Exhibit 1.1














ANNUAL INFORMATION FORM














(Except as otherwise noted the


information herein is given


as at December 31,2009)









March 30, 2010













TABLE OF CONTENTS









PageABBREVIATIONS
1CONVERSIONS
1DEFINITIONS
2GLOSSARY OF TECHNICAL TERMS
5CURRENCY
8FORWARD-LOOKING INFORMATION
9CANADIAN SUPERIOR ENERGY INC
12GENERAL DEVELOPMENT OF THE BUSINESS
13DESCRIPTION OF THE BUSINESS
16PRINCIPAL PROPERTIES
21STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
25RISK FACTORS
32DIVIDENDS
42DESCRIPTION OF SHARE CAPITAL
42MARKET FOR SECURITIES
44PRIOR SALES
44ESCROWED SECURITIES
44DIRECTORS AND OFFICERS
45AUDIT COMMITTEE
47LEGAL AND REGULATORY PROCEEDINGS
48INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
48TRANSFER AGENT AND REGISTRAR
49MATERIAL CONTRACTS
49INTERESTS OF EXPERTS
49ADDITIONAL INFORMATION
49







APPENDIX "A"
-
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITORAPPENDIX "B"
-
REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSUREAPPENDIX "C"
-
CHARTER OF THE AUDIT COMMITTEE OF CANADIAN SUPERIOR ENERGY INC.










ABBREVIATIONS




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




Oil,Natural Gas Liquids and Natural Gasbbl
barrelMbbl
thousand barrelsMMbbl
million barrelsbbl/d
barrel or barrels per dayMcf
thousand cubic feetMMcf
million cubic feetMcf/d
thousand cubic feet per dayMMcf/d
million cubic feet per dayMMBtu
million British Thermal UnitsMMscf/d
million standard cubic feet per day of gasBcf
billion cubic feetTcf
trillion cubic feetGJ
gigajoule





OtherAECO
a natural gas storage facility located at Suffield, AlbertaAPI
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 oilBOE
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 wellheadm3
cubic metresMBOE
1,000 barrels of oil equivalent$M
thousands of dollars$MM
millions of dollarsWTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard gradepsi
pounds per square inch2D
two dimensional3D
three dimensional


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 ByMcf
1,000 m3 of gas
0.0281,000 m3 of gas
Mcf
35.493bbl
m3 of oil
0.158m3 of oil
bbl
6.290feet
metres
0.305metres
feet
3.281miles
kilometres
1.609kilometres
miles
0.621acres
hectares
0.405hectares
acres
2.471GJ
MMBtu
0.950















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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 Participation Agreement" means the Participation Agreement dated July 5, 2008 between the Corporation and a third party 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 Corporation, Challenger and the Challenger Shareholders.




"Arrangement Agreement" means the Arrangement Agreement dated June 18, 2009 between the Corporation 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 Canadian Superior in accordance with the provisions of the Joint Operating Agreement, alleging various breaches of the Joint Operating Agreement by Canadian Superior as initiated on February 9, 2009.




"BG Sale Agreement" means the Sale Agreement dated June 30, 2009 between the Corporation 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 Corporation 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.




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




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




"Canada Southern" means Canada Southern Petroleum Ltd.




"Canadian Superior" or the "Corporation" means Canadian Superior Energy Inc.




"CBCA" means theCanada 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.




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













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"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.




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




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




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




"COP 15" means the United Nation's Framework Convention on Climate Change 15th session of the Conference of 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 Corporation 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 Corporation and its joint venture partner by MEEI in respect of MG Block.




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




"Financial Advisor" means Jennings Capital Inc.




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




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




"GLJ" means GLJ Petroleum Consultants Ltd.




"GLJ Report" means the report dated March 18, 2010 prepared by GLJ evaluating the oil, NGL and natural gas reserves attributable to the properties of the Corporation effective December 31, 2009.




"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.




"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.




"Joint Operating Agreement" means the Joint Operating Agreement dated August 11, 2007 between the Corporation, BG and Challenger in respect of Block 5(c).












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"Kan Tan IV Rig" means the Kan Tan IV Semi Submersible Drilling Rig.




"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.




"NEB" means the National Energy Board of Canada.




"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.




"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 Corporation.




"Palo Alto" means Palo Alto Investors, LLC.




"Petrotrin" means the Petroleum Company of Trinidad and Tobago.




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




"PSC" means the Production Sharing Contract dated July 20, 2005 between the Corporation 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 Corporation.




"Rights Plan Agreement" means the Shareholder Rights Plan Agreement dated January 22, 2001 between the Corporation and Valiant Trust Company.




"ROFR" means a right of first refusal.




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




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




"Seeker" means Seeker Petroleum Ltd.













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




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




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




"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 Canadian Superior, 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, Canadian Superior's rights in respect of its participating interest as described in the Joint Operating Agreement.




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




"Trinidad Sale Agreement" means the Purchase and Sale Agreement dated May 21, 2009 between the Corporation 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.




"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.




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




"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;(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;




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(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 Corporation 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:




(a)
in relation to the Corporation'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 Corporation;













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(b)
in relation to wells, the total number of wells in which the Corporation has an interest; and(c)
in relation to properties, the total area of properties in which the Corporation 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 "NGLs" 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 Corporation'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 Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and(c)
in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.


"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 Corporation 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 know 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 wellsite.




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 312009
2008
2007Rate at end of period
US$0.9564
US$0.8166
US$1.0120Average rate during period
US$0.8757
US$0.9381
US$0.9304High
US$0.9748
US$1.0289
US$1.0905Low
US$0.7698
US$0.7711
US$0.8437









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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 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:




·
volumes and estimated value of Canadian Superior's oil and gas reserves;·
the life of each of Canadian Superior's reserves;·
volume and product mix of Canadian Superior's oil and gas production;·
future oil and gas prices and interest rates in respect of Canadian Superior's commodity risk management programs;·
the amount and timing of future asset retirement obligations;·
future liquidity, creditworthiness and financial capacity;·
future interest rates;·
future results from operations and operating metrics;·
future development, exploration and other expenditures;·
future costs, expenses and royalty rates; and·
Canadian Superior'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 Corporation 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 Corporation believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because the Corporation 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:




·
field production rates and decline rates;·
the ability of the Corporation to secure adequate product transportation;·
the impact of increasing competition in or near the Corporation's properties;·
the timely receipt of any required regulatory approvals;·
the ability of the Corporation to obtain qualified staff, equipment and services in a timely and cost efficient manner to develop its business;·
Canadian Superior's ability to operate the properties in a safe, efficient and effective manner;·
the ability of the Corporation to obtain financing on acceptable terms;·
the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;




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·
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 Corporation 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 Corporation for the year ended December 31, 2009 and  "Risk Management" and "Risk Assessment" in the management discussion and analysis of the Corporation for the year ended December 31, 2009.  Canadian Superior 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:




·
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;·
sufficient liquidity for future operations;·
cost of capital risk to carry out Canadian Superior's operations;·
unforeseen title defects;·
aboriginal land claims;·
increased competition and the lack of availability of qualified personnel or management;·
loss of key personnel;·
ability to attract key personnel, including the hiring of a Chief Executive 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;









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·
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 Corporation 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.












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CANADIAN SUPERIOR ENERGY INC.




General




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




·
on April 17, 1993 to change the name of the Corporation to "KapaIua Gold Mines Ltd." and to remove the private company restrictions;·
on November 16, 1993 to change the name of the Corporation 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 Corporation to "Canadian Superior Energy Inc." and toconsolidate 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 Corporation; and·
on February 3, 2010 to add the Series B Preferred Shares to the authorized share capital of the Corporation.


The Corporation is a reporting issuer, or the equivalent, in the provinces of British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia and Newfoundland and Labrador.  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 "SNG".




The head office and registered office of the Corporation is located at 3200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6. In addition, the Corporation has offices located in Halifax, Nova Scotia; Jersey City, New Jersey; Drumheller, Alberta; St. Clair, Port of Spain, Trinidad and Tobago; and Gammarth, Tunis, Tunisia.




Intercorporate Relationships




The percentage of votes attaching to all voting securities of the material subsidiaries beneficially owned, or controlled or directed, directly or indirectly, by Canadian Superior, 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




Canadian Superior is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada, offshore Nova Scotia, Canada, offshore Trinidad and Tobago and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Corporation also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities. The Corporation is also engaged in the LNG Project.




Three Year History




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




2007




On January 23, 2007,  the Corporation announced that its offshore Nova Scotia exploration acreage holdings had increased to 1,048,136 net hectares (2.59 million net acres) with the addition of the Falcon Exploration License 2412 and the Osprey Exploration License 2413 deepwater blocks previously held by a U.S. company.  The Falcon Exploration License 2412 and the Osprey Exploration License 2413 complimented Canadian Superior's Mayflower Exploration Licence 2406, Marauder Exploration Licence 2415, Marconi Exploration Licence 2416, Mariner Exploration Licence 2409 and Marquis Exploration Licence 2402.




On June 26, 2007, Greg Noval was appointed as the Executive Chairman of the Board.




On August 11, 2007, the Corporation entered into the Joint Operating Agreement with BG and Challenger in respect of the exploration drilling and development of Block 5(c).  Under the terms of the Joint Operating Agreement, BG acquired a 30% working interest in the PSC.  The Joint Operating Agreement was approved by the Government of the Republic of Trinidad and Tobago on October 29, 2007.  Also, under the terms of the Joint Operating Agreement, BG paid Canadian Superior approximately US$38.7 million and, on a go forward basis, paid approximately 40% of the exploration costs associated with the drilling of the three commitment wells required on Block 5(c).




On October 1, 2007, Craig McKenzie was appointed as the Chief Executive Officer of the Corporation.




On November 15, 2007, Craig McKenzie was appointed as a member of the Board.




On November 16, 2007, the Corporation completed a private placement of 6,472,500 Common Shares issued on a "flow-through " basis at a price of $3.50 per Common Share for gross proceeds of approximately $22.7 million.




2008




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




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




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




On March 26, 2008, the Corporation 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 $22.2million 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












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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, Canadian Superior announced its participation in the LNG Project.  The LNG Project was to be conducted by a 50/50 joint venture between Canadian Superior and Global LNG Inc.  Under the terms of the joint venture agreement, Canadian Superior agreed to advance the first US$10.0 million of the pre-construction costs for the LNG Project.  On August 13, 2009, the Corporation executed an agreement as a result of which the Corporation now owns 100% of the LNG Project and is responsible for 100% of the ongoing costs.




On July 5, 2008, Canadian Superior entered into the 7th of November Block Participation Agreement with a third party 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, Canadian Superior is to use reasonable efforts to transfer a 50% participating interest in the EPSA to the third party. The third party's participating interest is to be held in trust by Canadian Superior until the third party is recognized as a party to the EPSA. The third party is obligated to pay its share of the project costs incurred after July 5, 2009.




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




On August 27, 2008, Canadian Superior entered into the EPSA with Joint Oil, on behalf of itself as to a 50% participating interest and a third party as to a 50% participating interest (which participating interest is currently held in trust by Canadian Superior). Under the terms of the EPSA, Canadian Superior has been named the operator of the 7th of November Block.




On August 27, 2008, Canadian Superior 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 royalty well has been spud on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to Canadian Superior for US$12.5 million.




On September 3, 2008, the Corporation 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 or were exercised.




On September 23, 2008, Canadian Superior 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 Corporation and as a member of the Board.  Michael Coolen was appointed as the Chief Executive Officer of the Corporation.




On December 5, 2008, the Corporation 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, Canadian Superior 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 Proceedings"












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On February 10, 2009, the Corporation 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 Corporation received a demand letter from Canadian Western Bank for repayment of all amounts outstanding under the Corporation's $45.0 million credit facility with Canadian Western Bank by February 23, 2009.




On February 23, 2009,the Corporation advised that it had reached an accommodation with Canadian Western Bank whereby the demand for repayment of all amounts outstanding under the Corporation'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 Corporation from the sale of certain Western Canadian properties.




On March 3, 2009, the Corporation announced the successful flow testing of the "Endeavour" well, the third well drilled by the Corporation 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 Officerof 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 Corporation.




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.




On September 15, 2009, the Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation's credit facility from $25.0 million to $40.0 million.  The credit facility is subject to its next scheduled review in April 2010.




On December 21, 2009, the Corporation announced that due to the current industry environment and market conditions, the Corporation 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 other areas.  The Corporation extended the Mariner Exploration License 2409 until December 31, 2010.




Recent Developments




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












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On January 19, 2010, the Corporation 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 Corporation converted all of the 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 Corporation dated February 4, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein.




Significant Acquisitions




The Corporation did not complete any significant acquisitions during the year ended December 31, 2009 for which disclosure was required under Part 8 of NI 51-102.




DESCRIPTION OF THE BUSINESS




General




Canadian Superior is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada, offshore Nova Scotia, Canada, offshore Trinidad and Tobago and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Corporation also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities. The Corporation is also engaged in the LNG Project.




Competitive Conditions




The oil and natural gas industry is intensely competitive in all its phases.  Canadian Superior 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.  Canadian Superior's competitors include resource companies which have greater financial resources, staff and facilities than those of Canadian Superior.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery.  Canadian Superior 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, 2009, Canadian Superior recorded an obligation on its balance sheet of $14.0 million for asset retirement.  The Corporation 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 Corporation 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 Canadian Superior 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 Canadian Superior's financial condition, results of operations or prospects.  See "Risk Factors – Environmental Risks" and "Industry Conditions".















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Employees




The Corporation has a total of 35 full-time staff, including one staff member in its Halifax, Nova Scotia office, three staff members in its Jersey City, New Jersey office, eight staff members in its Drumheller, Alberta office, three staff members in its St. Clair, Port of Spain, Trinidad and Tobago office and one consultant in its Gammarth, Tunis, Tunisia office.




Foreign Operations




In addition to its Canadian operations, Canadian Superior is engaged in the exploration for oil and natural gas in Trinidad and Tobago, Tunisia and Libya and is engaged in the LNG Project.   International oil and gas operations are subject to inherent risks and uncertainties which are beyond the control of Canadian Superior, 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. Canadian Superior's international exploration ventures may entail certain political and technical business risks. Canadian Superior's strategy is to mitigate such risks by aligning itself with partners and engaging personnel and consultants that have international experience.  See "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 Canadian Superior with a default notice under the provisions of the Joint Operating Agreement, alleging various breaches of the Joint Operating Agreement by Canadian Superior.  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% 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, Canadian Superior served Challenger and BG with a default notice under the provisions of the Joint Operating Agreement alleging various breaches of the Joint Operating Agreement by one or both of BG and Challenger.  A further default notice was served on Challenger by Canadian Superior on March 24, 2009 with respect to Challenger's obligations under the Block 5(c) Participation Agreement.  In addition, on March 24, 2009, Canadian Superior served Challenger with a default notice under the Bridge Facility and the Joint Operating Agreement.  The foregoing default notices issued against Challenger were stayed in accordance with the terms of the Challenger CCAA Proceedings.




On March 4, 2009, Canadian Superior filed an application with the Court for an order allowing Canadian Superior to prepare a plan of arrangement under the CCAA, and staying all claims and actions against Canadian Superior and its assets.  On March 5, 2009, the application of Canadian Superior for an initial order granting protection under the CCAA was successful.  The result of this successful application was that Canadian Superior was permitted to prepare a plan of arrangement, and all claims and actions against the assets of Canadian Superior, 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 Canadian Superior's rights in respect of its participating interest as described in the Joint Operating Agreement, were stayed.  The initial order permitted Canadian Superior 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, Canadian Superior 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












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45% interest in Block 5(c).  Canadian Superior advised the Court that such a sale would allow Canadian Superior to restructure in an organized manner and emerge from the CCAA Proceedings in due course.




On March 11, 2009, the Corporation announced that the NYSE Amex had halted the trading of the Common Shares.  In addition, the NYSE Amex advised the Corporation of its intention to file a delisting application with the SEC due to its determination that the Corporation 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 Canadian Superior 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 Canadian Superior including, but not limited to, a sale of Canadian Superior, a recapitalization, an equity injection or a sale of certain assets with a view to Canadian Superior's successful emergence from the CCAA Proceedings.




On April 22, 2009, the Corporation 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 Corporation 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 Corporation 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 Corporation's audited financial statements and related documents.  The Common Shares resumed trading on the NYSE Amex on May 6, 2009.




On July 10, 2009, the Court approved an Arrangement Agreement contemplating the Arrangement wherein the Corporation 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 Corporation announced that the NYSE Amex had notified the Corporation 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 Corporation 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:




·
Canadian Superior 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 Canadian Superior emerging from CCAA protection, Canadian Superior 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 Corporation filed the Arrangement with the Court.  The purpose of the Arrangement was to effect a compromise and settlement of all affected claims in order to allow the Corporation 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:















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·
The Corporation 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 Corporation 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 Joint Operating Agreement;·
The Corporation would pay to the Monitor an amount sufficient to fund the affected creditors' pool and disputed claims reserve; and·
The Corporation 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 Corporation emerged from CCAA protection.




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




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




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 Canadian Superior pursue the sale of a 25% interest or more in Block 5(c) and by an agreement dated February 19, 2009, Canadian Superior 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 Canadian Superior 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 Corporation's exploration and evaluation of various strategic alternatives to maximize value for the Shareholders and address the interests of the Corporation'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 Corporation's Western Canadian assets.  The previously constituted special committee charged with dealing with issues between the Corporation and Challenger was dissolved and the Independent Committee assumed its mandate.












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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 Canadian Superior 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 Canadian Superior 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 Canadian Superior signed a non-binding letter of intent to negotiate a formal agreement to effect the acquisition by Canadian Superior 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 Canadian Superior 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, Canadian Superior entered into an agreement of purchase and sale with Centrica, under which Centrica agreed to acquire from Canadian Superior 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 Joint Operating Agreement 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 Canadian Superior and to Challenger advising both parties that BG was electing to exercise its ROFR, as provided by the Joint Operating Agreement, to purchase the 45% interest in Block 5(c) that Canadian Superior has agreed to sell to Centrica.  Following the receipt of the notice of exercise of the ROFR, BG and Canadian Superior 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.




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 Corporation under the CCAA Proceedings; and (v) the impact on the Corporation 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.








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On July 30, 2009, BG and Canadian Superior entered into the Compromise Agreement, under which Canadian Superior 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 Canadian Superior and Challenger under the CCAA Proceedings and the Challenger CCAA Proceedings, respectively.  In accordance with the Compromise Agreement, the settlement amount was setoff 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.




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.




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 Corporation emerged from CCAA protection.




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 Canadian Superior.  To this end, the Corporation 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.


Canadian Superior 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 Corporation'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 Corporation's working interest share before the deduction of royalties payable to others.




Producing Properties




Western Canada




The Corporation derives all of its production and cash flow from Western Canada.  Approximately 65% of the Corporation's production comes from the Drumheller area of Alberta. The balance of production largely comes from the Kaybob/Windfall, and Peace River Arch areas.




All of the  Corporation's Western Canada drilling activity occurred in the latter part of  2009.  When the Corporation emerged from CCAA protection in the fall there was approximately $10.0 million of 2008 flow through capital to be spent. This amount was spent in November and December of 2009.   The Corporation drilled or participated in 13












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gross wells, 12 operated and one non-operated exploration wells (a total of 11.63 net wells) with an overall success rate of 54%.  At December 31, 2009, the Corporation held in Western Canada 161,289 gross hectares or 398,555 gross acres (106,238 net hectares or 262,519 net acres) of predominately Canadian Superior operated lands with an average working interest of approximately 66%.




The lack of drilling and maintenance spending in 2009 resulted in a declining production base over 2008 levels. Average production in December 2009 was 2,897 BOE/d.  This was comprised of 14,305 Mcf/d, 425 bbl/d of oil and 88 bbl/d of NGLs.  There was approximately 500 BOE/d was behind pipe awaiting tie-in at year end.




The Drumheller area offers a multitude of  oil and gas play types  contained in several distinct stratigraphic zones.  The shallow targets include the Second White Specks, Medicine Hat, Belly River group, and Edmonton groups and range in depth from 300 to 1,100 metres (980 to 3,600 feet).  Production from in these zones range from 50 to 750 Mcf/d with associated reserve size of 0.1 to 1 Bcf.  Deeper targets in the Drumheller area include Mannville group sands and the Banff formation.  The Mannville group typically encounters several stacked reservoirs such as the Colony, Glauconitic, Ostracod, Ellerslie, and Detrital with average production rates for these horizons ranging from 250 to over 1000 Mcf/d and reserves of 0.5 to 2.0 Bcf.  The Banff formation is a carbonate play which ranges in depth from 1,100 to 1,400 metres (3,600 to 4,600 feet) and tend to be oil prone.  On average, the Banff formation can produce oil rates of 20 to 200 bbl/d with reserves ranging from 15 to 150 Mbbl.




At December 31, 2009, the Corporation held 61,165 gross hectares or 151,141 gross acres (35,838 net hectares or 88,557 net acres) of land in the greater Drumheller area. Included in this number is 11,605 gross undeveloped hectares or 28,676 gross undeveloped acres (8,524 net undeveloped hectares or 21,064 net undeveloped acres).  This core area accounts for approximately 65% of the Corporation's production.  In 2009, 2.0 gross (2.0 net) exploration wells were drilled in the Drumheller area with a success rate of 50%.




Drumheller




The Drumheller area is near the heart of CBM development in Western Canada and the Corporation has a concentrated, high working interest land position in both the Horseshoe Canyon and the Mannville CBM fairways. The Corporation holds 41,612 gross hectares or 102,825 gross acres (21,983 net hectares or 54,322 net acres) of Horseshoe Canyon CBM rights. The Horseshoe Canyon coals are typically found in a package of 8 to 10 seams with each seam 0.75 to 1.50 metres (2.46 to 4.92 feet)  in thickness and occur at a depth of 200 to 400 metres (656 to 1,312 feet). These coals contain dry gas and produce little or no water. The Corporation also holds 8,482 hectares (20,960 acres) of land with Mannville CBM potential.




Windfall




The Banff, Nordegg and various Cretaceous formations are the drilling targets in the Windfall area.  Canadian Superior drilled one well in 2009.  This well targeted the Leduc Formation and was unsuccessful.  The Corporation continues to look at this higher reward-medium risk area with a view towards further expansion.




Kaybob




During 2009 Canadian Superior did not drill any wells in  the Kaybob area of Alberta; however, Kaybob is viewed as an area of future focus.  The Corporation is focused on the potential of the Nordegg formation, Mannville group, and Viking formation in this area.  Several vertical and horizontal locations have been identified on the Corporation's lands.




Exploration Properties




Trinidad and Tobago




On July 20, 2005, Canadian Superior signed the PSC for the 32,417 hectare(80,041 acre) Block 5(c) with the Government of the Republic of Trinidad and Tobago. The PSC provides Canadian Superior the right to explore on Block 5(c), which is located approximately 97 kilometres (60 miles) off the east coast of Trinidad with water depths in the range of 150 to 450 metres (500 to 1,500 feet). During 2005 and 2006, the Corporation actively pursued various rig options for the Block 5(c) drilling and entered into a firm drilling contract for the Kan Tan IV Rig to drill












-23-







the first three exploration wells. These wells were planned to evaluate three large separate potential hydrocarbon bearing structures, "Victory", "Bounty" and "Endeavour". These prospects had been delineated by Canadian Superior following evaluation and interpretation of extensive 3D seismic over Block 5(c).




Following a scheduled refurbishment in Brownsville, Texas, the Kan Tan IV Rig was moved to the port of Chaguarmas in Trinidad and then to the first drilling location on the "Victory" prospect. The Kan Tan IV Rig arrived at the "Victory-1" well site on June 19, 2007 and commenced drilling operations on June 25, 2007. On August 30, 2007, the "Victory-1" well reached Total Depth of 5,066 metres (16,621 feet) (subsea). While attempting to come out of the hole to commence wireline logging and possible flow testing of the well, a portion of the drill string became stuck in the hole and was deemed unretrievable. Accordingly, the well was plugged back to a depth of approximately 2,915 metres (9,564 feet) and re-drilled to a total depth of 4,923 metres (16,150 feet). On December 17, 2007, the Corporation announced that all participants had agreed to case and conduct flow tests on the "Victory-1" well.




The "Victory-1" well tested natural gas from two formations. The first test was conducted at rates of between 40 and 45 MMscf/d, and the second test was conducted at rates of over 30 MMscf/d. Both tests were rate restricted by testing equipment and had high flowing pressures. The "Victory-1" well was subsequently suspended so that the wellbore is available for possible future re-entry.




On February 20, 2008, the Kan Tan IV Rig spudded the "Bounty-1" well approximately 3.5 kilometres (2.2 miles) east from the "Victory-1" well location. On July 9, 2008, the Corporation announced that the "Bounty" well reached Total Depth of 5,291 metres (17,360 feet) (subsea) and that all participants had agreed to case and conduct flow tests on the "Bounty-1" well.




The "Bounty-1" well successfully tested natural gas from the primary target formation (Pleistocene "I" sand). The results from the "Bounty-1" well test combined with 3D seismic interpretation and other data indicate the presence of a natural gas resource. During the testing of the "Bounty-1" well, production testing equipment flow capacity was maximized. The result was a stabilized flow rate of 60 MMcf/d of natural gas with a flowing wellhead pressure of 4,505 psi.The Bounty-1well was subsequently suspended with a number of cement plugs and is available for future re-entry.




On August 28, 2008, the Kan Tan IV Rig spudded the "Endeavour-1" well, the third and final well of the initial exploration program, approximately 8.4 kilometres (5.2 miles) north of the "Bounty-1" well location. On December 29, 2008 the Corporation announced that, having reached 5,201 metres (17,063 feet) (subsea), the Corporation and its partners had decided to re-drill the final section of the "Endeavour-1" well. This sidetrack was necessary as the initial well bore had lost integrity during well control operations. On January 23, 2009, the Corporation announced that the "Endeavour-1" well had reached Total Depth of 5,311 metres (17,426 feet) (subsea) and that all participants had agreed to case and conduct flow tests on the "Endeavour-1" well.




The "Endeavour-1" well successfully tested natural gas in the primary target formation (Pleistocene "I" sand). During testing, production testing equipment capacity was maximized resulting in flow testing being restricted to a peak flow rate of 60.1 MMscf/d of natural gas with a flowing wellhead pressure of 4,122 psi. The well was subsequently suspended with a number of cement plugs for future re-entry. The Kan Tan IV Rig was subsequently released from location and from contract.




Canadian Superior currently has a 25% working interest Block 5(c). BG holds the remaining 75% interest. As the Joint Operating Agreement contemplated, BG became the operator of Block 5(c) upon finishing the original three well drilling commitment. Preparation for the drilling of an appraisal location(s) is ongoing. At December 31, 2009, BG held in escrow for Canadian Superior US$20.0 million.  The Corporation must maintain the lesser of US$20.0 million or 25% of the estimated capital expenditure requirements in respect of Block 5(c) through to the end of the second phase of the exploration program. Any draws made against the US$20.0 million are required to be replenished by the Corporation within 30 days of the draw date. The Corporation's future obligations for the exploration and development of Block 5(c) are largely dependent on BG's decisions as operator and the Government of the Republic of Trinidad and Tobago.  The data from the exploration wells is being collectively evaluated before deciding on commercial viability.












-24-




In 2007, the Corporation received the Exploration and Production License from the Government of the Republic of Trinidad and Tobago on the MG Block and, as a result, was committed to conducting 3D seismic by the end of 2009 and to drill two exploration wells on the MG Block in a joint venture with Petrotrin.  The first well had to be drilled to a depth of at least 3,000 meters by January 2010 and the second to a depth of at least 1,800 metres (5,906 feet) by July 2010.  The Corporation estimates that its share of the cost of these wells to be approximately US$15.0 million per well.  The estimated cost of the 3D seismic program is approximately US$30.0 million.  The Corporation has agreed to provide a performance security to Petrotrin of US$12.0 million to meet the minimum work program.  The Corporation has not conducted the 3D seismic or drilled any exploration wells as it believes that the MG Block is not economically viable and that there are significant ecological issues in conducting operations.  The Corporation has met with Petrotrin and the Government of the Republic of Trinidad and Tobago to express its concerns and requested that the work obligations be transferred without penalty to a more prospective area.  While the Corporation believes that its request remains under consideration, it is possible that the request will be denied and the Corporation may be required to pay some portion of the performance security in order to relinquish the MG Block.




North Africa, Tunisia and Libya




On September 3, 2008, Canadian Superior announced its "Oasis" Project, the Corporation's first entry into North Africa.  Oasis commenced with the formal signing ceremonies for the EPSA which were conducted on August 27, 2008, in Tunis, Tunisia. Under the terms of the EPSA, Canadian Superior was named operator of  the 7th of November Block which straddles the nautical border between Libya and Tunisia. The 7th of November Block comprises an area of approximately 1,931 square kilometres or 310,799 hectares (1,200 square miles or 768,000 acres), located approximately 121 kilometres (75 miles) offshore the Mediterranean Gulf of Gabes, in water depths ranging from 76 to 114 metres (250 to 375 feet). In accordance with the terms of the EPSA, Joint Oil awarded to Canadian Superior, the exclusive right to explore for, develop and produce crude oil and natural gas from the 7th of November Block.




On August 27, 2008, Canadian Superior 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. If at the end of August 2011, no royalty well has been spud on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to Canadian Superior for US$12.5 million.




The exploration work commitment for the first phase (four years) of the seven year exploration period of the EPSA includes three exploration wells, 500 square kilometres (311 square miles) of 3D seismic, and one appraisal well.  This appraisal well is intended to be the first well in the drilling program and will be delineating a significant gas, condensate and oil discovery drilled in the 1990's known as "Zarat" in the adjacent contract area.  Based on 3D seismic acquired subsequent to the discoveries, a substantial portion of the undeveloped "Zarat discovery area" is interpreted to extend north, into the 7th of November Block.




In 2009, Canadian Superior technical staff interpreted the existing seismic provided under the terms of the EPSA. The appraisal location has been picked on the Zarat 3D volume. Early production from Zarat will be liquids only which will find ready access to nearby, well traded markets. Multiple leads have been identified on the existing 2D data base which will be further delineated with the acquisition of new 3D data.




Offshore Nova Scotia,Canada




The Corporation is one of the few operators in the offshore Nova Scotia basin and currently holds the Mariner Exploration License 2409.  The Mariner Exploration License 2409 is in the Sable Island area which is an area of natural gas supply that is strategic for North Eastern United States gas supply. The Corporation relinquished Mayflower Exploration License 2406 and the Marauder Exploration License 2415 at the end of 2009.




Canadian Superior's reduced Mariner Block covers 11,246 hectares (27,790 acres) and is located approximately 9 kilometres (5.6 miles) northeast of Sable Island and directly offsets five significant discoveries near Sable Island, including the ExxonMobil Venture natural gas field and other nearby Sable Offshore Energy Project production infrastructure.  A Cretaceous structure has been identified for drilling on the Mariner Block based on an evaluation












-25-





of seismic data. Under the Swap Agreement, an overriding royalty interest and optional participating interest was awarded to Joint Oil in the Mariner Block.




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, 2009, the oil, NGL and natural gas reserves attributable to the properties of Canadian Superior.  All of the Corporation's reserves are located in the Canadian provinces of British Columbia, Alberta and Saskatchewan.




The tables below are summaries of the oil, NGL and natural gas reserves of the Corporation 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 Corporation'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 Corporation'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 Corporation'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 Corporation and GLJ's opinions of reasonable practice in the industry.  The extent and character of ownership and all factual data pertaining to the Corporation's petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation 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 ReservesLight and Medium Crude Oil
NGLs
Natural Gas
Light and Medium Crude Oil
NGLs
Natural GasReserve Category
Mbbls
Mbbls
MMcf
Mbbls
Mbbls
MMcfProvedDeveloped Producing
827
156
19,870
744
99
17,642Developed Non-Producing
32
125
5,129
29
91
4,446Undeveloped
9
1
4,329
8
1
4,039Total Proved
868
282
29,328
781
191
26,127Probable
939
147
16,708
780
96
14,734Total Proved Plus Probable
1,807
429
46,036
1,561
287
40,861














-26-





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$)ProvedDeveloped Producing
120,847
98,866
84,360
74,031
66,276Developed Non-Producing
21,637
17,938
15,301
13,325
11,790Undeveloped
11,095
7,384
4,850
3,057
1,747Total Proved
153,579
124,188
104,511
90,413
79,813Probable
120,644
76,006
52,966
39,415
30,681Total Proved Plus Probable
274,223
200,194
157,476
129,828
110,495





After Future Income Tax Expenses and Discounted at (%/year)0%
5%
10%
15%
20%Reserve Category
(M$)
(M$)
(M$)
(M$)
(M$)ProvedDeveloped Producing
120,847
98,866
84,360
74,031
66,276Developed Non-Producing
21,637
17,938
15,301
13,325
11,790Undeveloped
11,095
7,384
4,850
3,057
1,747Total Proved
153,579
124,188
104,511
90,413
79,813Probable
120,644
76,006
52,966
39,415
30,681Total Proved Plus Probable
274,223
200,194
157,476
129,828
110,495





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 ExpensesReserve Category
(M$)
(M$)
(M$)
(M$)
(M$)
(M$)
(M$)
(M$)Total Proved
310,188
33,403
102,214
13,156
7,836
153,579
-
153,579Total Proved Plus Probable
563,261
68,646
188,162
22,616
9,615
274,223
-
274,223













-27-





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%/yearReserve Category and Product Group
(M$)
($/BOE)Total ProvedLight and Medium Crude Oil
32,289
30.81Associated Gas and Non-Associated Gas
66,638
19.03Non-Conventional Oil and Gas Activities (CBM)
5,584
7.21Total
104,511
19.63Total Proved Plus ProbableLight and Medium Crude Oil
50,945
25.32Associated Gas and Non-Associated Gas
95,401
18.31Non-Conventional Oil and Gas Activities (CBM)
11,130
7.76Total
157,476
18.19




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, 2009 in estimating the Corporation's reserves data, using forecast prices and costs.




Year
Infla-

tion

%
Bank of Canada Average Noon Ex-change 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
Alberta NGLsSpec Ethane
Edmonton Propane
Edmonton Butane
Edmonton Pentanes Plus$US/$
$US/bbl
$US/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl
$/bbl2010
2.0
0.95
80.00
78.50
83.26
74.61
70.36
70.76
64.99
78.27
76.60
20.02
52.46
64.11
84.932011
2.0
0.95
81.37
81.50
86.42
72.59
71.30
71.70
65.24
80.37
78.64
22.88
54.45
66.54
88.152012
2.0
0.95
82.66
84.50
89.58
73.45
72.11
72.51
65.33
83.31
80.62
23.24
56.43
68.98
91.372013
2.0
0.95
83.87
87.50
92.74
74.19
72.80
73.20
65.26
86.25
82.54
23.43
58.42
71.41
94.592014
2.0
0.95
85.00
90.50
95.90
76.72
75.28
75.68
67.52
89.19
85.35
23.79
60.42
73.84
97.82Thereafter escalation rate of 2%





Year
Henry Hub NYMEX

Near Month  Contract
Midwest

Price at Chicago
AECO/NIT Spot
Alberta Plant Gate
Saskatchewan Plant Gate
Sumas Spot
British Columbia
Sulphur FOB Vancouver
Alberta Sulphur at Plant GateSpot

Constant 2009 $
ARP
Aggre-

gator
Alliance
Sask

Energy
Spot
Westcoast Station 2
Spot Plant Gate$US/

MMBtu
$US/

MMBtu
$/

MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$/MMBtu
$US/LT
$/LT2010
6.00
6.10
5.96
5.75
5.58
5.51
5.00
5.68
5.88
5.60
5.76
5.56
35.00
(6.16)2011
7.00
7.10
6.79
6.58
6.38
6.30
6.07
6.48
6.71
6.45
6.59
6.38
50.00
9.632012
7.10
7.20
6.89
6.68
6.48
6.40
6.12
6.58
6.81
6.55
6.69
6.49
60.00
20.162013
7.15
7.25
6.95
6.73
6.53
6.45
6.17
6.63
6.87
6.60
6.75
6.54
75.00
35.952014
7.35
7.45
7.05
6.84
6.63
6.55
6.37
6.73
7.08
6.80
6.85
6.64
75.00
35.95Thereafter 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.












-28-




The weighted average realized sales prices by the Corporation for the year ended December 31, 2009 was $4.09/Mcf for natural gas net of transportation, $58.56/bbl for light and medium crude oil and $48.38/bbl for NGLs.




Reconciliation of Corporation Gross Reserves by Product Type




The following table sets forth the changes the Corporation's reserve volume estimates made as at December 31, 2009 and the corresponding estimates as at December 31, 2008, using forecast prices and costs.




Light and Medium Crude Oil
CBM
Natural Gas
NGLs
Total Oil EquivalentGross 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 ProbableFactors
(Mbbl)
(Mbbl)
(Mbbl)
(MMcf)
(MMcf)
(MMcf)
(MMcf)
(MMcf)
(MMcf)
(Mbbl)
(Mbbl)
(Mbbl)
(MBOE)
(MBOE)
(MBOE)Dec. 31, 2008
1,062
892
1,954
4,872
4,819
9,691
26,237
13,261
39,498
278
155
433
6,525
4,060
10,585Extensions and Improved Recovery
10
79
89
37
9
46
1,985
827
2,812
75
29
103
421
247
669Technical Revisions
(40)
(29)
(69)
506
(512)
(6)
1,364
(1,523)
(160)
(24)
(36)
(60)
247
(404)
(157)Discoveries
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-Acquisitions
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-Dispositions
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-Economic Factors
(4)
(4)
(8)
(46)
(46)
(92)
(249)
(126)
(375)
(2)
(1)
(3)
(56)
(33)
(89)Production
(159)
-
(159)
(262)
-
(262)
(5,114)
-
(5,114)
(45)
-
(45)
(1,100)
-
(1,100)Dec. 31, 2009
868
939
1,807
5,106
4,270
9,376
24,223
12,438
36,660
281
147
428
6,037
3,870
9,907





Proved Undeveloped Reserves




The following table sets forth the volumes of proved undeveloped reserves that were first attributed for each of the Corporation'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(Mbbl)
(MMcf)
(Mbbl)Prior to December 31, 2007
-
3,415
3December 31, 2007
-
3,651
3December 31, 2008
13
4,287
3December 31, 2009
9
4,329
1





Proved undeveloped reserves are generally those reserves related to planned infill drilling locations.  The Corporation'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 Corporation'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(Mbbl)
(MMcf)
(Mbbl)Prior to December 31, 2007
646
13,087
111December 31, 2007
848
13,890
87December 31, 2008
892
18,080
155December 31, 2009
939
16,708
147













-29-


Probable undeveloped reserves relate to wells to be drilled, tied in and brought on-stream in future.  The Corporation's probable undeveloped reserves are forecasted to be developed during the following two years in accordance with the Corporation'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 ProbableYear
(M$)
(M$)2010
11,683
19,5802011
1,224
1,5362012
-
6042013
53
-2014
2
685Remaining Years
194
210Total for all years undiscounted
13,156
22,616





The Corporation 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 Corporation may consider farm-out arrangements for certain projects.  The Corporation does not expect that the cost of funding will make the development of a property uneconomic for the Corporation, nor is it expected that the cost of such funding will impact the Corporation's reserves or future net revenue.




Oil and Gas Wells




The following table sets forth the number and status of wells in which the Corporation has a working interest as at December 31, 2009.




Location
Light and Medium Crude Oil
Natural GasProducing
Non-Producing
Producing
Non-ProducingGross
Net
Gross
Net
Gross
Net
Gross
NetBritish Columbia
-
-
-
-
2
1.1
5
1.2Alberta
91
64.2
34
25
313
153
134
82.4Saskatchewan
-
-
1
1
-
-
6
6Trinidad and Tobago
-
-
-
-
-
-
3
0.75Total
91
64.2
35
26
315
154.1
148
90.4
















-30-




Properties With No Attributed Reserves




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




Location
Gross Acres
Net Acres
Net Acres Expiring

Within One YearBritish Columbia
30,124
9,268
-Alberta
156,124
116,343
24,349Saskatchewan
39,871
39,871
-Offshore Nova Scotia
27,790
27,790
27,790Offshore Trinidad and Tobago
80,980
20,245
-Offshore Tunisia
741,000
741,000
-Total
1,075,907
954,517
52,139




As at December 31, 2009, the estimated cost of the remaining work commitments on the 7th of November Block, Offshore Tunisia was approximately US$49 million gross to the Corporation. In Trinidad, BG currently holds US$20.0 million in escrow for Canadian Superior whereby the Corporation 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 Corporation within 30 days of the draw date.




Forward Contracts




The Corporation periodically enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility.  These financial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes.  The Corporation entered into the following financial instrument during the year ended December 31, 2009:




Product
Contract
Volume
Pricing Point
Price
TermNatural Gas
Fixed Price, Non-Physical
5000 GJ/d
AECO monthly
$5.50
Jan. 1, 2010 - Dec. 31, 2010





Additional Information Concerning Abandonment and Reclamation Costs




The Corporation 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 267 net wells under the proved reserves category is $7.8 million undiscounted ($3.5 million discounted at 10%), of which a total of $1.1 million undiscounted is estimated to be incurred in 2010, 2011 and 2012.  This estimate does not include expected reclamation for surface leases of $4.0 million undiscounted ($1.8 million discounted at 10%).




The Corporation will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the properties held by it upon abandonment.  Ongoing environmental obligations are expected to be funded out of cash flow.




Tax Horizon




Based on production from existing reserves, the Corporation estimates that it will not be required to pay income taxes in 2010 or 2011 and with continued exploration activity, the tax horizon could be pushed further.




Exploration and Drilling Activity




The following table summarizes the gross and net exploratory and development wells the Corporation has drilled, or has participated in for the year ended December 31, 2009.













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Gross
NetExploratory
Development
Exploratory
DevelopmentLight and Medium Crude Oil Wells
1
-
1
-Natural Gas Wells
6
-
4.9
-CBM Wells
-
-
-
-Dry Wells
6
-
5.5
-Service Wells(1)
-
-
-
-Total
13
-
11.4
-




Note:


(1)
A service well is 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 has, propane, butane, or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation or injection for combustion.




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
Light and Medium Crude Oil
Natural Gas
NGLs
Total Oil Equivalent(Mbbl)
(MMcf)
(Mbbl)
(MBOE)ProvedDrumheller
128
3,020
37
668Other
38
2,380
17
452Total
166
5,400
54
1,120ProbableDrumheller
8
107
1
27Other
17
600
4
121Total
25
707
5
148Total Proved Plus ProbableDrumheller
136
3,127
38
695Other
55
2,980
21
573Total
191
6,107
59
1,268





Production History




The following table sets forth, on a quarterly basis for the year ended December 31, 2009, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback.




Three Months EndedMarch 31,2009
June 30,2009
September 30,2009
December 31,2009Average Daily Production VolumeLight and Medium Oil and NGLs (bbl/d)
531
601
582
653Natural Gas (Mcf/d)
17,016
15,094
11,794
14,428Total (BOE/d)
3,367
3,117
2,548
3,058Average Prices ReceivedLight and Medium Oil and NGLs ($/bbl)
46.44
57.78
58.24
56.73Natural Gas ($/Mcf)
4.94
3.62
2.57
4.82Total ($/BOE)
32.31
28.67
25.23
34.87Royalties PaidLight and Medium Oil and NGLs ($/bbl)
8.68
5.14
10.99
9.56Natural Gas ($/Mcf)
0.69
0.21
(0.48)
(0.01)Total ($/BOE)
4.88
1.99
0.30
2.01Operating ExpensesLight and Medium Oil and NGLs ($/bbl)
13.93
20.18
15.15
15.89















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Three Months EndedMarch 31,2009
June 30,2009
September 30,2009
December 31,2009Natural Gas ($/Mcf)
1.82
2.41
1.51
1.72Total ($/BOE)
11.39
15.57
10.43
11.49Netback Received(1)Light and Medium Oil and NGLs ($/bbl)
23.83
32.46
32.10
31.28Natural Gas ($/Mcf)
2.43
1.00
1.54
3.11Total ($/BOE)
16.04
11.11
14.50
21.37




Note:


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




Production Volume by Field




The following table indicates the average daily production from each of the Corporation's important fields for the year ended December 31, 2009.




Field
Light and Medium Crude Oil
Natural Gas
NGLs
Total Oil Equivalent
%(bbl/d)
(Mcf/d)
(bbl/d)
(BOE/d)Drumheller
317
9,304
95
1,963
66.6Kaybob
70
1,290
20
305
10.3Peace River
43
2,910
30
558
18.9Cabin
-
739
-
123
4.2Total
430
14,243
145
2,949
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 Corporation's other public filings. In order to mitigate these risks, the Corporation has qualified technical and financial personnel, with experience in the areas of Canada, the United States, Trinidad and Tobago, Tunisia and Libya. Further, the Corporation has focused its foreign operations, and plans to target future foreign operations, in known and prospective hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies.  Additional risks and uncertainties not currently known to the management of the Corporation may also have an adverse effect on Canadian Superior's business and the information set out below does not purport to be an exhaustive summary of the risks affecting Canadian Superior.




Exploration, Development and Production Risks




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




Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but 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,












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and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. 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 Corporation 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 Corporation.  In accordance with industry practice, the Corporation is not fully insured against all of these risks, nor are all such risks insurable. Although the Corporation maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Corporation could incur significant costs that could have a material adverse effect upon its financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on the Corporation.




Operational Dependence




Other companies operate some of the assets in which the Corporation has an interest. As a result, the Corporation will have limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation’s financial performance. The Corporation’s return on assets operated by others will therefore depend upon a number of factors that may be outside of the Corporation’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 Corporation 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 Corporation’s ability to execute projects and market oil and natural gas will depend upon numerous factors beyond the Corporation’s control, including:




·
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;·
the availability of drilling and related equipment;·
unexpected cost increases;·
accidental events;·
currency fluctuations;·
changes in regulations;












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·
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 Corporation 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.




Substantial Capital Requirements




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




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 Corporation 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 Corporation, 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 Corporation, 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 Corporation's securities in particular.




Additional Funding Requirements




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




Issuance of Debt
  From time to time the Corporation may enter into transactions to acquire assets or the shares of other corporations.  These transactions may be financed partially or wholly with debt, which may increase the Corporation's debt levels above industry standards for oil and natural gas companies of similar size.  Depending on future exploration and development plans, the Corporation 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 Corporation nor its by-laws limit the amount of indebtedness that the Corporation may incur.  The level of the Corporation's indebtedness from time to time, could impair its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively effect the Corporation's debt ratings.  This in turn, could have a material adverse effect on the Corporation's business, financial condition, results of operations and cash flow.







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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 Corporation and may delay exploration and development activities. To the extent the Corporation is not the operator of its oil and gas properties, the Corporation will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.




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 Corporation is and will continue to be affected by numerous factors beyond its control. The Corporation’s ability to market its oil and natural gas may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. The Corporation may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.




The Corporation’s revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Corporation’s ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors include economic conditions, in the United States, Canada, Trinidad and Tobago, Tunisia, Libya, 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 Corporation’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 Corporation in part determined by the Corporation’s borrowing base. A sustained material decline in prices from historical average prices could reduce the Corporation’s borrowing base, therefore reducing the bank credit available to the Corporation which could require that a portion, or all, of the Corporation’s bank debt be repaid.




Insurance




The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although prior to conducting drilling and other field activities, the Corporation 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 Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.  The payment of such uninsured liabilities would reduce the funds available to the Corporation.  The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Corporation's financial position, results of operations or prospects. 
 Legal Proceedings
 
 The Corporation may from time to time be subject to litigation and regulatory proceedings arising in the normal course of its business.  The Corporation cannot determine whether such litigation and regulatory proceedings will,












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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 Corporation'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 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 Corporation to incur costs to remedy such discharge.  Although the Corporation 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 Corporation 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 Corporation 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 Corporation 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 Corporation 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, Tunisia and Libya 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 Corporation's international operations.  In addition, because Libya is a member of OPEC, any production obtained by the Corporation from Libya will be constrained by OPEC quotas. 
 Furthermore international oil and gas operations in Trinidad and Tobago, Tunisia and Libyainvolve 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 and the Untied States. As a result, drilling and development operations may take longer to complete and may cost more than similar operations in Canada and the United States. 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 and the United States.










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Foreign Legal Systems




Trinidad and Tobago, Tunisia and Libya have less developed legal systems than in Canada and the Untied States 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 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 Corporation's activities are transacted in or referenced to the currencies of the United States, Trinidad and Tobago, Tunisia and Libya. The Corporation'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 Corporation are located, could result in unanticipated fluctuations in the Corporation's financial results which are denominated in Canadian dollars. The Corporation does not manage its exposure to fluctuations in currency exchange rates.




Competition




The Corporation 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 Corporation.  The Corporation'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 Corporation'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 Corporation.




Certain of the Corporation's customers and potential customers are themselves exploring for oil and gas, and the results of such exploration efforts could affect the Corporation's ability to sell or supply oil or gas to these customers in the future.  The Corporation'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 Corporation's future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Corporation 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 Corporation's reserves will depend not only on the Corporation's ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects.  There can be no assurance that the Corporation's future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.












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Reliance on Industry Partners




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




Reliance on Key Employees




The Corporation's success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse affect on the Corporation. The Corporation does not have key person insurance in effect for management. The contributions of these individuals to the Corporation'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 Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the Corporation's management.




Permits, Licences and Approvals




The Corporation’s properties are held in the form of licences and leases and working interests in licences and leases. If the Corporation or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Corporation’s licences or leases or the working interests relating to a licence or lease may have a material adverse effect on 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 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 Corporation's claim which could result in a reduction of the revenue received by the Corporation.








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Multi-Jurisdictional Legal Risks




The Corporation is incorporated under the ABCA and all but four of the Corporation's directors and all of its officers are residents of Canada.  Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Corporation or upon those directors or officers who are not residents of the United States, or to realize in the United States upon judgments of United States courts predicated upon civil liabilities under the United States Securities Exchange Act of 1934.  Furthermore, it may be difficult for investors to enforce judgments of the U.S. courts based on civil liability provisions of the U.S. federal securities laws in a Canadian court against the Corporation or any of the Corporation's non-U.S. resident executive officers or directors.  There is substantial doubt whether an original lawsuit could be brought successfully in Canada against any of such persons or the Corporation predicated solely upon such civil liabilities.




Reserve Information




The reserve and recovery information contained in the GLJ Report are only estimates and the actual production and ultimate reserves from the Corporation'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 Corporation and substituted for the price assumptions utilized in the report, the present value of estimated future net cash flows for the Corporation'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 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 Corporation.




Dilutive Effect of Financings and Acquisitions




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




Dividends




The Corporation 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 Corporation, the need for funds to finance ongoing operations and other business considerations as the Board considers relevant.




Third Party Credit Risk




The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Corporation, such failures could have a material adverse effect on the Corporation 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 Corporation’s ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a suitable alternative partner. 
 Failure to Realize Anticipated Benefits of Acquisitions and Dispositions
 
 The Corporation makes acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Corporation’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. 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 Corporation can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-












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core assets of the Corporation, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Corporation.




Hedging




From time to time the Corporation may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Corporation will not benefit from such increases and the Corporation 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 Corporation may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Corporation 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 Corporation is unable to assess what, if any, impact such claims will have on the business and operations that it conducts in Western Canada.




Conflict of Interest




Certain of the directors and officers of the Corporation are also directors and officers of other oil and gas companies involved in natural resource exploration and development, and conflicts of interest may arise between their duties as officers and directors of the Corporation 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 Corporation's operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Corporation is 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 Canadian Superior 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 Government of Canada has originally indicated an intention to regulate the emissions of industrial GHG emissions from a range of industries in the Framework, which Framework was updated on March 10, 2008 pursuant to the Update.  The Federal Plan (which is comprised of the Framework, as amended by the Update) outlines a number of policies to reduce GHG emissions intensity of regulated facilities starting in 2010.  Under the Federal Plan, existing facilities are to be subject to mandatory GHG emission reductions of 18% from the 2006 baseline starting in 2010 with an additional 2% reduction for each subsequent year; new facilities (which are defined as those facilities whose first year of operation is 2004 or later) will 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.  For the upstream oil and gas industry, the Federal Plan also provides for a company threshold of 10,000 BOE/d and a facility threshold of 3,000 tonnes of carbon dioxide. 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








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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.  Draft regulations adopting the Federal Plan were expected to be available for public comment in the fall of 2008 but have not yet been released, and it is not known whether such regulations will be released or implemented.




The Government of Canada is also working with the provinces and territories to develop a cap and trade system which is to ultimately be aligned with the emerging cap and trade system being developed by the United States.  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 will 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.




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.




In December 2009, Canada participated in COP 15 in Denmark, the goal of which was to reach a new agreement for fighting global climate change.  COP 15 resulted in the Copenhagen Accord, which committed Canada and the other participating countries to implement the quantified economy-wide emissions targets by 2020.  Canada submitted its targets on January 30, 2010, noting that: (a) the emissions reduction target it set of 17% for the baseline year of 2005 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 the Copenhagen Accord.




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




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 in the Climate Change and Emissions Management Act(Alberta) came into effect on July 1, 2007. Under this legislation, Alberta facilities emitting more than 50,000 tonnes of GHG emissions per year must report such emission 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%.  Companies have four options to choose from in order to meet the reduction requirements outlined in this legislation, and these are:  (i) making improvement to operations that result in reductions; (ii) purchasing emission credits from other sectors or facilities that have reduced their emissions below the required emission intensity reduction levels; (iii) 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 (iv) contributing to the 'Climate Change and Emissions Management Fund'.  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. 
 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.












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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 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; (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 fuels such as gasoline, diesel, natural gas, propane and coal, and it is revenue-neutral, meaning tax revenues will be returned to taxpayers through reductions in other provincial taxes.




On April 3, 2008, the Government of British Columbia  introduced the Greenhouse Gas Reduction (Cap and Trade) Act, which will allow participation in the Western Climate Initiative cap and trade systems being developed. The proposed system establishes a limit on GHG emissions, and allows regulated emitters to buy/sell GHG emission allowances or offset emits. The emitter is obliged to obtain GHG emission allowances (compliance units) which are equal to the amount of GHG emissions release within a certain period of time, which are then to be surrendered to the Government of British Columbia as proof of compliance.




DIVIDENDS




The Corporation 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 Corporation'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 Corporation and such other factors as the Board considers appropriate.




Dividends of US$375,000, US$nil and US$187,500 per Series A Preferred Share were paid by the Corporation in each of the years ended December 31, 2007, 2008 and 2009, respectively, to West Coast.




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




DESCRIPTION OF SHARE CAPITAL




The Corporation'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, 197,057,498 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 Corporation dated February 4, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein. 
 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 Canadian Superior 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












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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 Corporation 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 and restricted to the 150 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 Corporation 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.




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 and restricted to the 150 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 Corporation 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 B Preferred Share is convertible into 167 Common Shares at a price of US$0.60 per Common Share. The Series B Preferred Shares are redeemable and retractable five years from the date of issue, subject to earlier redemption or retraction in certain events.  The Corporation can force the conversion of the Series B Preferred Shares at anytime 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 Corporation 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 January 22, 2011 unless re-approved by the Shareholders at the 2010 annual and special meeting of Shareholders.




The primary objective of the Rights Plan is to: (i) provide Shareholders adequate time to properly assess the merits of a take-over bid for the Common Shares without undue pressure; (ii) allow competing bids to emerge; and (iii) give the Board time to consider alternatives to enable Shareholders to maximize the value of their Common Shares.  The Rights Plan is designed to encourage a potential acquirer to proceed either by way of a take-over bid specifically permitted by the Rights Plan (a "Permitted Bid") or with the approval of the Board.
  Under the Rights Plan, one right (a "Right") is attached to each Common Share.  The Rights will separate from the Common Shares and become exercisable eight trading days (the "Separation Time") after a person acquires, or commences a take-over bid to acquire, 20% or more of the voting shares or other securities convertible into voting shares of the Corporation, unless the Separation Time is deferred.  The acquisition by any person (an "Acquiring Person") of 20% or more of the Common Shares, other than in a permitted manner, is called a "Flip-in Event". Any Rights held by an Acquiring Person will become void upon the occurrence of a Flip-In Event.
  After the Separation Time, each Right will permit the holder (other than an Acquiring Person) to purchase from the Corporation to purchase a Common Share for the then determined exercise price.   The result will be a dilution of the holdings of the Acquiring Person.  The Corporation anticipates that no Acquiring Person will be willing to risk such dilution and so will instead either make a take-over bid that is permitted by the Rights Plan, negotiate with the








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Board for a waiver of the Rights Plan, or apply to regulatory authorities for an order rendering the Rights Plan ineffective.




A person will not become an Acquiring Person, and will not trigger the separation and ability to exercise the Rights, by becoming the beneficial owner of 20% or more of the Common Shares pursuant to a Permitted Bid or in other circumstances provided for under the Rights Plan.  Investment advisors (for fully managed accounts), trust companies (acting in their capacities as trustees and administrators) and statutory bodies acquiring 20% of the Common Shares are exempted from triggering a Flip-In Event, provided that they are not making, and are not part of a group making, a take-over bid.




The issue of the Rights is not initially dilutive.  However, upon a Flip-In Event occurring and the Rights separating from the Common Shares, reported earnings per share on a fully diluted or non-diluted basis may be affected.  Holders of Rights who do not (or, in the case of an Acquiring Person, cannot) exercise their Rights upon the occurrence of a Flip-In Event will suffer substantial dilution.




This summary is qualified in its entirety by reference to the Rights Plan Agreement, a copy of which is available on SEDAR at www.sedar.com.




MARKET FOR SECURITIES




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




2009
High

($)
Low

($)
Close

($)
VolumeJanuary
1.46
1.15
1.18
1,019,400February
1.25
0.35
0.46
6,257,200March
0.66
0.23
0.59
11,673,500April
0.97
0.51
0.84
9,261,100May
0.87
0.71
0.80
3,845,300June
0.96
0.76
0.78
4,214,700July
0.80
0.62
0.75
1,501,300August
0.89
0.66
0.66
1,791,700September
1.19
0.66
0.93
5,486,800October
0.91
0.65
0.66
4,331,100November
0.69
0.56
0.60
2,808,600December
0.73
0.50
0.64
3,294,500





PRIOR SALES
  During the year ended December 31, 2009, a total of 4,458,000 Options, being the only unlisted securities of the Corporation that were issued, were granted are as follows:
  Date of Grant
Number of Options
Exercise PriceNovember 11, 2009
4,458,000
$0.64
  ESCROWED SECURITIES
  To the knowledge of management of the Corporation, none of its securities are subject to escrow conditions or contractual restrictions on transfer.







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DIRECTORS AND OFFICERS




Directors and Officers




The following sets forth the residence of the directors and executive officers of the Corporation, their offices or positions with the Corporation, their principal occupations during the past five years and the period during which each director has served as a director.  The term of the directors' office expires at the next annual meeting of Shareholders.




Name and Residence
Office or Position
Director Since
Principal Occupation During the Last Five YearsMarvin M. Chronister(1)(2)(4)(5)(6)

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.Dr. James Funk(3)(5)

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)(4)

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. R. William Roach(4)(5)(6)(7)

Calgary, Alberta
Director
September 2009
From October 2004 to present, President and Chief Executive Officer of UTS Energy Inc., a public oil and gas company.Gregory G. Turnbull(1)(3)(6)

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)(5)

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.


Robb D. Thompson

Alberta, Canada
Chief Financial Officer
Not applicable
From February 2008 to present, Chief Financial Officer of the Corporation.  Prior thereto, from January 2007 to January 2008, Chief Financial Officer of Berkana Energy Inc., a public oil and gas company.  Prior thereto, from September 2000 to December 2007, Chief Executive Officer of Dynetek Industries Ltd., a public alternative energy company.Richard Watkins(2)(4)(6)(7)

Texas, United States
Director
May 2006
From June 2006 to present, Managing Director of Energy Advisors LLC, an energy consulting firm.Leif Snethun

Alberta, Canada
Chief Operating Officer
Not applicable
From April 2009 to present, Chief Operating Officer of the Corporation.  Prior thereto, from February 2008 to April 2009, Vice President of Western Canada for the Corporation.  Prior, thereto, from April 2003 to March 2008, founder, President and Chief Executive Officer of Seeker.
  Notes:
 (1)
Member of the Audit Committee.
 (2)
Member of the Compensation Committee.
 (3)
Member of the Corporate Governance Committee.
 (4)
Member of the Management Committee.
 (5)
Member of the Reserves Committee.
 (6)
Member of the CEO Selection Committee.
 (7)
Member of the Liberty Project Committee.













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As at December 31, 2009, the directors and executive officers of the Corporation, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 236,279 Common Shares representing less than one percentof the issued and outstanding Common Shares.




Corporate Cease Trade Orders or Bankruptcies




To the knowledge of management, no director or executive officer of Canadian Superior is, or has been, within the past 10 years before the date hereof, a director or executive officer of any issuer that, while that person was acting in that capacity: (i) was the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days; or (ii) was subject to an event that resulted, after the person ceased to be a director or executive officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days, other than:




·
Mr. Riddell was a director and executive officer of Paramount Resources Ltd., the general partner of T.T.Y. Paramount Partnership No. 5, a limited partnership engaged in oil and gas exploration and development activities. A cease trade order against T.T.Y. Paramount Partnership No. 5 was issued by the Quebec Securities Commission in 1999 for failing to file its June 30, 1998 financial statements in Quebec. The cease trade order was revoked on April 9, 2008. T.T.Y. Paramount Partnership No. 5 was dissolved on July 21, 2008.


To the knowledge of management, no director, executive officer of Canadian Superior or controlling Shareholder is, or has been, within the past 10 years before the date hereof, a director or executive officer of any  issuer that, while that person was acting in that capacity or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than:




·
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. Watkins was a director of Canadian Superior and Messrs. Thompson and Snethun were executive officers of Canadian Superior upon the commencement of the CCAA Proceedings.  For more information with respect to the CCAA Proceedings, see "Description of the Business - Bankruptcy and Similar Procedures" and the Information Circular of the Corporation dated August 12, 2009, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein;·
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.
 Personal Bankruptcies
  To the knowledge of management, no director, executive officer of Canadian Superior or controlling Shareholder has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person's assets.













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Penalties or Sanctions




To the knowledge of management, no director, executive officer of Canadian Superior or controlling Shareholder has: (i) been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or (ii) been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.




Conflicts of Interest




Certain of the directors and officers of the Corporation are directors and/or officers of other private and public companies.  Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise.  Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the ABCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of the Corporation.




AUDIT COMMITTEE




Composition of the Audit Committee




The Audit Committee operates under written charter that sets out its responsibilities and composition requirements.  A copy of the charter is attached to this Annual Information Form as Appendix "C".  The Audit Committee consists of Messrs. Chronister (Chair), Brittain and Turnbull.  All members of the Audit Committee are independent and financially literate (as determined by National Instrument 52-110, Audit Committees).




In considering criteria for the determination of financial literacy, the Board looked at the ability to read and understand a balance sheet, an income statement and cash flow statement of a public company as well as the director's past experience in reviewing or overseeing the preparation of financial statements.  The following sets out the education and experience of each director relevant to the performance of his duties as a member of the Audit Committee.




Marvin M. Chronister
  Marvin Chronister is an energy finance and operational consultant and has over 30 years experience in the oil and gas industry. Mr. Chronister holds a Bachelor of Business Administration degree.  For more information with respect to Mr. Chronister's principal occupations during the past five years, see "Directors and Officers".
  Kerry Brittain
  Kerry Brittain is currently in private law practice advising companies on acquisitions and domestic and international transactions and has over 35 years experience in the oil and gas industry.  Mr. Brittain holds a Bachelor of Arts degree and a Juris Doctor degree.  For more information with respect to Mr. Brittain's principal occupations during the past five years, see "Directors and Officers".
  Gregory G. Turnbull
  Gregory Turnbull is a partner of McCarthy Tétrault llp and has over 30 years experience in the oil and gas industry.  Mr. Turnbull currently also serves as a director of Crescent Point Energy Corp., Storm Exploration Inc., Heritage Oil Plc, Canadian Superior Energy Inc., Sunshine Oilsands Ltd., BNP Resources Inc. and Hawk Exploration Ltd.  Mr. Turnbull holds a Bachelor of Arts (Honours) degree and a Bachelor of Laws degree and was called to the Alberta bar in 1980.  For more information with respect to Mr. Turnbull's principal occupations during the past five years, see "Directors and Officers".








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Auditors' Fees




Deloitte & Touche llp, Chartered Accountants, became the Corporation's auditors on December 1, 2009 in order to fill the vacancy created by the resignation of Meyers Norris Penny llp, Chartered Accountants.  Meyers Norris Penny llp had served as the Corporation's auditors since 2005 and resigned at the request of the Corporation.  Fees paid to the Corporation's auditors for the years ended December 31, 2009 and 2008 are detailed below.




Fee
For the year ended December 31,2009
For the year ended December 31,2008Audit Fees
$296,462
$216,725Audit-Related Fees(1)
$117,170
$65,850Tax Fees(2)
$2,756
$15,330Other Fees(3)
$37,254
$96,342Total
$453,542
$394,247




Notes:


(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.





All permissible categories of non-audit services to be provided by the external auditor must be pre-approved by the Audit Committee subject to certain statutory exceptions.




LEGAL AND REGULATORY PROCEEDINGS




Except as disclosed herein and in the Information Circular of the Corporation dated August 12, 2009, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein, Canadian Superior is not a party to any legal proceeding nor was it a party to, nor is or was any of its property the subject of any legal proceeding, during the year ended December 31, 2009, nor is management of the Corporation aware of any such contemplated legal proceedings, which involve a claim for damages, exclusive of interest and costs, that may exceed 10% of the current assets of Canadian Superior.




During the year ended December 31, 2009, there were no: (i) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision; or (iii) settlement agreements the Corporation entered into before a court relating to securities legislation or with a securities regulatory authority.


On December 14, 2009, the Corporation announced that it had been notified of a class action lawsuit commenced in the United States District Court for the Southern District of New York against certain former executive officers and a current executive officer of Canadian Superior for allegedly violating the United States Securities Exchange Act of 1934 with respect to disclosed information concerning its prospects in Trinidad and Tobago.  Canadian Superior has not been named a defendant in the case.  The class action lawsuit purports to be brought on behalf of purchasers of Common Shares from January 14, 2008 to February 17, 2009.  The defendants may seek indemnification from the Corporation for the expenses and costs of the lawsuit and in respect of any damages that may be awarded to the plaintiffs.  In such event, the Corporation will assess its indemnification obligations, if any, in respect of the amounts claimed.  The Corporation carries director and officer liability insurance which may  limit the indemnification obligations, if any, of the Corporation.
  INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
  Except as disclosed herein and in the Information Circulars of the Corporation dated August 12, 2009, May 15, 2008 and March 27, 2007, copies of which are available on SEDAR at www.sedar.com and are incorporated by reference herein, no director or executive officer of the Corporation, or any person or company that is the beneficial owner of, or who exercises control or direction of, more than 10% of the Common Shares or any associate or affiliate of any of the foregoing persons has had any material interest, direct or indirect, in any transaction in the three most recently










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completed financial years or during the current financial year that has materially affected or will materially affect Canadian Superior.




TRANSFER AGENT AND REGISTRAR




Valiant Trust Company at 310, 606 - 4th Street S.W., Calgary, Alberta, T2P 1T1, is the transfer agent and registrar for the Common Shares.




MATERIAL CONTRACTS




Except for contracts entered into in the ordinary course of business, the Corporation has not entered into any material contracts within the most recently completed financial year, or before the most recently completed financial year that are still in effect, other than:




·
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".


INTERESTS OF EXPERTS




Reserve estimates contained in this Annual Information Form have been prepared by GLJ.  As at December 31, 2009, the effective date of those estimates, and as of the date hereof, the principals, directors, officers and associates of GLJ, as a group, owned, directly or indirectly, less than one percent of the outstanding Common Shares.




Deloitte & Touche llp is the external auditor of the Corporation and is independent within the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.




ADDITIONAL INFORMATION




Additional information, including information as to directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans, if applicable, is contained in the Information Circular of the Corporation prepared in connection with the most recent annual meeting of Shareholder that involved the election of directors.  Additional financial information is provided in the Corporation's financial statements and management discussion and analysis for the year ended December 31, 2009, which are contained in the Annual Report of the Corporation for the year ended December 31, 2009.















APPENDIX"A"




REPORT ON RESERVES DATA BY




INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR




Terms to which a meaning is ascribed in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities have the same meaning herein.




To the Board of Directors of Canadian Superior Energy Inc. (the "Corporation"):




1.
We have evaluated the Corporation's reserves data as at December 31, 2009.  The reserves data are estimates of proved and probable reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.2.
The reserves data are the responsibility of the Corporation'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 Corporation evaluated by us for the year ended December 31, 2009, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Corporation's management and Board of Directors.







Independent Qualified Reserves Evaluator or Auditor
Description and Preparation Date of Evaluation Report
Location of Reserves (Country)
Net Present Value of Future Net Revenue

(10% discount rate)Audited (M$)
Evaluated (M$)
Reviewed (M$)
Total (M$)GLJ Petroleum Consultants Ltd.
March 18, 2010
Canada
Nil
157,476
Nil
157,476





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


Executed as to our report referred to above:




GLJ Petroleum Consultants Ltd.



(signed) "John H. Stilling"John H. Stilling, P. Eng.

Vice PresidentDated March 26, 2010














APPENDIX"B"




REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE




Terms to which a meaning is ascribed in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities have the same meaning herein.




Management of Canadian Superior Energy Inc. (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements.  This information includes reserves data which are estimates of proved and probable reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.




Independent qualified reserves evaluator has evaluated and reviewed the Corporations reserves data.  The report of the independent qualified reserves evaluator is presented in Appendix "A" to the Annual Information Form of the Corporation, effective as at December 31, 2009.




The Reserves Committee of the Board of Directors of the Corporation has:




(a)
reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;(b)
met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and(c)
reviewed the reserves data with management and the independent qualified reserves evaluator.


The Reserves Committee of the Board of Directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management.  The Board of Directors has, on the recommendation of the Reserves Committee approved:




(a)
the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;(b)
the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and(c)
the content and filing of this report.


Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.  However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.







(signed) "Leif Snethun"

(signed) "Robb D. Thompson"Leif Snethun

Robb D. ThompsonChief Operating Officer

Chief Financial Officer(signed) "Marvin M. Chronister"

(signed) "James M. Funk"Marvin M. Chronister

James M. FunkDirector

DirectorDated March 30, 2010














APPENDIX"C"




CHARTER OF THE AUDIT COMMITTEE OF THE


CANADIAN SUPERIOR ENERGY INC.




Purpose/Objectives




The Audit Committee is appointed by the Board to assist the Board in fulfilling its oversight responsibilities, including:




1.
the integrity of the Corporation's financial statements;2.
the integrity of the financial reporting process;3.
the system of internal control and management of financial risks the external auditors' qualifications and independence; and4.
the external audit process and the Corporation's process for monitoring compliance with laws and regulations.


In performing its duties, the Committee will maintain effective working relationships with the Board, management and the external auditors.  To perform his or her role effectively, each Committee member will obtain an understanding of the Corporation's business, operations, risks and related legislation, regulations and industry standards.  So that the Audit Committee can discharge the duties as a whole, all Audit Committee members must be financially literate, and at least one member must have significant accounting or related financial management experience.




Authority




The Board authorizes the Committee, within its scope of duties and responsibilities, to:




1.
seek any information it requires from any employee of the Corporation (whose employees are directed to cooperate with any request made by the Committee);2.
seek any information it requires directly from external parties including the external auditors and independent reservoir engineering firm; and3.
obtain outside legal or professional advice without seeking Board approval (however providing notice to the Chair of the Board).


Organization




The following provisions and regulations shall apply to the composition of the Committee:




1.
the Committee shall consist of three members of the Board of the Corporation;2.
the members of the Committee shall be independent members of the Board as defined in section 1.4 of Multilateral Instrument 52-110 Audit Committees, as well as Part 1, section 121(A) of the AMEX Company manual;3.
the Chairman of the Committee shall be determined by the Board;4.
two members of the Committee shall constitute a quorum thereof;5.
no business shall be transacted by the Committee except at a meeting of its members at which a quorum is present in person or by telephone or by a resolution in writing signed by all members of the Committee;





















6.
the meetings and proceedings of the Corporation that regulate meetings and proceedings of the Board shall apply to the Committee;7.
the Committee may invite such directors, officers or employees of the Corporation, the external auditors and the independent reservoir engineering firm as it may see fit, to attend its meetings and take part in the discussion and consideration of the affairs of the Committee; and8.
meetings shall be held not less than four times per year, generally coinciding with the release of interim or year-end financial information including consecutive sessions with Management and the External Auditors.


Special meetings may be convened as required upon the request of the Committee.  The external auditors and independent reservoir engineering firm may convene a meeting if they consider that it is desirable or necessary; and the proceedings of all meetings will be minuted.




Duties and Responsibilities




The Board hereby delegates and authorizes the Committee to carry out the following duties and responsibilities to the extent that these activities are not carried out by the Board as a whole:




Corporate Information and Internal Control




1.
review and recommend for approval of quarterly and annual financial statements, MD&A and annual reports of the Corporation;2.
review of internal control systems maintained by the Corporation;3.
review of significant accounting and tax compliance issues where there is choice among various alternatives or where application of a policy has a significant effect on the financial results of the Corporation;4.
review of significant proposed non-recurring events such as mergers, acquisitions or divestitures; and5.
review of press releases or other publicly circulated documents containing financial information.


External Auditors




1.
retain and/or terminate the external auditors (subject to regulatory and shareholder notification) who, in turn, will report directly to the Audit Committee;2.
review the terms of the external auditors' engagement and the appropriateness and reasonableness of the proposed engagement fees;3.
annually, obtain and review a certificate attesting to the external auditors' independence, identifying all relationships between the external auditors and the Corporation;4.
annually, evaluate the external auditors' qualifications, performance and independence;5.
annually, to assure continuing auditors' independence, consider the rotation of the lead audit partner or the external audit firm;6.
pre-approve engagements for non-audit services provided by the external auditors or their affiliates together with estimated fees and potential issues of independence; and7.
review hiring policies for employees or former employees of the external auditors.
















Audit




1.
review the audit plan for the coming year with the external auditors and with management;2.
review with management and the external auditors any proposed changes in major accounting policies, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material to financial reporting;3.
query management and the external auditors regarding significant financial reporting issues during the fiscal period and the method of resolution;4.
review any problems experienced by the external auditors in performing the audit, including any restrictions imposed by management of significant accounting issues in which there was a disagreement with management;5.
review audited annual financial statements and quarterly financial statements with management and the external auditors (including disclosures under "Management Discussion and Analysis"), in6.
conjunction with the report of the external auditors and obtain explanation from management of all significant variances between comparative reporting periods; and7.
review the auditors' report to management, containing recommendations of the external auditors, and management's response and subsequent remedy of any identified weaknesses.


Other Duties and Responsibilities




1.
The responsibilities, practices and duties of the Committee outlined herein are not intended to be comprehensive.  The Board may, from time to time charge the Committee with the responsibility of reviewing items of a financial or control, risk management or reserves nature.2.
The Committee shall periodically report to the Board the results of reviews undertaken and any associated recommendations.3.
The Committee shall monitor the receipt, retention and treatment of complaints received by the issuer regarding accounting, internal accounting controls, or auditing matters.4.
The Committee shall monitor the confidential, anonymous submissions by employees of concerns regarding questionable accounting or auditing matters.