Michichi Detrital pool (lower Cretaceous Detrital sandstone). The Company is planning a multi-year re-development of these oil pools using horizontal drilling and multi-stage fracturing technology, and has identified 86 future horizontal oil infill locations.

In addition, the Company owns over 150 locations in the form of both producing and suspended vertical wells that hold potential for re-development of existing zones and development of new, principally shallower non-producing zones. The Company has planned an aggressive work-over and re-development program targeting the Cretaceous Ellerslie, Glauconitic and Viking formations in these locations during 2011.

In the Kaybob/Windfall area of Alberta, the assets contain a series of vertically-stacked Cretaceous and Jurassic tight gas sand development opportunities, of principal importance being the Windfall Gething pool. The Company has had success in proving the economic viability and a geographic limit of this liquids-rich gas play with two vertical re-entries in 2010, and is preparing to develop the pool using horizontal wells and multi-stage fracturing. The Company has identified 14 horizontal development locations on its acreage base and plans proof-of-concept drilling at two of these locations in 2011. In addition, the Company holds a number of attractive re-entry candidates targeting Jurassic Nordegg and Cretaceous Viking tight gas sands, and plans a modest re-development program targeting these wells in 2011.

In addition to the conventional opportunities outlined above, the Company has amassed approximately 65,000 net acres of Duvernay rights in the Kaybob and Puskwaskau areas of north-central Alberta. The Company believes that the Duvernay contains a potentially robust oil resource play opportunity, and plans participation in two gross wells in 2011 to begin evaluation of the play. If the Niko Sale does not close, the Company intends to finance future Western Canada capital expenditures to the extent it can, with existing cash flow, and available debt capacity. In addition, we are limiting our North Africa activities in compliance with the political issues and Libyan sanctions.

Forward Contracts

The Company may periodically enter into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are to be entered into solely for hedging purposes and are not used for trading or other speculative purposes. The Company did not enter into any forward contracts as of December 31, 2010. For information with respect to the commodity hedging contract entered into on February 14, 2011, see "General Development of the Business - Recent Developments".

Additional Information Concerning Abandonment and Reclamation Costs

The Company typically estimates well abandonment costs area by area. Such costs are included in the GLJ Report as deductions in arriving at future net revenue.

The expected total abandonment and disconnect costs, net of salvage value, included in the GLJ Report for 245 net wells under the proved reserves category is $6.9 million undiscounted ($3.3 million discounted at 10%), of which a total of $1.1 million undiscounted is estimated to be incurred in 2011, 2012 and 2013. This estimate does not include expected reclamation for surface leases of $4.0 million undiscounted ($1.8 million discounted at 10%).

The Company 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.

Costs Incurred

The following table summarizes capital expenditures (net of incentives and net of certain proceeds and including capitalized general and administrative expenses) incurred by the Company for the year ended December 31, 2010:

Property Acquisition Costs		Exploration Costs	Development Costs
Proved Properties	Unproved Properties	Exploration Costs	Development Costs
(M$)	(M$)	(M$)	(M$)
Nil	785	Nil	14,796

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Tax Horizon

Based on production from existing reserves, the Company estimates that it will not be required to pay income taxes in 2011 or 2012 and with continued exploration activity, the tax horizon could be pushed further.

Exploration and Drilling Activity

There were no wells drilled during the year ended December 31, 2010.

Production Estimates

The following tables sets forth for each product type the total volume of production estimated by GLJ in the GLJ Report for the first year reflected in the estimates of gross proved reserves and gross probable reserves and gross proved plus probable reserves as disclosed above.

Reserve Category - CGU	Light and Medium Crude Oil	Natural Gas	NGLs	Total Oil Equivalent
Reserve Category - CGU	(Mbbl)	(MMcf)	(Mbbl)	(MBOE)
Proved
Northern Alberta	1,832	101	13	182
Southern Alberta	20,513	732	202	1,115
Central Alberta	5,930	35	92	419
British Columbia	1,064	-	5	4,353
Total	29,339	868	312	6,070
Probable
Northern Alberta	782	33	5	168
Southern Alberta	12,513	763	85	2,874
Central Alberta	5,566	16	91	1,035
British Columbia	271	-	2	47
Total	18,772	812	183	4,124
Total Proved Plus Probable
Northern Alberta	2,614	134	18	588
Southern Alberta	32,666	1,495	287	7,226
Central Alberta	11,496	51	183	2,150
British Columbia	1,335	-	7	230
Total	48,111	1,680	495	10,194

Production History

The following table sets forth, on a quarterly basis for the year ended December 31, 2010, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback.

	Three Months Ended
	March 31, 2010	June 30, 2010	September 30, 2010	December 31, 2010
Average Daily Production Volume
Light and Medium Oil (bbl/d)	457	462	496	440
NGL (bbl/d)	138	158	150	290
Natural Gas (Mcf/d)	13,104	13,631	12,417	14,140
Total (BOE/d)	2,779	2,892	2,716	3,087
Average Prices Received
Light and Medium Oil ($/bbl)	77.24	70.13	69.77	70.98
NGL ($/bbl)	42.50	72.83	53.90	53.46
Natural Gas ($/Mcf)	5.41	4.30	4.33	4.65
Total ($/BOE)	40.41	35.38	35.49	36.95
Royalties Paid
Light and Medium Oil ($/bbl)	10.59	8.62	12.45	9.87

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	Three Months Ended
	March 31, 2010	June 30, 2010	September 30, 2010	December 31, 2010
NGL ($/bbl)	29.97	27.22	12.33	9.74
Natural Gas ($/Mcf)	0.59	0.70	0.25	(0.14)
Total ($/BOE)	6.02	6.19	4.09	1.71
Production Costs
Light and Medium Oil and NGLs ($/bbl)	15.58	13.36	15.61	18.90
Natural Gas ($/Mcf)	1.93	1.71	2.14	2.66
Total ($/BOE)	11.50	10.23	12.37	15.42
Netback Received(1)
Light and Medium Oil and NGLs ($/bbl)	38.96	44.20	37.56	37.44
Natural Gas ($/Mcf)	2.89	1.89	1.94	2.13
Total ($/BOE)	22.89	18.96	19.03	19.80

Note:

(1)	Netback is calculated by subtracting royalties and operating costs from revenues.

Production Volume by Cash Generating Unit ("CGU")

The following table indicates the average daily production from each of the Company's important fields for the year ended December 31, 2010.

CGU	Light and Medium Crude Oil	Natural Gas	NGLs	Total Oil Equivalent	%
CGU	(bbl/d)	(Mcf/d)	(bbl/d)	(BOE/d)	%
Northern Alberta	32.6	570.4	14.0	141.6	5
Southern Alberta	379.1	10,389.9	126.6	2,237.4	78
Central Alberta	51.1	1460.2	37.0	331.5	12
British Columbia	0.6	903.1	7.0	158.1	5
Total	463.4	13,323.6	184.6	2,868.6	100

RISK FACTORS

An investment in Common Shares would be subject to certain risks. Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Company's other public filings. In order to mitigate these risks, the Company has qualified technical and financial personnel, with experience in the areas of Canada, the United States, Trinidad and Tobago and North Africa. Further, the Company has focused its foreign operations, and plans to target future operations, in known and prospective hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with oil and gas companies. Additional risks and uncertainties not currently known to the management of the Company may also have an adverse effect on the Company's business and the information set out below does not purport to be an exhaustive summary of the risks affecting the Company.

Niko Sale Agreement and Ability to Continue as a Going Concern

On December 21, 2010, the Company entered into the Niko Sale Agreement with respect to the purchase of its interests in Block 5(c) by Niko for an aggregate purchase price of US$87.5 million, to be satisfied at closing by the payment of US$75.5 million in cash and the assumption of the Company's US$12.0 million liability under the performance guarantee provided for in the MG Block. A US$ 20 million debenture was provided by the Company to support the deposit made by Niko in the event that the Niko Sale is not completed. BG waived it’s ROFR with respect to the Niko Sale. The Niko Sale Agreement is subject to the satisfaction of certain conditions including approval from the MEEI. After closing, the Company will cease all operations in Trinidad and Tobago and completely exit the country. As of the date hereof, the MEEI has not approved the transactions contemplated in the Niko Sale Agreement and no assurances can be given that such approval will be obtained in a timely matter or at all. Accordingly, if the Company fails to close the transactions contemplated in the Niko Sale Agreement and thereafter, fails to access adequate financing, the Company may not be able to continue as a going concern.

Additional financial information with respect to the foregoing is provided in the Company's financial statements and management discussion and analysis for the year ended December 31, 2010, copies of which are available on SEDAR at www.sedar.com.

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Mariner Swap Agreement

On August 27, 2008, the Company also entered into the Swap Agreement with Joint Oil pursuant to which Joint Oil was granted a 3% overriding royalty interest and an optional participating interest in the Mariner Block, offshore Nova Scotia. If at the end of August 2011, no well is drilled on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million.

North Africa

Both the governments of Tunisia and Libya are in political turmoil. During January, 2011, protests in Tunisia led to the overthrow of the government. Election of a new national constituent assembly is scheduled to take place on July 24, 2011 and while relative calm has been restored, uncertainty remains over the future direction of the country. Similarly, widespread protests over the government in Libya have occurred and a state of war exists between government and opposition forces. This has led to the cessation of oil production in the country, military intervention by Western forces and the imposition of Libyan Sanctions. While this turmoil has not had a direct impact on the Company’s 7th of November Block current activities it may significantly and adversely affect the Company including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, make payments to Joint Oil and the ability to attract joint venture partners or financing.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If the Company's revenues or reserves decline, it may limit the Company's ability to expend or access 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. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's financial condition, results of operations or prospects.

Capital Markets

The market events and conditions witnessed over the past two financial years, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility in commodity prices and increases in the rates at which the Company is able to borrow funds for its capital programs. While there have been recent signs which may suggest the beginning of a global economic recovery, there can be no certainty regarding the timing or extent of a potential recovery, and such continued uncertainty in the global economic situation means that the Company, along with all other oil and gas entities, may continue to face restricted access to capital and increased borrowing costs. This could have an adverse effect on the Company, as its ability to make future capital expenditures is dependent on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry generally and the Company's securities in particular.

Additional Funding Requirements

The Company's cash flow from its producing reserves may not be sufficient to fund its ongoing activities at all times. From time to time, the Company may require additional financing in order to carry out its acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company's ability to expend the necessary capital to replace its reserves or to maintain its production. If the Company's cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on favourable terms.

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Issuance of Debt

From time to time the Company may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Company's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Company may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the articles of the Company nor its by-laws limit the amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time, could impair its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively affect the Company's debt ratings. This in turn, could have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time, and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that the Company will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, management of the Company may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by the Company.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, availability of drilling rigs, support equipment, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, the Company may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Company. In accordance with industry practice, the Company is not fully insured against all of these risks, nor are all such risks insurable. Although the Company maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on the Company.

Operational Dependence

Other companies operate some of the assets in which the Company has an interest (in particular, the Company's interests in Trinidad and Tobago). As a result, the Company will have limited ability to exercise influence over the

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operation of those assets or their associated costs, which could adversely affect the Company's financial performance. The Company's return on assets operated by others will therefore depend upon a number of factors that may be outside of the Company's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

Project Risks

The Company will manage a variety of small and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Significant project cost over-runs could make a project uneconomic. The Company's ability to execute projects and market oil and natural gas will depend upon numerous factors beyond the Company's control, including:

·	the availability of drilling and related equipment;
·	the availability of processing capacity;
·	the availability and proximity of pipeline capacity;
·	the availability of storage capacity;
·	the supply of and demand for oil and natural gas;
·	the availability of alternative fuel sources;
·	the effects of inclement weather;
·	unexpected cost increases;
·	accidental events;
·	currency fluctuations;
·	changes in regulations;
·	the availability and productivity of skilled labour; and
·	the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, the Company could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that it produces.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) 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 Company and may delay exploration and development activities. To the extent the Company is not the operator of its oil and gas properties, the Company 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.

Prices, Markets and Marketing of Crude Oil and Natural Gas

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is and will continue to be affected by numerous factors beyond its control. The Company's ability to market its oil and natural gas may depend upon its ability to contract capacity on pipelines that deliver natural gas to commercial markets. The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive

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government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

The Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company's ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions, in the United States, Canada Trinidad and Tobago and North Africa, the actions of the OPEC and Russia, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Company's carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations.

Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

In addition, bank borrowings available to the Company in part determined by the Company's borrowing base. A sustained material decline in prices from historical average prices could reduce the Company's borrowing base, therefore reducing the bank credit available to the Company which could require that a portion, or all, of the Company's bank debt be repaid.

Insurance

The Company's involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although prior to conducting drilling and other field activities, the Company will obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company's financial position, results of operations or prospects.

Legal Proceedings

The Company may from time to time be subject to litigation and regulatory proceedings arising in the normal course of its business. The Company cannot determine whether such litigation and regulatory proceedings will, individually or collectively, have a material adverse effect on its business, results or operations and financial condition. To the extent expenses incurred in connection with litigation or any potential regulatory proceeding or action (which may include substantial fees of attorneys and other professional advisors and potential obligations to indemnify officers and directors who may be parties to such actions) are not covered by available insurance, such expenses could adversely affect the Company's cash position.

Environmental Risks

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and international, national, provincial, state and local law and regulation. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of same can result in the imposition of clean-up orders, fines and/or penalties, some of which may be material, as well as possible forfeiture of requisite approval obtained from the various

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governmental authorities. The discharge of GHG emissions and other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it is in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect its financial condition, results of operations or prospects. See "Industry Conditions".

Canadian Tax Considerations

As the Company is engaged in the oil and natural gas business its operations are subject to certain unique provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation relating to characterization of costs incurred in their businesses which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. The Company has reviewed its historical income tax returns with respect to the characterization of the costs incurred in the oil and natural gas business as well as other matters generally applicable to all corporations including the ability to offset future income against prior year losses. The Company has filed or will file all required income tax returns and believes that it is full compliance with the provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation, but such returns are subject to reassessment. In the event of a successful reassessment of the Company it may be subject to a higher than expected past or future income tax liability as well as potentially interest and penalties and such amount could be material.

Foreign Operations

International operations in Trinidad and Tobago and North Africa are subject to political, economic and other uncertainties, including, among others, risk of war, risk of terrorist activities, border disputes, expropriation, renegotiations or modification of existing contracts, restrictions on repatriation of funds, import, export and transportation regulations and tariffs, taxation policies including royalty and tax increases and retroactive tax claims, exchange controls, limits on allowable levels of production, currency fluctuations, labour disputes, sudden changes in laws, government control over domestic oil and gas pricing, and other uncertainties arising out of foreign government sovereignty over the Company's international operations. See Risk Factors – North Africa. In addition, because Libya is a member of OPEC, any production obtained by the Company from Libya may be constrained by OPEC quotas.

Furthermore international oil and gas operations in Trinidad and Tobago and North Africa involve substantial costs and are subject to certain risks owing to the underdeveloped nature of the oil and gas industry in such countries. The oil and gas industry in various countries is not as developed as the oil and gas industry in Canada. As a result, drilling and development operations may take longer to complete and may cost more than similar operations in Canada. The availability of technical expertise, specific equipment and supplies is more limited in various countries than in Canada and the United States. Such factors may subject oil and gas operations in other countries to economic and operating risks not experienced in Canada.

Foreign Legal Systems

Trinidad and Tobago, Tunisia and Libya have less developed legal systems than in Canada which may result in risks such: as (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or, in an ownership dispute, being difficult to obtain; (ii) a higher degree of discretion on the part of

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governmental authorities; (iii) the lack of judicial or administrative guidance on interpreting applicable rules and regulations; (iv) inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; or (v) relative inexperience of the judiciary and courts in such matters; in certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licenses, license applications or other legal arrangements will not be adversely affected by the actions of government authorities and the effectiveness of and enforcement of such arrangements in these jurisdictions cannot be assured.

Foreign Currency Rates

A significant amount of the Company's activities are transacted in or referenced to the currencies of the United States, Trinidad and Tobago, Tunisia and Libya. The Company's revenues, operating costs and certain of its payments in order to maintain property interests are to be in the local currency of the jurisdiction where the applicable property is located. As a result, fluctuations in the currencies of the United States, Trinidad and Tobago, Tunisia and Libya against the Canadian dollar, and each of those currencies against currencies in jurisdictions where properties of the Company are located, could result in unanticipated fluctuations in the Company's financial results which are denominated in Canadian dollars. The Company does not currently manage its exposure to fluctuations in currency exchange rates.

Competition

The Company actively competes for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than the Company. The Company's competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. Competition may also be presented by alternate energy sources.

The oil and gas industry is highly competitive. The Company's competitors for the acquisition, exploration, production and development of oil and natural gas properties, and for capital to finance such activities, include companies that have greater financial and personnel resources available to them than the Company.

Certain of the Company's customers and potential customers are themselves exploring for oil and gas, and the results of such exploration efforts could affect the Company's ability to sell or supply oil or gas to these customers in the future. The Company's ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Reserve Replacement

The Company's future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Existing reserves and production will decline over time without the continual additional of new reserves. A future increase in the Company's reserves will depend not only on the Company'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 Company's future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.

Reliance on Industry Partners

In order to carry out certain of its business and operations, the Company relies on its industry partners (certain of which include suppliers, contractors and joint venture parties and operators). Accordingly, the Company is exposed to third party risk. Should such industry partners fail to fulfil those duties and obligations each owes to the Company, such failure could have a material adverse effect on the Company's business and/or operations.

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Reliance on Key Employees

The Company's success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the Company. The Company does not have key person insurance in effect for management. The contributions of these individuals to the Company's immediate operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the Company's management.

Permits, Licences and Approvals

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on its results of operations and business.

Royalties, Incentives and Production Taxes

In addition to federal regulations, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown Lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time, the Governments of Canada, Alberta and British Columbia have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects.

Land Tenure

Crude oil and natural gas located in the Canadian western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms 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.

Title to Properties

Although title reviews may be conducted prior to the purchase of producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the Company's claim which could result in a reduction of the revenue received by the Company.

Reserve Information

The reserve and recovery information contained in the GLJ Report are only estimates and the actual production and ultimate reserves from the Company's properties may be greater or less than the estimates prepared in such report. The GLJ Report has been prepared using certain commodity price assumptions which are described in the notes to the reserve tables. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Company and substituted for the price assumptions utilized in the report, the present value of estimated future net cash flows for the Company's reserves would be reduced and the reduction could be significant, particularly based on the constant price case assumptions. Exploration for oil and natural gas involves many risks, which even a combination of

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experience and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil and natural gas will be discovered by the Company.

Dilutive Effect of Financings and Acquisitions

The Company may make future acquisitions or enter into financing or other transactions involving the issuance of securities of the Company which may be dilutive.

Dividends

The Company has not paid any dividends on its outstanding Common Shares. Payment of dividends on the Common Shares in the future will be dependent on, among other things, the cash flow, results of operations and financial condition of the Company, the need for funds to finance ongoing operations and other business considerations as the Board considers relevant.

Third Party Credit Risk

The Company 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 Company, such failures could have a material adverse effect on the Company and its cash flow from operations. 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 Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company makes acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of an acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Company, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Company.

Hedging

In 2010 and 2011, the Company entered into agreements to receive fixed prices on a portion of the Company’s 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 Company will not benefit from such increases and the Company may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements. Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Company will not benefit from the fluctuating exchange rate.

Aboriginal Claims

The Canadian First Nations have made rights and title claims to a significant portion of Western Canada. At present the Company is unable to assess what, if any, impact such claims will have on the business and operations that it conducts in Western Canada.

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Conflict of Interest

Certain of the directors and officers of the Company 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 Company and as officers and directors of such other companies. Such conflicts must be disclosed in accordance with, and are subject to such other procedures and remedies as apply under the ABCA.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, environmental, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to export and taxation of oil and natural gas by agreements among the Governments of Canada, British Columbia, Alberta, Saskatchewan and Nova Scotia, among others, (including the governments of the United States, Trinidad and Tobago, Tunisia and Libya), 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 Company's operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Company is currently unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of environmental legislation and regulations relevant to the oil and gas industry in the jurisdictions in which The Company has developed producing reserves.

Federal

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol which was established thereunder to set legally binding targets to reduce nationwide GHG emissions. The Canadian federal government has indicated an intention to regulate the emissions of GHGs from a range of industries in the Framework. The Framework was updated on March 10, 2008 pursuant to the Update. The Federal Plan outlines a number of policies to reduce GHGs intensity of regulated facilities. New facilities (which are defined as those facilities whose first year of operation is 2004 or later) would face intensity reduction requirements beginning in their fourth year of commercial production, of 2% per year from their "baseline" emissions intensity (which baseline is the emissions intensity for such facility's third year of commercial production) until at least 2020. Compliance options for new facilities under the Federal Plan include making emissions intensity improvements; making investments in certified carbon capture and storage projects; buying offsets or emissions performance credits; and for a portion of each entity's emissions reduction obligations, making payments of $15 per tonne until 2012, $20 per tonne in 2013 and an escalating annual rate per tonne thereafter, to the federal technology fund.

The Federal Plan also includes proposed requirements to be implemented by the Canadian federal government which would govern the emission of industrial air pollutants. Certain of the proposed requirements include fixed emissions caps, an emissions credit trading system, and several options from which companies can choose to meet their GHG emission reduction targets. At present, the status of its proposals is unclear. The Canadian federal government has repeatedly stated that it intends to align their GHG emission reduction policies with those of the United States, and it is willing to wait until the United States has developed its framework before implementing any policies here in Canada. As such, and given the current political climate in Washington, it is unclear when, or in what form, the Federal Plan will be implemented.

Several of the provinces and territories are working together with various American states to develop a cap and trade system. It remains to be seen whether the Canadian federal government would adopt such an approach, but given its statements regarding aligning policy with the United States, this will likely depend on whether the United States adopts a cap and trade system. No assurance can be given that either a modified Federal Plan or a North American cap and trade system will or will not be implemented, or what kinds of obligations may be imposed under such a system.

In February 2009, the United States and Canada established the 'Clean Energy Dialogue' in order for the two countries to collaborate on the development of clean energy science and technologies to reduce GHG emissions and combat climate change. A number of working groups have been created to develop recommendations for joint initiatives.

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At the July 2009 G8 Summit in Italy, Canada and the other G8 members agreed to work together toward achieving at least a 50% reduction of global GHG emissions by 2050. Canada reiterated its commitment to this goal at the June 2010 G8 Summit in Huntsville Ontario.

In December 2009, Canada participated in the COP 15 in Denmark, the goal of which was to reach a new agreement for fighting global climate change. COP 15 resulted in the non-binding Copenhagen Accord, whereby Canada and the other participating countries committed to implementing quantified economy-wide emissions targets by 2020. Canada submitted its GHG emission reduction targets on January 30, 2010, noting that: (a) its target is a 17% reduction from a baseline of 2005 emission levels (which target is aligned with the final economy-wide emissions target and base year of the United States); and (b) its submission is dependant on the other parties to the Copenhagen Accord submitting emissions targets and mitigation actions in accordance with such Accord. In late November and early December 2010, Canada also participated in the COP 16 in Mexico. COP 16 resulted in little progress towards a new binding agreement to replace the Kyoto Protocol post-2012, but did lay the groundwork for several mechanisms which will aid in that regard going forward.

There has been much public debate surrounding Canada's ability to meet emission reduction targets and the strategies proposed for controlling climate change and GHG emissions. Whether such strategies meet the requirements set forth in the Kyoto Protocol, announcements made at the 2009 G8 Summit or targets set in response to the Copenhagen Accord, it is likely that any such strategy will materially impact the nature of oil and gas operations, including those carried out by Cequence. At present, it is not possible to predict the impact such strategies will have on the business, operations and/or finances of Cequence.

Alberta

Environmental legislation in the Province of Alberta has largely been consolidated into the Environmental Protection and Enhancement Act (Alberta), the Water Act (Alberta), and the Oil and Gas Conservation Act (Alberta). These statutes impose environmental standards, require compliance, reporting and monitoring obligations, and impose penalties. In addition, the emission reduction requirements set out in the Climate Change and Emissions Management Act (Alberta) came into effect on July 1, 2007. Under this statute and the regulations enacted thereunder, Alberta facilities emitting more than 50,000 tonnes of GHG emissions per year must report such emissions to Alberta Environment and Environment Canada while facilities emitting more than 100,000 tonnes of GHG emissions per year must reduce their emissions intensity by 12% from baseline levels. Companies have four options to choose from in order to meet the reduction requirements: making improvements to operations that result in actual reductions; purchasing emission credits from other sectors or facilities that have reduced their emissions below the required emission intensity reduction levels; purchasing off-set credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions in Alberta; or contributing to the 'Climate Change and Emissions Management Fund' at the current rate of $15 for every tonne of emissions over its reduction target. A company can choose one of these options or a combination thereof, however it should be noted that the price of off-set credits could be raised, and the required reductions in GHG emissions intensity presently set forth can be increased to unspecified levels.

In January of 2008 Alberta introduced its Climate Change Strategy which includes three broad themes: (i) conserving and using energy efficiently; (ii) implementing carbon capture and storage; and (iii) greening energy production. Under the Climate Change Strategy, Alberta has indicated its intention to meet the following emission reduction targets: a 20 megatonne reduction by 2010, a 50 megatonne reduction by 2020 and a 200 megatonne reduction by 2050, all while maintaining economic growth. In furtherance of this Climate Change Strategy, the Government of Alberta has begun enacting legislation including the 2009 Carbon Capture and Storage Funding Act and the 2010 Carbon Capture and Storage Statutes Amendment Act.

British Columbia

British Columbia's Environmental Assessment Act creates an environmental assessment process for reviewing the potential environmental impact of major energy projects within the province.

On February 27, 2007, the Government of British Columbia unveiled the BC Energy Plan, which outlines the province's energy strategy. The BC Energy Plan sets targets for reducing GHG emissions, promoting investments in innovation, and sustainable environmental management. The BC Energy Plan's objectives are to achieve clean

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energy through conservation and energy efficient practices, and to increase competitiveness in order to attract new investment in the oil and natural gas industry. The changes proposed include: (i) the creation of policies and measures for the reduction of emissions; (ii) the elimination of routine flaring at producing wells by 2016 with an interim target of a 50% reduction in flaring by 2011; (iii) the establishment of the Innovative Clean Energy Fund, in order to find new technologies that will help solve energy and environmental issues; (iv) a new Oil and Gas Technology Transfer Incentive Program, which encourages the research, development and use of innovative technologies to responsibly develop new oil and gas reserves and increase recoveries from existing reserves; and (v) the development of unconventional resources such as tight gas and coalbed gas.

In furtherance of these initiatives, the Government of British Columbia introduced the Carbon Tax Act on July 1, 2008. The carbon tax applies to fossil fuels such as gasoline, diesel, natural gas, propane and coal used in the Province of British Columbia, and it is revenue-neutral, meaning tax revenues generated by the carbon will be returned to taxpayers through reductions in other provincial taxes. The carbon tax is currently being phased in. The carbon tax rates on July 1, 2010 are equal to $20 per tonne of CO2 equivalent emissions, increasing by $5 per tonne each year for the next two years to $30 per tonne in 2012.

On May 29, 2008, the Government of British Columbia enacted the Greenhouse Gas Reduction (Cap and Trade) Act, which allows for participation in the Western Climate Initiative cap and trade system currently being developed by a group of Canadian Provinces and US States. The proposed system establishes a limit on GHG emissions, and allows regulated emitters to buy/sell GHG emission allowances or offset credits. The emitter is obliged to obtain GHG emission allowances (compliance units) which are equal to the amount of GHG emissions released within a certain period of time, which are then to be surrendered to the Government of British Columbia as proof of compliance.

In support of an eventual cap and trade system, British Columbia has also enacted certain regulations under the Greenhouse Gas Reduction (Cap and Trade) Act, including the Reporting Regulation which was approved by the Governor in Council on November 25, 2009. The Reporting Regulation sets out the requirements for the reporting of greenhouse gas emissions from facilities in British Columbia emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year beginning on January 1, 2010. Those reporting operations with emissions of 25,000 tonnes or greater are required to have emissions reports verified by a third party. Additional regulations that will further enable British Columbia to implement a cap and trade system are currently under further development.

DIVIDENDS

The Company has not declared or paid any dividends on the Common Shares since incorporation. It is not currently expected that dividends will be paid in respect of the Common Shares during the current phase of development of the Company's business and operations. The payment of dividends in the future will be at the discretion of the Board and will be dependent on the future earnings and financial condition of the Company and such other factors as the Board considers appropriate.

Dividends of US$5.8 million, US$5.4 million and US$ Nil per Series A Preferred Share were paid by the Company in each of the years ended December 31, 2008, 2009 and 2010, respectively, to various preferred shareholders.

The Company has not declared or paid any dividends on the Series B Preferred Shares.

DESCRIPTION OF SHARE CAPITAL

The Company's authorized share capital consists of an unlimited number of Common Shares and an unlimited number of Preferred Shares, issuable in series. As of the date hereof, 62.3 million Common Shares and 150,000 Series B Preferred Shares were issued and outstanding and no Series A Preferred Shares were issued and outstanding. For more information with respect to the conversion of the Series A Preferred Shares, see "General Development of the Business - Recent Developments" and the Material Change Report of the Company dated February 4, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein.

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Common Shares

The holders of Common Shares are entitled to notice of and to vote at all meetings of Shareholders (except meetings at which only holders of a specified class or series of shares are entitled to vote) and are entitled to one vote per Common Share. The holders of Common Shares are entitled to receive such dividends as the Board may declare and, upon liquidation, to receive such assets of the Company as are distributable to holders of Common Shares.

Preferred Shares

The Preferred Shares may be issued in one or more series with each series to consist of such number of shares as may, before the issue of the series, be fixed by the Board. The Board is authorized, before the issue of the series, to determine the designation, rights, restrictions, conditions and limitations attaching to the Preferred Shares of each series. The Preferred Shares of each series rank equally with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up and in priority to the Common Shares and any other shares of the Company ranking junior to the Preferred Shares. In addition, if any amount of a fixed cumulative dividend or an amount payable on return of capital in respect of shares of a series of Preferred Shares is not paid in full, the shares of the series are entitled to participate rateably with the shares of any other series of the same class in respect of such amounts.

Series A Preferred Shares

The Series A Preferred Shares carry a cumulative dividend of 5% per annum if, as and when declared by the Board, payable quarterly, equal to $100 multiplied by the applicable quarterly dividend rate, which is 1.25% until December 30, 2010 and shall, for the 150 day period after December 30, 2010, increase by 1/30 of 1% per day, resulting in a maximum applicable annual dividend rate of 6.25%. The Company may elect to satisfy its dividend payment obligation entirely or in part by delivering such number of Common Shares equal to 115% of the applicable dividend rate multiplied by $1000 divided by the current market price of the Common Shares. Each Series A Preferred Share is convertible into 40 Common Shares at a price of US$2.50 per Common Share. The Series A Preferred Shares are redeemable and retractable five years from the date of issue, subject to earlier redemption or retraction in certain events. On February 3, 2010, the Company converted all the Series A Preferred Shares into B Preferred Shares.

Series B Preferred Shares

The Series B Preferred Shares carry a cumulative dividend of 5% per annum if, as and when declared by the Board, payable quarterly, equal to $100 multiplied by the applicable quarterly dividend rate, which is 1.25% until December 30, 2010 and shall, for the 150 day period after December 30, 2010, increase by 1/30 of 1% per day, resulting in a maximum applicable annual dividend rate of 6.25% and thereafter reverts to 5%. The Company may elect to satisfy its dividend payment obligation entirely or in part by delivering such number of Common Shares equal to 115% of the applicable quarterly dividend rate multiplied by $100 divided by the current market price of the Common Shares. Each Series B Preferred Share is convertible into 33.33 Common Shares at a price of US$3.00 per Common Share. The Series B Preferred Shares are redeemable by the Company on or after December 31, 2011 and retractable by holders on December 31, 2011. Subject to earlier redemption or retraction in certain events. The Company can force the conversion of the Series B Preferred Shares at any time if the Common Shares close at a price of at least a 100% premium to the conversion price on a major United States exchange for 20 out of any 30 consecutive trading days.

Rights Plan

The Company adopted the Rights Plan in accordance with the Rights Plan Agreement. Pursuant to the terms of the Rights Plan Agreement, the Rights Plan will expire on the date that the annual meeting of Shareholders to be held in 2013 terminates unless re-approved by the Shareholders. For more information with respect to the Rights Plan, see the Information Circular of the Company dated August 12, 2009 and the Rights Plan Agreement, copies of which are available on SEDAR at www.sedar.com and are incorporated by reference herein.

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MARKET FOR SECURITIES

The Common Shares are listed and posted for trading on the TSX and the NYSE Amex under the symbol "SOQ". The following table sets forth the price ranges and volume of Common Shares traded as reported by the TSX for the periods indicated.

2010(1)	High ($)	Low ($)	Close ($)	Volume
January	0.65	0.59	0.60	2,688,185
February	0.63	0.51	0.52	2,814,430
March	0.62	0.50	0.62	5,682,896
April	0.69	0.57	0 .6	2,960,001
May	0.72	0.53	0.67	13,415,166
June 1 to 7	0.77	0.65	0.70	2,799,212
June 9 to 30	3.64	3.02	3.29	1,912,263
July	3.25	2.68	3.02	1,449,479
August	3.40	2.88	2.97	1,732,165
September	3.35	2.86	3.11	4,553,911
October	3.27	2.82	3.25	2,447,463
November	3.37	2.93	3.13	1,024,317
December	3.65	2.96	3.64	1,013,245

Date of Grant	Number of Options	Exercise Price
November 9, 2009 (a)	83,200	$3.20
February 2, 2010	13,000	$3.10
May 3, 2010	83,200	$3.13
June 18, 2010	2,450	$3.30
October 19, 2010	800,000	$3.06

Name and Residence	Office or Position	Director Since	Principal Occupation During the Last Five Years
Marvin M. Chronister(1)(2)(4) Texas, United States	Chairman of the Board	September 2009	From June 2006 to present, an energy finance and operational consultant. Prior thereto, from August 2004 to June 2006, Financial Operations Practice Director of Jefferson Wells International, Inc., a financial consulting firm.
Jack W. Schanck Alberta, Canada	President and Chief Executive Officer and Director	December 15, 2010	From December 2010 to present, Chief Executive Officer and President of Sonde. Prior thereto, from 2007 to 2009, Managing Partner of Tecton Energy, LLC, a private oil and gas company. Prior thereto, from 2005 to 2007, Chief Executive Officer of SouthView Energy LP, a predecessor entity of Tecton Energy, LLC.
Dr. James Funk(3)(4) Pennsylvania, United States	Director	September 2009	From January 2004 to present, President and Geologist of J.M Funk & Associates, Inc., a private oil and gas consulting company.
Kerry Brittain(1)(2)(3) Texas, United States	Director	September 2009	From July 2007 to present, in private law practice advising companies on acquisitions and domestic and international transactions. Prior thereto, from July 2002 to July 2007, Senior Vice President, General Counsel and Secretary for Harvest Natural Resources, a public oil and gas company.
Dr. William J.F. Roach(4) Calgary, Alberta	Director	September 2009	From October 2010 to present, Chief Executive Officer of Calera Corporation, a carbon capture company. Prior thereto, from October 2004 to October 2010, President and Chief Executive Officer of UTS Energy Inc., a public oil and gas company.
Gregory G. Turnbull(1)(3) Alberta, Canada	Director	September 2009	From July 2002 to present, a partner with the law firm of McCarthy Tétrault llp.
James H.T. Riddell(2)(4) Alberta, Canada	Director	January 2010	From June 2002 to present, President and Chief Operating Officer of Paramount Resources Ltd., a public oil and gas company and from February 2010 to present, President and Chief Executive Officer of Trilogy Energy Corp., a public oil and gas company. Prior thereto, from February 2005 to February 2010, President and Chief Executive Officer of Trilogy Energy Ltd., a public oil and gas company.
William Dirks Alberta, Canada	Chief Operating Officer	N/A	From October 2010 to present, Chief Operating Officer of the Company. Prior to that, from 2005-2010, Managing Partner of Tecton Energy, LLC, a privately-owned E&P company he co-founded; from 2001-2005 President of Samson Canada Ltd. and Vice President of Business Development for Samson Resources, both privately-held E&P companies. Prior experience, from 1981-1999, was a series of assignments for the Royal Dutch / Shell Group of companies.
Kurt A. Nelson Texas, United States	Interim Chief Financial Officer	N/A	From June 2008 to present, in private upstream petroleum finance practice. Prior thereto, from November 2001 to May 2008, Vice President and Chief Accounting Officer for Harvest Natural Resources, Inc. a public oil and gas company.

(3)	Member of the Corporate Governance Committee.
(4)	Member of the Health, Safety, Environment and Reserves Committee.

Fee	For the year ended December 31, 2010	For the year ended December 31, 2009
Audit Fees	$281,295	$296,462
Audit-Related Fees(1)	$102,394	$117,170
Tax Fees(2)	$88,963	$2,756
Other Fees(3)	$58,366	$37,254
Total	$531,018	$453,542

(1)	Member of the Audit Committee.
(2)	Member of the Compensation Committee.

·	as disclosed herein with respect to the CCAA Proceeding;
·	Mr. Turnbull was a director of Mobilift Inc., a corporation engaged in the development, system integration and commercialization of innovative fall prevention technology. Mobilift Inc. was placed into receivership in September 2001 by its major creditor after Mr. Turnbull left the board of directors of Mobilift Inc. in August 2001;
·	Mr. Turnbull was a director of Action Energy Inc., a corporation engaged in the exploration, development and production of oil and gas in Western Canada. Action Energy Inc. was placed in receivership on October 28, 2009 by its major creditor and Mr. Turnbull resigned as a director immediately thereafter.
·	Mr. Chronister was a director of Saratoga Resources, Inc., a corporation engaged in the production, development and acquisition of natural gas and crude oil properties. Saratoga Resources, Inc. filed a voluntary petition for reorganization under Chapter 11 of the US Bankruptcy Code in March 2009. Mr. Chronister left the board of directors of Saratoga Resources, Inc. in April, 2009; and
·	Mr. Riddell was a director of Jurassic Oil and Gas Ltd., a private oil and gas company, within one year of such company becoming bankrupt. Jurassic Oil and Gas Ltd.'s bankruptcy was subsequently annulled.

(1)	"Audit-Related Fees" Include the aggregate fees paid to the external auditors for services related to the audit services, including reviewing quarterly financial statements and management's discussion thereon and consulting with the Board and Audit Committee regarding financial reporting and accounting standards.
(2)	"Tax Fees" Include the aggregate fees paid to external auditors for tax compliance, tax advice, tax planning and advisory services, including namely preparation of tax returns.
(3)	"All Other Fees" Include the aggregate fees paid to the external auditors for assurance procedures in connection with filings statements and information circulars and services related to offerings.

·	Arrangement Agreement - see "Bankruptcy and Similar Procedures - CCAA Proceedings";
·	Rights Plan Agreement - see "Description of Share Capital - Rights Plan"; and
·	BG Sale Agreement - see "Bankruptcy and Similar Procedures - Discussion of the Parties".

1.	We have evaluated the Company's reserves data as at December 31, 2010. The reserves data are estimates of proved and probable reserves and related future net revenue as at December 31, 2010, estimated using forecast prices and costs.
2.	The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.
4.	The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us for the year ended December 31, 2010, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and Board of Directors.

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Net Present Value of Future Net Revenue (10% discount rate)
Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Audited (M$)	Evaluated (M$)	Reviewed (M$)	Total (M$)
GLJ Petroleum Consultants	March 9, 2011	Canada	Nil	124,148	Nil	124,148

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied.
6.	We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their preparation dates.
7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

GLJ Petroleum Consultants Ltd., Alberta, Canada, March 21, 2011
(signed) "John H. Stilling"
John H. Stilling, P. Eng. Vice President

(signed) "Jack W. Schanck"		(signed) "William Dirks"
Jack W. Schanck		William Dirks
Chief Executive Officer		Chief Operating Officer
(signed) "Marvin M. Chronister"		(signed) "James M. Funk"
Marvin M. Chronister		James M. Funk
Director		Director

1.	Audit Committee
	The Board of Directors (the “Board”) of Sonde Resources Corp. (the “Corporation”) has established an audit committee (the “Audit Committee” or the “Committee”) of directors for the purpose of overseeing the accounting and financial reporting processes of the Corporation and audits of its financial statements.
2.	Composition of Committee
	(a)	The Audit Committee will consist of at least three directors. All members of the Committee must be independent as defined in applicable securities laws (subject to permitted exemptions under those laws) and the rules of any stock exchange on which the Corporation’s securities are listed for trading.
	(b)	Each member of the Audit Committee must be financially literate, or become financially literate within a reasonable period of time following his or her appointment to the Committee (provided that the Board has determined that this will not materially adversely affect the ability of the Committee to satisfy its responsibilities). A member is financially literate under applicable securities laws if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Corporation’s financial statements.
	(c)	At least one-quarter of the members of the Audit Committee must be resident Canadians.
3.	Appointment of Committee Members
	Members of the Audit Committee will be appointed by the Board and re-appointed at the meeting of the Board immediately following each annual meeting of shareholders. Committee members will hold office until the next annual meeting or earlier if their successors are appointed, they are removed by the Board or they cease to be directors of the Corporation.
4.	Compensation of Committee Members
	The Board will fix the remuneration of the members of the Audit Committee and may provide additional remuneration to the Chair of the Committee. Other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or

	vice-chair of the Board or any Board committee, or as otherwise permitted by applicable securities laws, no consulting, advisory or other compensatory fee will be paid to a member of the Audit Committee by the Corporation or any subsidiary of the Corporation.
5.	Vacancies
	When a vacancy occurs in the membership of the Audit Committee, it may be filled by the Board and must be filled by the Board if the membership of the Committee as a result of the vacancy is less than three directors. Any member may be removed or replaced at any time by the Board. Any member will cease to be a member upon ceasing to be a director.
COMMITTEE PROCEDURES
6.	Committee Chair
	The Board will appoint a Chair for the Audit Committee.
7.	Absence of Committee Chair
	If the Chair is not present at any meeting of the Audit Committee, one of the other members of the Committee present at the meeting will be chosen by the Committee to preside at the meeting.
8.	Secretary of Committee
	The Secretary of the Company shall be the secretary to the Committee unless the Committee designates otherwise.
9.	Meetings
	The Audit Committee will meet at least four times per year. All Committee members are expected to attend each meeting, in person or by telephone - or video-conference. The Committee shall only act on the affirmative vote of a majority of members. A resolution in writing, signed by all the Audit Committee members entitled to vote on that resolution at a meeting of the Committee, is as valid as if it had been passed at a meeting of the Committee.
10.	Notice of Meetings
	(a)	A meeting of the Audit Committee may be called by any member of the Committee, by the Chairman of the Board, the chief executive officer or the chief financial officer of the Corporation (or persons holding equivalent offices) or by the external auditor. Notice of the time and place of a meeting will be given in writing or by electronic communication to each member of the Committee and to the external auditor prior to the time fixed for the meeting.
	(b)	A member of the Audit Committee may in any manner waive notice of a Committee meeting. Attendance of a member at a Committee meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

11.	Quorum and Participation
	(a)	A majority of the number of members of the Audit Committee appointed by the Board constitutes a quorum at any meeting of the Committee.
	(b)	A member of the Audit Committee may, if all the members of the Committee consent, participate in a meeting of the Committee by means of a telephonic, electronic or other communication facility that permits all participants to communicate adequately with each other during the meeting. A member participating in a Committee meeting by those means is deemed to be present at that meeting.
12.	Attendance by External Auditor and Others
	(a)	The external auditor is entitled, at the expense of the Corporation, to attend and be heard at every meeting of the Audit Committee, and, if so requested by a member of the Committee, shall attend every meeting of the Committee held during the term of office of the external auditor.
	(b)	At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Corporation or directors who are not members of the Committee may attend a meeting of the Committee.
13.	Procedure, Records and Reporting
	The chair of the Committee shall report regularly to the Board on the Committee’s activities, findings and re commendations. Minutes of all meetings shall be made available to the Board, and all information reviewed and discussed by the Committee at any meeting shall be retained and made available for examination by the Board upon request of the chair.
14.	Independent Advisors
	The Audit Committee may engage independent counsel and other advisors as it determines necessary to carry out its duties. Furthermore, the Committee has the authority to set and pay the compensation for any such advisors which are employed by the Committee. The Corporation will provide the Committee adequate funds to cover fees and other costs incurred in carrying out its duties and responsibilities.
15.	Review of Committee Performance and Charter
	At least annually the Committee will review its performance and effectiveness and report the results to the Board. The annual review will include an assessment of the adequacy of this Charter and the Committee will recommend any proposed changes to the Board for approval.
16.	Duties and Reliance
	(a)	In exercising their powers and discharging their duties under this charter and applicable law, each member of the Audit Committee must (i) act honestly and in good faith with a view to the best interests of the Corporation and (ii) exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

	(b)	Each member of the Audit Committee will be entitled to reasonable reliance, or reliance in good faith, on:
		(i)	financial statements of the Corporation represented to the member of the Committee by an officer of the Corporation or in a written report of the external auditor of the Corporation to reflect fairly the financial condition of the Corporation;
		(ii)	the Corporation’s disclosure compliance system and on the Corporation’s officers, employees and others whose duties would in the ordinary course have given them knowledge of the relevant facts; and
		(iii)	a report, statement or opinion of an expert, being a person or company whose profession gives authority to a statement made in a professional capacity by the person or company including, without limitation, an accountant, actuary, appraiser, auditor, engineer, financial analyst, geologist or lawyer.
MANDATE OF COMMITTEE
17.	External Auditor
	(a)	The external auditor will report directly to the Audit Committee, be responsible for planning with the Corporation and carrying out the audit of the annual financial statements (and any requested review of quarterly financial statements) and ultimately be accountable to the Audit Committee and the Board as the representatives of the shareholders.
	(b)	The Audit Committee will recommend to the Board:
		(i)	the external auditor to be nominated for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Corporation; and
		(ii)	the compensation of the external auditor.
	(c)	The Audit Committee will be directly responsible for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Corporation, including the following:
		(i)	review of the mandate of the external auditor, including the annual engagement letter, audit plan, audit scope and the factors considered in determining the audit scope, including the major risk factors; and confirmation as to whether or not any limitations have been placed on the scope or nature of the external auditor’s audit procedures;
		(ii)	review of significant accounting and reporting principles, practices and procedures applied by the Corporation in preparing its financial statements, including discussions with the external auditor of its judgments about the quality, not just the acceptability, of the Corporation’s accounting principles used in financing reporting;

	(iii)	review of the independence of the external auditor, and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees;
	(iv)	review any rotation of the partners assigned to the audit in accordance with applicable laws and professional standards, the internal quality control findings of the external auditor’s firm and peer reviews;
	(v)	review of the performance of the external auditor, including the relationship between the external auditor and management and the evaluation of the lead partner of the external auditor;
	(vi)	termination or resignation of the external auditor if circumstances warrant, after due inquiry and discussion with management and the external auditor;
	(vii)	resolution of disagreements between management and the external auditor regarding financial reporting;
	(viii)	review of material written communications between the external auditor and management;
	(ix)	review of the annual management letter from the external auditor regarding internal controls and opportunities for improvement or efficiency, plus management’s response and follow-up in respect of any identified weakness; and
	(x)	communication with the external auditor regarding such other matters as are required by the Canadian Institute of Chartered Accountants Handbook and other professional standards.
(d)	As necessary or desirable, but in any case at least quarterly the Audit Committee will meet or communicate directly with the external auditor and members of management, in separate executive sessions, as required or appropriate to discharge the responsibilities of the Committee. Discuss with the external auditor, without management being present, (a) the quality of the Corporation’s financial and accounting personnel, and (b) the completeness and accuracy of the Corporations’s financial statements. Also, elicit the comments of management regarding the responsiveness of the external auditors to the Corporation’s needs.
(e)	Have a predetermined arrangement with the external auditor that it will advise the Committee, through its Chair and management of the Corporation, of any matters identified through procedures followed for the review of interim quarterly financial statements of the Corporation, and that such notification is to be made prior to the related press release. Also receive a written confirmation provided by the external auditor at the end of each of the first three quarters of the year that it has nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues.

18.	Non-Audit Services
	(a)	The Audit Committee will pre-approve all non-audit services to be provided to the Corporation or its subsidiaries by the external auditor.
	(b)	The Audit Committee may delegate to one or more of its members the authority to pre-approve non-audit services. The pre-approval of non-audit services by any member to whom authority has been delegated must be presented to the Committee at its first scheduled meeting following such pre-approval.
	(c)	Pre-approval of de minimus non-audit services will be satisfied if:
		(i)	the aggregate amount of all the non-audit services that were not pre-approved is reasonably expected to constitute no more than five per cent of the total amount of fees paid by the Corporation and its subsidiaries to the Corporation’s external auditor during the fiscal year in which the services are provided;
		(ii)	the Corporation or the subsidiary, as the case may be, did not recognize the services as non-audit services at the time of the engagement; and
		(iii)	the services are promptly brought to the attention of the Audit Committee and approved, prior to the completion of the audit, by the Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Committee.
	(d)	Pre-approval of non-audit services will also be satisfied if the Audit Committee adopts specific policies and procedures for the engagement of non-audit services and:
		(i)	the pre-approval policies and procedures are detailed as to the particular service;
		(ii)	the Audit Committee is informed of each non-audit service; and
		(iii)	the procedures do not include delegation of the Audit Committee’s responsibilities to management.
19.	Financial and Other Disclosure
	(a)	The Audit Committee will review, discuss with management (and the external auditor where required or appropriate) and, if required or appropriate, approve or recommend that the Board approve the following Corporation documents prior to public disclosure:
		(i)	annual audited financial statements and related management’s discussion and analysis;
		(ii)	quarterly unaudited financial statements and related management’s discussion and analysis;
		(iii)	certifications by the chief executive officer and chief financial officer of annual and quarterly filings, disclosure controls and procedures and internal controls over financial reporting;

		(iv)	news releases announcing financial results, containing financial information based on unreleased financial results or non-GAAP financial measures or providing earnings guidance or forward-looking financial information; and
		(v)	financial information contained in any annual information form, information circular, prospectus, take-over bid circular, issuer bid circular or rights offering circular.
	(b)	The Audit Committee will be satisfied that adequate procedures are in place for the review of the Corporation’s public disclosure of financial information extracted or derived from the Corporation’s financial statements and will periodically assess the adequacy of those procedures.
	(c)	The Audit Committee will review the disclosure required by applicable securities laws to be included in its annual information form and cross-referenced in a management information circular to solicit proxies from the shareholders of the Corporation for the purpose of electing directors to the Board. That disclosure will consist of the text of this charter, the composition of the Audit Committee, the relevant education and experience of Committee members, reliance on certain exemptions from securities laws relating to audit committees, oversight of the nomination and compensation of the external auditor, policies and procedures for non-audit services and external auditor service fees.
20.	Financial Reporting Processes
	(a)	The Audit Committee will review with management and the external auditor:
		(i)	the appropriateness of the Corporation’s accounting principles and policies and financial reporting;
		(ii)	any changes to the Corporation’s accounting principles and policies and financial reporting as such changes are recommended by management or the external auditor;
		(iii)	the accounting treatment of significant risks and uncertainties;
		(iv)	key estimates and judgments of management that may be material to the Corporation’s financial reporting;
		(v)	significant changes to the audit plan, if any; and
		(vi)	Any serious disputes or difficulties with management encountered during the audit and the cooperation received by the external auditor during its audit, including access to all requested records, data and information.
	(b)	The Audit Committee will in particular review the following specific matters, where material:
		(i)	the effect of regulatory and accounting initiatives;
		(ii)	extraordinary transactions;

		(iii)	the use of special purpose entities;
		(iv)	off-balance sheet transactions;
		(v)	financial risk management, including the use of derivatives;
		(vi)	asset retirement or reclamation obligations;
		(vii)	pension obligations;
		(viii)	commitments, contingencies and guarantees;
		(ix)	related party transactions;
		(x)	actual or pending legal claims, tax or regulatory matters; and
		(xi)	any other matters of accounting or auditing risk.
21.	Other Responsibilities
	(a)	The Audit Committee will establish procedures for:
		(i)	the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and
		(ii)	the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.
	(b)	The Audit Committee will review on a timely basis all discovered incidents of fraud within the Corporation, regardless of monetary value;
	(c)	The Audit Committee will oversee any auditing or accounting reviews or similar procedures or investigations and may conduct its own investigations with full access to books, records, facilities and personnel of the Corporation.
	(d)	The Audit Committee will at least annually provide oversight of the Corporation’s risk management policies.
	(e)	The Audit Committee will review and approve the Corporation’s policies regarding officer and director expenses, perquisites and use of corporate assets, and may review expenses actually incurred by the chief executive officer and other senior officers.
	(f)	The Audit Committee will review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and any former external auditor of the Corporation.
	(g)	Review with management, internal audit and the external auditors the methods used to establish and monitor the Corporation’s policies with respect to unethical or illegal activities by Corporation employees that may have a material impact on the financial statements.

	(h)	Generally as part of the review of the annual financial statements, receive a report(s), at least annually, from the Corporation’s counsel concerning legal, regulatory and compliance matters that may have a material impact on the financial statements.
	(i)	Coordinate with the Reserves Committee as necessary concerning the disclosure of information with respect to the Corporation’s oil and gas reserves, including the Corporation’s procedures for complying with the disclosure requirements and restrictions of applicable regulations.
	(j)	Review with the external auditor the internal controls on computerized information system controls and security.
	(k)	The Audit Committee will review and/or approve any other matters specifically delegated to the Committee by the Board and undertake on behalf of the Board such other activities as may be necessary or desirable to assist the Board in fulfilling its responsibilities.