40-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 40-F

(Check One)

o REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

x ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007 Commission File Number: 001-31395

CANADIAN SUPERIOR ENERGY INC.

(Exact name of Registrant as specified in its charter)

Alberta	1311	Not Applicable
(Province or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code (if applicable))	(I.R.S. Employer Identification Number (if applicable))

Suite 2700, 605 5th Avenue SW

Calgary, Alberta, Canada  T2P 3H5

(403) 294-1411

(Address and telephone number of Registrant’s principal executive offices)

PTSGE Corp.

Attn:  Gary Kocher

925 Fourth Avenue, Suite 2900

Seattle, Washington 98104

(206) 623-7580

(Name, address (including zip code) and telephone number

(including area code) of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title	Name of Each Exchange on Which Quoted
Common Shares	American Stock Exchange Toronto Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act.  None.

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.  None.

For annual reports, indicate by check mark the information filed with this Form:

x  Annual information form x  Audited annual financial statements

Indicate number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

The Registrant had 140,312,273 common shares outstanding as of December 31, 2007

Indicate by check mark whether the Registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”).  If “Yes” is marked, indicate the file number assigned to the Registrant in connection with such Rule.

Yes  oNo  x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes  xNo  o

TABLE OF CONTENTS

	Page
Principal Documents	1
Disclosure Controls and Procedures	1
Internal Control Over Financial Reporting	1
Remediation Effort	2
Audit Committee Financial Expert	2
Code of Ethics	3
Principal Accountant Fees and Services	3
Pre-Approval Policies	3
Off-Balance Sheet Arrangements	3
Disclosure of Contractual Obligations	4
Audit Committee	4
Undertaking	4
Consent to Service of Process	4

Except where otherwise indicated, all dollar amounts stated in this Annual Report on Form 40-F are Canadian dollars.

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F:

A.Annual Information Form

For our Annual Information Form for the twelve-month period ended December 31, 2007, see Exhibit 99.1 to this Annual Report on Form 40-F.

B.Audited Annual Financial Statements

For our Consolidated Audited Financial Statements for the twelve-month period ended December 31, 2007, including the report of independent registered public accounting firm with respect thereto, see Exhibit 99.2 to this Annual Report on Form 40-F.  For a reconciliation of important differences between Canadian and United States generally accepted accounting principles, see Note 19 of the Notes to the Consolidated Financial Statements.

C.Management’s Discussion and Analysis

For Management’s Discussion and Analysis for the twelve-month period ended December 31, 2007, see Exhibit 99.3 to this Annual Report on Form 40-F.

Disclosure Controls and Procedures

In accordance with the Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of December 31, 2007. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that, because of material weaknesses described below in “Internal Control over Financial Reporting”, our disclosure and procedures were not effective as of December 31, 2007.

Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting and designing such internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP), including a reconciliation to U.S. GAAP. Our management, including the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, our management concluded that our internal control over financial reporting was not effective as December 31, 2007 due to the material weaknesses described below. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

During the fourth quarter of 2007 a new CEO was hired along with a new CFO and finance and accounting team in the first quarter of 2008. Although material deficiencies existed at December 31, 2007, the Corporation has taken significant steps in Q1 2008 to alleviate in the near term some of the noted material weaknesses, such as segregation of duties and financial preparation and review procedures and has implemented an aggressive plan that by the end of 2008 all noted material weaknesses at December 31 will be substantially eliminated.

Management’s assessment identified the following material weaknesses in internal control over financial reporting as of December 31, 2007:

·There are no effective controls or procedures related to significant accounts or processes to provide reasonable assurance that transactions are recorded accurately, are recorded timely and are complete;

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·The Corporation was not adequately staffed with accounting personnel possessing an adequate level of technical expertise and did not maintain effective segregation of duties over automated and manual transactions leading to ineffective monitoring, supervision and reviews.

·The Corporation did not maintain effective controls over the safeguarding of monetary assets. The material weakness affects cash and short-term investments.

Meyers Norris Penny LLP, the independent registered public accounting firm that audited our consolidated financial statements has issued an attestation report on our internal control over the financial reporting. For Meyers Norris Penny LLP’s report, see Exhibit 99.5 to this Annual Report on Form 40-F.

Remediation Effort

Our management completed its assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007, and in performing its assessment, identified the material weaknesses described above. These material weaknesses have been discussed with the Audit Committee. The Audit Committee has taken an active role in overseeing management’s implementation of the remedial measures described below. By implementing these remedial measures, management intends to improve our internal control over financial reporting and to avoid material misstatements in consolidated financial statements prepared for external purposes, in the future. Our management is working under the supervision of the Audit Committee to identify and implement additional corrective actions, where required, to improve the effectiveness of our internal control over financial reporting, including the enhancement of systems and procedures.

We have implemented or are implementing the following measures, which will improve significantly our internal control over financial reporting:

·The hiring of a new CFO and Corporate Controller and key additional operational accounting and financial reporting staff of which a number are Chartered Accountants with Canadian and US financial and regulatory reporting experience;

·The implementation of regular management meetings to provide operational, financial, and accounting updates of the Corporation;

·A budgeting process which will compare actual results to budgeted results for management to review and query on a monthly basis;

·The implementation of controls to safeguard monetary assets; and

·The initiation of an ongoing and comprehensive review of financial controls and procedures to address the issues identified above and to bring into compliance with the requirements of the Sarbanes-Oxley Act with respect to internal controls and procedures.

Management believes that, through implementation of the measures noted above, we will begin to address the conditions identified above as material weaknesses. We will monitor the effectiveness of these measures, and our internal control over financial reporting on an ongoing basis. We will continue to asses our remediation plans and will take further action, as appropriate, to strengthen our internal control over financial reporting.

Audit Committee Financial Expert

Our Board of Directors has determined that Mr. Squires is an audit committee financial expert serving on our audit committee (as defined in paragraph 8(b) of General Instruction B to Form 40-F).  Our Board of Directors has determined that Mr. Squires is independent pursuant to the standards of the American Stock Exchange.  For a description Mr. Squires’ relevant experience in financial matters, see his employment history in the section “Directors and Officers” in our Annual Information Form for the year ended December 31, 2007, which is filed as Exhibit 99.1 to this Annual Report on Form 40-F.

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Code of Ethics

Our code of ethics applicable to our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions is disclosed in our Code of Business Conduct and Ethics, which is applicable to all of our directors, officers and employees. Our Code of Business Conduct and Ethics is filed as Exhibit 99.4 to this Annual Report on Form 40-F. In the event that we:

(i)amend any provision of our Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F, or

(ii)grant a waiver, including an implicit waiver, from a provision of our Code of Business Conduct and Ethics to any of our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition as enumerated in paragraph (9)(b) of General Instruction B to Form 40-F,

then we will disclose in a Form 6-K any such amendment or waiver. Such disclosure will specifically describe the nature of the amendment or waiver, and will, in the case of a waiver, name the person to whom the waiver was granted.

Principal Accountant Fees and Services

The following table provides information about the fees billed to us for professional services rendered by Meyers Norris Penny LLP, our principal accountant during fiscal years 2007 and 2006:

	2007		2006
Audit fees	$	201,798	$	141,820
Audit-related fees	52,115		35,490
Tax fees	7,420		6,400
All other fees	50,032		44,245
Total fees	$	311,365	$	227,955

Audit Fees.  Audit fees consist of fees for the audit of our annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees.  Audit-related fees included fees relating to the review of our quarterly financial statements.

Tax Fees.  Tax fees included tax compliance, tax planning, tax advice and various taxation matters.

All Other Fees.  All other fees consists of services provided by our principal accountant other than audit, audit-related and tax services, including prospectus and other offering related work.

Pre-Approval Policies

All audit and non-audit services performed by our auditors for the 2007 and 2006 fiscal years were pre-approved by our audit committee.  It is our policy that all audit and non-audit services performed by our auditors will continue to be pre-approved by our audit committee.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements to report.

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Disclosure of Contractual Obligations

In the normal course of business we are obligated to make future payments.  These obligations represent contracts and other commitments that are known and committed.

	Payment Due by Period
	Total		Less than 1 year		1 – 3 years		3 – 5 years	More than 5 years
Long-term debt obligations	—		—		—		—	—
Capital (finance) lease obligations	—		—		—		—	—
Operating lease obligations	$	1,122,543	$	471,166	$	651,377	—	—
Purchase obligations	—		—		—		—	—
Other long-term liabilities reflected on the Company’s balance sheet under the GAAP of the primary financial statements	—		—		—		—	—
Total	$	1,122,543	$	471,166	$	651,377	—	—

Audit Committee

We have established an audit committee in accordance with section 15 U.S.C. 78c(a)(58)(A). Each of the following directors serves on the audit committee: Mssrs. Squires, Watkins and Dallas.  See the section entitled “Audit Committee” in our Annual Information Form for the year ended December 31, 2007, which is filed as Exhibit 99.1 to this Annual Report on Form 40-F.

Undertaking

We undertake to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when required to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an Annual Report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

We have previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this Annual Report on Form 40-F arises.  Any change to the name and address of the agent for service for service of process shall be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X.

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SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized.

CANADIAN SUPERIOR ENERGY INC.
By:	/s/  CRAIG MCKENZIE
Name:	Craig McKenzie
Title:	Chief Executive Officer
Date:	March 30, 2008

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EXHIBITS

Exhibit	Description
99.1	Annual Information Form of the Registrant for the twelve-month period ended December 31, 2007.
99.2	Consolidated Audited Financial Statements of the Registrant for the twelve-month period ended December 31, 2007, including Auditors’ Report to the Shareholders.
99.3	Management’s Discussion and Analysis of the Registrant for the twelve-month period ended December 31, 2007.
99.4	Code of Ethics.
99.5	Report of Meyers Norris Penny LLP on Internal Control over Financial Reporting.
99.6	Consent of Meyers Norris Penny LLP.
99.7	Consent of GLJ Petroleum Consultants Ltd.
99.8	Certifications of Chief Executive Officer pursuant to Rule 13a-14(a).
99.9	Certifications of Chief Financial Officer pursuant to Rule 13a-14(a).
99.10	Certifications of Chief Executive Officer pursuant to Rule 13a-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99.11	Certifications of Chief Financial Officer pursuant to Rule 13a-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).

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EX-99.1

Exhibit 99.1

ANNUAL INFORMATION FORM

(Except as otherwise noted the

information herein is given

as at December 31, 2007)

Dated:  March 30, 2008

TABLE OF CONTENTS

ABBREVIATIONS	1
CONVERSIONS	1
CERTAIN DEFINITIONS	2
GLOSSARY OF TECHNICAL TERMS	3
CURRENCY OF INFORMATION	6
FORWARD LOOKING STATEMENTS	6
THE CORPORATION	7
GENERAL DEVELOPMENT OF THE BUSINESS	8
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	15
INDUSTRY CONDITIONS	28
RISK FACTORS	35
DIVIDENDS	41
DESCRIPTION OF CAPITAL STRUCTURE	41
MARKET FOR SECURITIES	43
DIRECTORS AND OFFICERS	43
LEGAL PROCEEDINGS	45
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	46
TRANSFER AGENT AND REGISTRAR	46
INTERESTS OF EXPERTS	46
AUDIT COMMITTEE	47
ADDITIONAL INFORMATION	48

ABBREVIATIONS

Oil and Natural Gas Liquids
Bbl	Barrel
Bbls	Barrels
Mbbls	thousand barrels
MMbbls	million barrels
Mstb	1,000 stock tank barrels
bbls/d	barrels per day
bopd	barrels of oil per day
NGLs	natural gas liquids
STB	standard tank barrels
Natural Gas
Mcf	thousand cubic feet
MMcf	million cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
MMbtu	million British Thermal Units
Bcf	billion cubic feet
Tcf	trillion cubic feet
GJ	gigajoule

Other
AECO	EnCana Corp.’s natural gas storage facility located at Suffield, Alberta.
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil.
ARTC	Alberta royalty tax credit
BOE or boe	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
m3	cubic meters
MBOE	1,000 barrels of oil equivalent
Mstboe	1,000 stock tank barrels of oil equivalent
$M	thousands of dollars
$MM	millions of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
psi	pounds per square inch

The following table sets forth certain conversions between Standard Imperial Units and the International System of

Units (or metric units).

CONVERSIONS

To Convert From	To	Multiply By
Mcf	cubic meters	0.28174
cubic meters	cubic feet	35.494
bbls	cubic meters	0.159
cubic meters	bbls oil	6.293
feet	Meters	0.305
meters	Feet	3.281
miles	kilometres	1.609
kilometres	Miles	0.621
acres	Hectares	0.405
hectares	Acres	2.471
gigajoules	Mmbtu	0.950

In this document, a boe conversion ratio of 6 Mcf = 1 bbl has been used. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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CERTAIN DEFINITIONS

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

“ASC” means the Alberta Securities Commission.

“Canada Southern” means Canada Southern Petroleum Ltd.

“Canadian Superior” or the “Corporation” means Canadian Superior Energy Inc.

“CBM” means coal bed methane.

“CNSOPB” means the Canada-Nova Scotia Offshore Petroleum Board.

“Common Shares” means the common shares in the capital of the Corporation.

“GLJ” means GLJ Petroleum Consultants Ltd.

“GLJ Report” means the report dated March 14, 2008 prepared by GLJ evaluating the Corporation’s proved and proved plus probable reserves effective December 31, 2007.

“MEEI” means the Trinidad and Tobago Ministry of Energy and Energy Industries.

“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

“OSC” means the Ontario Securities Commission.

“Petrotrin” means Trinidad and Tobago’s National Oil Company.

“Preferred Shares” means the first preferred shares in the capital of the Corporation.

“PSC” means production sharing contract.

“Rights Plan” means the Corporation’s shareholder rights plan.

“Rights Plan Agreement” means the shareholder’s rights plan agreement in respective of the Rights Plan dated effective as of January 22, 2001 between the Corporation and Valiant Trust Company of Canada, as amended from time to time.

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GLOSSARY OF TECHNICAL TERMS

As used in this Annual Information Form, the following technical terms and acronyms have the respective meanings specified below.

1.“constant prices and costs” means prices and costs used in an estimate that are:

(a)the Corporation’s prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies;

(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).

For the purpose of paragraph (a), the Corporation’s prices will be the posted price for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors.

2.“crude oil” or “oil” means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated. It does not include solution gas or natural gas liquids.

3.“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;

(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.

4.“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.

5.“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:

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(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.

6.“exploratory well” means a well that is not a development well, a service well or a stratigraphic test well.

7.“field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to denote localized geological features, in contrast to broader terms such as “basin”, “trend”, “province”, “play” or “area of interest”.

8.“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).

9.“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 and costs or forecast prices and costs.

10.“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;

(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.

11.“natural gas” means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural gas can exist in a reservoir

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either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen.

12.“natural gas liquids” 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.

13.“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.

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

15.“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.

16.“production” means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

17.“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.

18.“proved property” means a property or part of a property to which reserves have been specifically attributed.

19.“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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20.“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.

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

22.“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.

CURRENCY OF INFORMATION

The information in this Annual Information Form is stated as at December 31, 2007, unless otherwise indicated. For an explanation of the capitalized terms and expressions and certain defined terms, please refer to the “Glossary of Technical Terms” in this Annual Information Form. Except as otherwise indicated, all dollar amounts in this Annual Information Form are expressed in Canadian dollars and references to $ are to Canadian dollars.

FORWARD LOOKING STATEMENTS

Canadian Superior Energy Inc. cautions that all statements in this document, other than statements of historical fact, including statements regarding estimates of reserves, estimates of future production as well as other statements about anticipated future events or results are forward looking statements. Forward looking statements often, but not always, are identified by the use of words such as “seek”, “anticipate”, “believe”, “continue”, “plan”, “estimate”, “expect”, “target”, and “intend” and statements that an event or result “may”, “will”, “should”, “could” or “might” occur or be achieved and other similar expressions. Forward-looking statements in this document include, but are not limited to, statements about:

·the future commercial success of the Corporation’s oil and natural gas exploration, development and production activities;

·the stability of world-wide oil and natural gas prices;

·the Corporation’s ability to make necessary capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future;

·competition with and among other oil and gas companies for the acquisition, exploration, production and development of oil and natural gas properties;

·the Corporation’s oil and natural gas reserves;

·the Corporation’s ability to obtain the required licenses and permits from governmental authorities for its exploration, development and production activities; and

·the Corporation’s ability to successfully defend against pending or future litigation.

This Annual Information Form contains forward-looking information on future production, project start-ups and future capital spending. Actual results or estimated results could differ materially due to changes in project schedules, operating performance, demand for oil and gas, commercial negotiations or other technical and economic factors or revisions.

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Statements contained in this Annual Information Form relating to future results, events and expectations are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements involve known and unknown risks, uncertainties, scheduling, re-scheduling and other factors which may cause the Corporation’s actual results, performance, estimates, projections, interpretations, prognoses schedules or achievements, or the actual results, performance, schedules or achievements of the industry in which the Corporation operates, to be materially different from any future results, performance or achievements expressed or implied by such statements.  Such factors include, among others, those described in the Corporation’s Annual Reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.

This Annual Information Form, the documents incorporated by reference into this Annual Information Form, and other reports and filings with the securities regulatory authorities include forward-looking information, including estimates, projections, interpretations, prognoses and other information that may relate to current, past or future production, development(s), testing, well test results, project start-ups and future capital spending. Current, past and/or future actual results and/or reported results, estimates, projections, interpretations, prognoses, well results, test results, reserves, production, resource and/or resource potential, development(s), project start-ups, and capital spending, plans and/or estimated results could differ materially due to changes in project schedules, operating performance, demand for oil and gas, commercial negotiations or other technical and economic factors or revisions.  The Corporation’s website and corporate information thereon may contain reference to the terms “discovery”, “reserves” and/or “resources” or “resource potential” which are those quantities estimated to be contained in accumulations.  There is no certainty that any portion of these accumulations or estimated accumulations on this website may not change materially and that, if discovered, in this or any other discovery, the accumulations or estimated accumulations may not be economically viable or technically feasible to produce.

This Annual Information Form, the documents incorporated by reference into this Annual Information Form, and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward looking statements are based on the Corporation’s beliefs and assumptions based on information available at the time the assumption was made. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. Much of this information also appears in management’s discussion and analysis. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in this Annual Information Form under “Risk Factors”, which could cause the Corporation’s actual results and experience to differ materially from the anticipated results or other expectations expressed. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this Annual Information Form or otherwise, 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 securities law.

THE CORPORATION

Canadian Superior was incorporated as 297272 Alberta Ltd. by Articles of Incorporation under the Business Corporations Act (Alberta) on March 21, 1983. Canadian Superior amended its articles: (i) on April 27, 1993, to change its name to “KapaIua Gold Mines Ltd.” and to remove the private company restrictions in its articles; (ii) on November 16, 1993, to change its name to “Prize-Energy Inc.” and to consolidate its issued and outstanding Common Shares on a 1-for-5 basis; and (iii) on January 19, 1999, to permit the appointment of additional directors between annual meetings and to restate its articles in a consolidated form. On August 24, 2000, a further amendment changed the name of the Corporation to “Canadian Superior Energy Inc.” and consolidated its issued and outstanding Common Shares on a l-for-2 basis.

Canadian Superior is a reporting issuer, or the equivalent, in the provinces of British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia, Prince Edward Island, and Newfoundland. The

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Common Shares are listed and posted for trading on the Toronto Stock Exchange and the American Stock Exchange under the symbol “SNG”.

The Corporation’s head office is located at 2700, 605 – 5th Avenue S.W., Calgary, Alberta, T2P 3H5 and its registered office is located at 3300, 421 - 7th Avenue S.W., Calgary, Alberta, T2P 4K9. In addition, the Corporation has an east coast office located at 1409, 1959 Upper Water Street, Halifax, Nova Scotia, B3J 3N2, a field office at P.O. Box 2259 Drumheller, Alberta, T0J 0Y0, and a field office in the West Indies located at 5 Herbert Street, St. Clair, Port of Spain, Trinidad & Tobago, West Indies.

The Corporation has no subsidiaries which individually represent more than 10%, nor in the aggregate represent more than 20%, of the total consolidated assets and total consolidated revenues of the Corporation, as at December 31, 2007.

The Corporation has a total of 60 full-time staff, including 4 staff members in its Halifax, Nova Scotia office, 8 staff members in its Drumheller, Alberta field office and 24 staff members in its Trinidad and Tobago field office and field operations.

GENERAL DEVELOPMENT OF THE BUSINESS

Canadian Superior is a crude oil and natural gas exploration and production company with its primary emphasis on the exploration for, and production of, crude oil and natural gas in Western Canada, offshore Nova Scotia, and offshore Trinidad and Tobago.

The most significant events in the development of the business of Canadian Superior during the past three completed fiscal years are described below.

On February 15, 2008, the Corporation announced that Robb Thompson and Leif Snethun had joined as Chief Financial Officer and as Vice President, Western Canada, respectively.

On January 16, 2008, the Corporation announced an agreement to acquire all of the issued and outstanding shares of Seeker Petroleum Ltd., subject to certain conditions, for total consideration of approximately $51.2 million, including the assumption of approximately $8.5 million of net debt.

On December 31, 2007, 500,000 warrants were exercised into 500,000 Common Shares at US$2.50 per share for gross proceeds of US$1.3 million.

On November 19, 2007, the Corporation closed a private placement consisting of 6,472,500 Common Shares issued on a “flow-through” basis at a price of $3.50 per share for gross proceeds of $22.7 million.

On November 15, 2007, Craig McKenzie, CEO, was named to the board of directors of the Corporation.

On October 1, 2007, the Corporation announced that Craig McKenzie, recent President of BG Trinidad & Tobago, BG Group PLC, was appointed as Chief Executive Officer of the Corporation.

On August 16, 2007, the Corporation announced that BG International Limited (“BG”) entered into a farm-in agreement and joint operating agreement to participate in the exploration, drilling and development of the “Intrepid” Block 5(c).  Under the terms of the agreements BG acquired a 30% working interest in Block 5(c).  In addition BG paid approximately US$39 million and on a go-forward basis paying approximately 40% of the exploration costs associated with the drilling of the three commitment wells in Block 5(c).

On June 26, 2007, Greg Noval was appointed to the new position of Executive Chairman of the Corporation.

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On January, 23, 2007, the Corporation announced that its offshore Nova Scotia exploration acreage holdings have increased to 2.59 million net acres with the addition of the EL2412 and EL2413 deepwater blocks previously held by a U.S. company.

On December 29, 2006 the Corporation completed a private placement of 2,500,000 Common Shares at  a price of $2.37 per share for gross proceeds of $5.9 million.

On December 13, 2006 the Corporation issued 6,000,000 Common Shares on a “flow-through” basis at a price of $2.57 per Common Share for aggregate proceeds of $15.4 million.

On August 16, 2006, Neil Dore was appointed Vice President Western Canada Operations and Roger Harman was appointed as Chief Financial Officer of the Corporation.

In June 2006, Canadian Superior offered to acquire all of the issued and outstanding shares of Canada Southern Petroleum Ltd. from existing shareholders. Canadian Superior offered 2.75 Common Shares plus $2.50 cash for each issued and outstanding share of Canada Southern. On July 17, 2006, Canadian Superior revised its offer to two Common Shares, $2.50 cash and a 25% net profit interest in Canada Southern’s approximately 927 bcf of natural gas attributed to it’s interest in the Canadian Arctic Islands. The minimum condition attached to the revised offer was not met. 171,495 Canada Southern shares were tendered to the original offer, for which Canadian Superior issued 471,612 Common Shares and paid $0.4 million to take-up. The costs incurred in relation to the offer, including the fair value of the Common Shares issued upon take-up, exceeded the fair value of the Canada Southern shares acquired. The difference has been recorded as a Loss on Investment in the Corporation’s financial statements. Canadian Superior subsequently received US$2.2 million as a result of the sale of the Canada Southern shares acquired.

On April 10, 2006, Michael (Mike) E. Coolen was appointed President and Chief Operating Officer of the Corporation.

On February 9, 2006, the Corporation completed a private placement of 1,000,000 units at a price of $2.40 per unit for gross proceeds of $2.4 million. Each unit consisted of one Common Share and one-half of one Common Share purchase warrant. Each purchase warrant entitled the holder thereof to acquire an additional Common Share at any time until December 31, 2006 at a price of $2.40 per Common Share.

On February 1, 2006, the Corporation completed a private placement of US $15 million of preferred share purchase units.

On January 4, 2006, the Corporation announced that at year end 2005 it had closed, by way of private placement, total “flow-through” share financings of 2,976,400 Common Shares at a price of $3.00 per share for gross proceeds of $8.9 million.

On November 10, 2005, the Corporation announced that they had been advised by CNSOPB that the consolidation of its deepwater Mayflower exploration licence (EL 2406) and its shallow water Mariner exploration licence (EL 2409) had been approved by the Government of Canada and the Province of Nova Scotia. The consolidation will come into effect upon the drilling of the next Mariner exploration well and will allow the work commitments and related work commitment deposits for these two exploration licences (EL 2406 and EL 2409) to be combined, allowing the existing work deposit for the Mayflower exploration licence (approximately $10 million) to be applied directly against the costs of drilling Canadian Superior’s next Mariner well. In effect, this provides Canadian Superior with $10 million of additional capital to be applied to drilling the next Mariner well.

On November 2, 2005, the Corporation announced the appointment of Michael (Mike) E. Coolen, Halifax, Nova Scotia and Kaare (Kory) Idland, Red Deer, Alberta to the board of directors of the Corporation.

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On September 6, 2005, the Corporation and its insurers reached an agreement to settle all securities class action litigation and other actions pending in Canada against the Corporation and certain of its officers and directors resulting from the drilling in 2004 of the Mariner 1-85 exploration well drilled offshore Nova Scotia. The $2.15 million settlement, which was covered by the Corporation’s insurance, was reached with no admission of liability by any party.

On July 21, 2005, the Corporation announced that it had entered into a production sharing contract with the Government of Trinidad and Tobago for offshore exploration and production on offshore Block 5(c), located approximately 90 km off the east coast of Trinidad in the Columbus Basin. The production sharing contract provides Canadian Superior the right to explore on Block 5(c), which covers 80,041 gross acres.

On July 12, 2005, the Corporation closed a private placement of 5.5 million special warrants at a price of $2.00 per special warrant for gross proceeds of $11.0 million.

On June 8, 2005, the Corporation announced that it and its insurers reached an agreement to settle all securities class action litigation and other actions pending in the United States against the Corporation and certain of its officers and directors resulting from the drilling of the Canadian Superior El Paso Mariner 1-85 exploration well drilled with El Paso Corporation in offshore Nova Scotia. The US$3.2 million settlement, covered by the Corporation’s insurance, was reached with no admission of liability by any party.

On February 16, 2005, Canadian Superior announced that the Toronto Stock Exchange had completed its review of the Corporation and had determined that it had met the Toronto Stock Exchange’s continued listing requirements.

On February 1, 2005, the Corporation announced that its first Windfall area exploration well had been successfully drilled. The well drilled at 14-33-60-14 W5M (W.I. 40%) was AOF’d at 1,300 Mcf/d and had an estimated stabilized rate of 750 Mcf/d at the time.

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

Canadian Superior is engaged in the exploration for, and the development and production of, crude oil and natural gas primarily in Western Canada and offshore Nova Scotia, Canada and Trinidad and Tobago. The Corporation also reviews potential acquisitions and new international exploration blocks to supplement its exploration and development activities.

OIL AND GAS 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.

Trinidad and Tobago

On July 20, 2005, Canadian Superior signed a PSC for the 80,020 acre “Intrepid” Block 5(c), offshore Trinidad and Tobago, with the Government of the Republic of Trinidad and Tobago. The PSC provides Canadian Superior the right to explore on “Intrepid” Block
5(c).

The “Intrepid” Block 5(c) is located approximately 96 kilometers (60 miles) off the east coast of the island of Trinidad with water depths in the range of 150m to 450m (500 to 1,500 feet). It is anticipated that all wells in Block 5(c) will be drilled from a semi-submersible drilling rig, with the first three wells being drilled in water depths of about 260 – 320 m (850 – 1,050 feet). During 2005 and 2006, the Corporation actively pursued various rig options for the “Intrepid” drilling and has entered into a firm multi-well drilling contract for the Kan Tan IV Semi- Submersible Drilling Rig to drill the first three exploration wells.

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The three “Intrepid” Block wells will evaluate three large separate potential hydrocarbon bearing structures that have been delineated by extensive 3D seismic over the entire “Intrepid” Block 5(c) that Canadian Superior has evaluated and interpreted. The first well commenced drilling shortly after the Kan Tan IV had completed a scheduled refurbishment in Brownsville, Texas. On May 11, 2007 the Kan Tan IV was towed out of the port of Brownsville, Texas, en route to the port of Chaguarmas in Trinidad to load up supplies and finalize drilling preparations and was then moved to the first drilling location on the “Victory” Prospect arriving on site June 19, 2007. The first well on the “Intrepid” Block 5(c) was on the “Victory” Prospect, the second and third wells are planned for the “Bounty” and “Endeavour” prospects.

On June 25, 2007, the drilling of a pilot hole at the “Victory” well site commenced. Following that drilling and evaluation, the main well bore was spudded on June 29, 2007. On August 30, 2007, the “Victory” well site reached Total Depth of 16,621 feet (subsea).  In attempting to come out of the hole to commence wireline logging and possible flow testing of the well, difficulties were encountered which resulted in being unable to remove the full drillstring from the well. Accordingly the well was severed at a depth of approximately 11,726 feet and the well plugged back to a depth of approximately 9,564 feet. The lower portion of the well was re-drilled to a total depth of 16,150 feet.  On December 17, 2007, the Corporation announced that it had unanimously agreed with its partners to case and conduct flow tests on the “Victory” well.

The “Victory” well tested natural gas in two main formations and the Corporation estimates that the well is capable of producing at flowing rates of over 100 mmcf/d from the lower zone, which was the first formation tested; in addition, the Corporation estimates that the well is capable of flowing 50 mmcf/d from the second formation. Both zones were tested at restricted rates and had high flowing pressures.

On February 20, 2008, the Corporation successfully spudded the “Bounty” well with the Kan Tan IV semi-submersible drilling rig. The rig had moved approximately 2.2 miles from the “Victory” well.  The “Bounty” well is planned to be drilled to a total vertical depth of approximately 18,000 feet subsea in about 1,000 feet of water and is expected to take about 110 days to drill. It is expected that the “Bounty” well and the third well, “Endeavour” will both be drilled and evaluated by year end 2008.

Trinidad and Tobago has a well educated labour force, good transportation and communication links, a strong legal system, a well entrenched stable democratic system of government, a soundly regulated financial system and a very successful and growing oil and gas industry that accounts for approximately 50% of total government revenue. Offsetting Canadian Superior’s “Intrepid” Block 5(c) to the west is British Gas’s Dolphin and Dolphin Deep Developments, both fields on trend with our ‘Intrepid’ Block 5(c) in the ‘dip’ direction (SW-NE). The same holds true in the ‘strike’ direction (NW-SE), with BP’s Manakin and Statoil’s Cocuina fields on trend to the southeast of our ‘Intrepid’ Block 5(c) and EOG Resources, Inc.’s 2006 discovery to the northwest, again directly on trend in the ‘strike’ direction.

To assist Canadian Superior in going forward with its drilling in Trinidad, the Corporation had entered into a participation agreement with a non-competitive industry financial partner. The partner participates on a promoted basis paying 1/3 of Canadian Superior’s Block 5(c) exploration program costs to obtain 25% of Canadian Superior’s revenue share of these prospects. In addition, in August, 2007, the Corporation announced that BG, a wholly owned subsidiary of BG Group PLC, had entered into a farm-in agreement and joint operating agreement. BG will participate on a promoted basis paying approximately 40% of Canadian Superior’s Block 5(c) exploration program costs to obtain a 30% working interest in the production sharing contract. BG also paid approximately US$39 million, addressing BG’s share of previous incurred costs and a substantial entry bonus.

Throughout 2006 and 2007, Canadian Superior was very active interpreting the extensive 3D seismic data coverage over Block 5(c) and the adjacent fields. This included detailed reprocessing of the 3D seismic data over Block 5(c) and several major offsetting natural gas fields. To assist in both the geological activities and ongoing well engineering, Canadian Superior obtained from MEEI extensive offsetting well technical data in the area and in combination with our detailed seismic interpretation was able to identify several drilling locations, including the three-well program in progress as outlined above. Canadian Superior also finished the geohazard surveys for two of the drilling sites. In addition to the

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various geological and geophysical analysis, evaluations and interpretation, in 2006 and 2007, many other well construction preparatory activities were undertaken in the areas of engineering, procurement, health, safety and environmental management, community relations, regulatory approvals and corporate oversight of the Kan Tan IV’s refurbishment project. This included the purchasing of pipe, wellheads and long lead items to facilitate the timely drilling of the first two wells, in addition to making an advance payment of US$20 million to the rig owners to be applied against drilling day rate charges.

In addition, Canadian Superior recruited additional key personnel to add to its Trinidad and Tobago well construction team, which is lead by Mr. Roger De Freitas, a Trinidadian national and Canadian Superior’s Country Manager (Trinidad and Tobago). Mr. De Freitas is a former Vice President with Santa Fe Drilling Co. and has been involved in the oil and gas offshore drilling business for over 30 years, holding several other senior management positions throughout the world, including work in Trinidad early in his oilfield career. These new personnel have included an engineering manager, a drilling superintendent, four offshore drilling supervisors, an HSE manager, shore base personnel and various supply chain and administrative staff. Furthermore, the Trinidad and Tobago well construction team continues to be ably supported by our experienced drilling team personnel in Halifax, Nova Scotia and in our Calgary, Alberta head office.

The Corporation also continues to prepare for the first phase of operations on its Mayaro/Guayaguayare (“M/G”) “Tradewinds” project. On July 27, 2007, Canadian Superior, as operator, and its joint venture partner, the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”) received the Exploration and Production License for the near shore Mayaro/Guayaguayare (“M/G”) Block off the east coast of the island of Trinidad and Tobago from the Trinidad and Tobago Ministry of Energy and Energy Industries. This joint venture encompasses two near-shore Blocks (58,080 gross acres) off the east coast of Trinidad where management hopes to establish significant oil reserves in the heart of a known producing hydrocarbons-bearing structural trend. For the M/G Block Land, the Corporation is working on the design of a seismic program to evaluate the near-shore block and is planning this program to be shot in 2008 where the Corporation intends to drill 2 offshore wells on the M/G Block prior to year end 2009.

Offshore Nova Scotia, Canada

Canadian Superior is one of the few operators involved in all three main play types in the offshore Nova Scotia basin where the Corporation has evolved as the company holding the largest exploration acreage position with 100% interests in five exploration licences totalling 1.2 million net acres at year end 2007. Canadian Superior relinquished EL2412 and EL2413 at the end of 2007 and currently holds the following exploration licenses “Mayflower” (EL2406), “Marauder” (EL2415), “Marconi” (EL2416), “Mariner” (EL2409) and “Marquis” (EL2402) exploration blocks. Four of these licences, “Marquis”, “Mariner”, Marauder” and “Marconi”, are in the Sable Island area which is an area of natural gas supply that is very important and strategic for the North Eastern United States gas supply.

Canadian Superior’s “Mariner” shallow water block (EL2409) covers 100,656 acres and is located approximately nine kilometres northeast of Sable Island, offshore Nova Scotia and directly offsets five significant discoveries near Sable Island, including the ExxonMobil Venture natural gas production field and other nearby Sable Offshore Energy Project existing production infrastructure. Three large Cretaceous structures have been identified for drilling on the “Mariner” block based on an evaluation of seismic data. The first exploration well, Canadian Superior El Paso “Mariner” I-85, was drilled on this block in November 2003 to March 2004 and encountered gas pay in multiple zones. Two new prospective locations have been identified and further drilling is planned by Canadian Superior on the “Mariner” Block in 2009. Front end geological and geophysical analysis are complete and environmental approvals are in place.

Canadian Superior’s “Mayflower” deepwater project exploration licence (EL2406) covers approximately 711,662 acres and mapping to date indicates the presence of several sizeable deepwater prospects. These large prospects are structural and are typically formed by mobile salt tectonics. The Corporation is planning to proceed in due course with a high resolution seismic program over the “Mayflower” block to further define targeted structures to enable future drilling.

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The Corporation’s “Marquis” block (EL2402) comprises 51,339 acres approximately 20 kilometres (12.5 miles) northwest of Sable Island and is directly on trend with the EnCana Deep Panuke Abenaki Reef discoveries and proposed development project, which is approximately 25 kilometres (15.6 miles) southwest. The “Marquis” Prospect is in shallow water depths (less than 100 metres) and is in close proximity to existing pipeline infrastructure. Canadian Superior’s “Marquis” L-35/L-35A test well was drilled from July 2002 – September 2002 and was abandoned after having encountered porosity and Abenaki reef reservoir.

Canadian Superior has identified several other large Cretaceous and Jurassic prospects on its 100% “Marauder” and 100% “Marconi” exploration lands which cover an additional 370,890 acres offshore Nova Scotia, offsetting the Sable Island area. The “Marauder” lands directly offsets three significant discovery licences and have several seismically defined prospects, two of which lie on trend with significant discoveries near existing production infrastructure. The “Marconi” licence has a seismically defined tilted fault / anticlinal prospect similar to other Sable area fields.

Western Canada

The Corporation continued its successful Western Canada exploration and development program in 2007 where it focused its drilling activity in its core Drumheller area.  Currently, the Corporation derives all of its production and cash flow from Western Canada, with approximately 90% of the Corporation’s production coming from the Drumheller area, where the Corporation remains focused on continued growth through the “drill-bit”.  In addition, the Corporation has placed a more emphasized focus on the Boundary Lake and Cecil areas and surrounding properties such as Giroux Lake and evaluating selected acquisition opportunities.

Canadian Superior reported that due to ongoing drilling success in 2007, with new production brought on-stream throughout 2007, production averaged approximately 3,025 boe/d raw (2,843 boe/d, average daily sales volume) for the year, and although flat compared to 2006 on a yearly average, showed significant growth in the 4th quarter resulting in year end production of approximately 3,520 boe/d raw (3,290 boe/d, average daily sales volume).

During 2007, the Corporation drilled or participated in 73 gross, 25 operated and 48 non-operated (total of 25.0 net wells) with an overall success rate of 92%. In addition, the land picture for Canadian Superior continues to remain steady as the Corporation drills and makes strategic land sale acquisitions. At December 31, 2007, the Corporation held in Western Canada 246,445 gross acres (164,968 net acres) of predominately Canadian Superior operated lands with a high working interest of approximately 70%.

On January 16, 2008, the Corporation announced entering into an acquisition agreement whereby Canadian Superior will acquire subject to certain conditions, all of the issued and outstanding shares of Seeker Petroleum Ltd., for total consideration of approximately $51.2 million, including the assumption of approximately $8.5 million of debt.  Canadian Superior will acquire approximately 1,035 boe/d of Western Canadian production and 2,073 MBOE of proven plus probable reserves.

Six wells were drilled and cased in the first quarter of 2008 and currently another well, from the Seeker assets, is being drilled.  There are two 3D seismic programs planned for winter 2008 that total 73 square kilometers.  A third program will be added to evaluate Seeker’s acreage.  The Corporation’s comprehensive 2008-2009 drilling program will be adjusted further to rank and prioritize the two companies drilling portfolios.

Drumheller Area

In the Drumheller area of Central Alberta, Canada, located approximately 60 miles N.E. of the City of Calgary, the Corporation has major acreage and production holdings in both conventional Cretaceous plays and in the Horseshoe Canyon and Mannville Coal Bed Methane (“CBM”) plays; an area which has shallow low cost prospects and year-round accessibility.

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The Drumheller area offers a multitude of opportunities that include both oil and gas play types and these are contained in six distinct stratigraphic zones.  The shallow targets include the Second White Specks, Medicine Hat, Belly River Group, and Edmonton Groups and range in depth from 300-1100 meters (980 - 3600 feet).  Well production in these zones range from 50 - - 750 mcf/d with associated reserve size of 0.1 - 1 Bcf.  Deeper targets in the Drumheller area include the Mannville group 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 Bcf.  The Banff formation is a carbonate play which ranges in depth from 1100 - 1400 meters (3600 - 4600 feet) and tend to be oil prone.  On average the Banff can produce oil rates of 20 - 200 bbl/d with reserves ranging from 20 - 200 mbbl.

The Corporation at the end of 2007 held 167,183 gross acres (107,126 net acres) of land in this area, with 40% of this still to be developed.  This core area accounts for approximately 90% of Canadian Superior’s production.  In 2007, 63 gross (17.9 net) wells were drilled in the Drumheller area consisting of 55 gross (15.5 net) conventional wells and 8 gross (2.4 net) Horseshoe Canyon CBM wells.

Coal bed methane has been recognized as one of the emerging plays available to the oil and gas industry in Canada, which continue to add Proven and Proven plus Probable Reserves to the Corporation.  The Drumheller area is near the heart of recent coal bed methane (CBM) development in Western Canada and Canadian Superior is fortunate to have one of the largest concentrated high working interest land positions with significant land holdings in both the Horseshoe Canyon and the Mannville stratigraphic zones.

Due to lower gas prices in 2007, the Corporation temporarily delayed some planned drilling of Horseshoe Canyon CBM wells.  The development of CBM lands in 2007 included the non-operated drilling of 8 CBM wells (2.41 net) and re-completing 5 CBM wells (1.1 net) in the Edmonton sands that currently are only producing from the Coals.  As with all new plays, the development strategy continues to be evolving with the more information we gain in order to save capital and increase the amount of reserves available per well bore.  One of these changes has been the commingling of the Horseshoe Canyon CBM with the Edmonton Sands.  Initial data is suggesting that completing both the Horseshoe Canyon and the Edmonton Sands together will both increase the flow rate and reserves per well.  The successful results to date achieved by Canadian Superior and its partners on a small portion of Canadian Superior’s non-operated land will be utilized by the Corporation to provide a solid foundation for development and operating drilling on this large CBM potential that exists over our extensive operated high working interest acreage base within our Drumheller core producing area.

The Corporation’s total acreage for CBM is 185 gross (108 net) sections of which 14 gross (13.4 net) sections have both Horseshoe Canyon and Mannville CBM potential.  Canadian Superior holds 157 gross (81 net) sections of Horseshoe Canyon rights.  The Horseshoe Canyon Coal depths range from 200 - 400 meters (650 - 1300 feet) and are typically found in 8 - 10 coal seams with each seam averaging from 0.75 - 1.5 meters (2.5 - 5 feet).  These coals contain dry gas and produce little or no water.

An untapped resource that exists in the Drumheller area is the Mannville coals.  These coals are between 1000 - 1300 meters (3300 - 4300 feet) in depth with each seam thicker (up to 4 meters) but less frequent (1 - 5 seams) than the Horseshoe Canyon.  Resource potential estimates are still in the early stages but Canadian Superior calculates it has over 1000 BCF (P50) of net sales reserves in this area.  Currently the Corporation has 42 gross (41 net) sections of land in the Mannville CBM fairway.  Drilling for these coals would include horizontal drilling techniques.  Plans for development of Mannville CBM by Canadian Superior will be measured until the reserve and production parameters are better defined.

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Windfall

Canadian Superior drilled 2 wells in 2007 and one of these wells is on production.  The Corporation continues to look at this higher reward-medium risk area with a view towards further expansion, using its current land base as a nucleus.  In nearby Rimbey the Corporation drilled and completed one gas well.  In this particular well, gas rates did not justify a tie-in and it was subsequently abandoned.

Boundary Lake/Cecil/Peroria/Parkland

The Boundary Lake/Cecil area is a high reward-medium risk that continues to gain momentum for exploration activity for Canadian Superior and was an important focus area in 2006 and into 2007, with its multi-zone potential and year-round access.  Following up successful wells in the area, the Corporation drilled 5 wells in 2007; 2 in Boundary Lake (1 D&A and 1 gas producing) and 2 in Cecil, both producing gas wells.  One well was drilled and cased in Peroria and was later abandoned.  Two wells were drilled in Parkland where the Corporation carries a Gross Overriding Royalty (“GORR”).  One of these wells is producing gas and the second is awaiting tie-in.  The Corporation has also been active in accumulating more land in the general vicinity and continues to build its land base in this emerging area.

The Foothills of Alberta, West of the 5th Meridian

During 2007 Canadian Superior also focused its exploration in Western Canada towards the foothills of Alberta, Canada to develop potentially high deliverability large reserve based drillable prospects in the Foothills.  This area represents an area of high risk-high reward exploration and production with year-round access.  In this area, well reserves can range to over 10 BCF/well with associated natural gas liquids and can produce at rates of over 5-10 mmcf/d.  Land strategies for this area include crown sales, leasing of freehold acreage and potential farm-ins or joint ventures.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

GENERAL

The reserve disclosure presented below conforms with the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which management of the Corporation believes is important to the readers of this information. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:l bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All of the Corporation’s reserves are in Canada, more specifically in the provinces of British Columbia, Alberta and Saskatchewan.

Selected Reserves Information

The following tables set forth certain information relating to the oil and natural gas reserves of the Corporation’s properties and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2007. The information set forth below is derived from the GLJ Report prepared by GLJ evaluating the Corporation’s proved and proved plus probable reserves. The effective date of the GLJ Report is December 31, 2007. The GLJ Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook. All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Corporation’s properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves

15

provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater or less than the estimates provided herein.

The Corporation has a Reserves Committee consisting of Messrs Greg Noval, Kaare Idland and Thomas J. Harp, which reviews the qualifications and appointment of the independent qualified reserves evaluators. The Reserves Committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluation and review by the independent qualified reserves evaluators.

In accordance with the requirements of NI 51-101, the Report on Reserves Data by Independent Qualified Reserves Evaluator in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as Appendices “A” and “B” hereto, respectively.

RESERVES DATA - CONSTANT PRICES AND COSTS

The following table sets forth a summary of reserves and values of the Corporation using constant pricing and costs.

Summary of Oil and Gas Reserves: Effective December 31, 2007

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	820	166	19,376	761	111	16,101
Developed Non-Producing	15	23	2,256	14	16	1,890
Undeveloped	—	3	3,638	—	3	3,305
Total Proved	834	192	25,271	776	130	21,297
Total Probable	838	87	13,820	729	59	11,772
Total Proved Plus Probable(1)	1,672	278	39,091	1,504	188	33,069

Notes:

(1)           Some totals may differ slightly due to rounding.

Net Present Value of Future Net Revenue of Oil and Gas Reserves

	Before Future Income Tax Expenses and Discounted at		After Future Income Tax Expenses and Discounted at
	0%	10%	0%	10%
	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	120,175	88,986	119,730	88,676
Developed Non-Producing	7,524	5,605	5,759	4,317
Undeveloped	8,867	3,650	7,275	2,569
Total Proved	136,566	98,241	132,764	95,562
Total Probable	89,844	41,946	69,995	31,505
Total Proved Plus Probable	226,409	140,187	202,759	127,067

16

Additional Information Concerning Future Net Revenue (Undiscounted)

	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Future Income Tax Expenses	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	254,346	32,100	70,782	9,371	5,528	136,566	3,802	132,764
Total Proved Plus Probable	421,814	56,084	113,532	19,538	6,251	226,409	23,651	202,759

Future Net Revenue By Production Group

	Future Net Revenue Before Income Taxes and Discounted at 10%(3)
	(M$)
Proved
Light and Medium Crude Oil(1)	34,409
Natural Gas(2)	59,088
Non-Conventional Oil and Gas Activities (CBM)	4,744
Total	98,241
Proved Plus Probable
Light and Medium Crude Oil(1)	55,505
Natural Gas(2)	76,954
Non-Conventional Oil and Gas Activities (CBM)	7,729
Total	140,187

Notes:

(1)Including solution gas and other by-products.

(2)Including by-products but excluding solution gas.

(3)Other company revenue and cost not related to a specific production group have been allocated proportionately to production groups.

RESERVES DATA – FORECAST PRICES AND COSTS

The following table sets forth a summary of reserves and values using forecast pricing and costs:

Summary of Oil and Gas Reserves: Effective December 31, 2007

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Proved
Developed Producing	802	166	19,425	745	111	16,150
Developed Non-Producing	15	23	2,256	14	16	1,891

17

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas
	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Undeveloped	—	3	3,651	—	3	3,318
Total Proved	817	192	25,333	760	130	21,359
Total Probable	848	87	13,890	737	60	11,832
Total Proved Plus Probable(1)	1,665	279	39,223	1,497	189	33,190

Net Present Value of Future Net Revenue of Oil and Gas Reserves

	Before Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	124,690	105,281	91,890	82,018	74,397
Developed Non-Producing	8,753	7,519	6,536	5,740	5,086
Undeveloped	11,941	8,001	5,391	3,588	2,295
Total Proved	145,384	120,801	103,817	91,345	81,778
Total Probable	95,833	63,108	44,539	32,924	25,139
Total Proved Plus Probable	241,217	183,909	148,356	124,269	106,917

	After Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	123,733	104,494	91,237	81,471	73,935
Developed Non-Producing	6,356	5,445	4,726	4,149	3,678
Undeveloped	9,753	6,263	3,985	2,431	1,330
Total Proved	139,842	116,202	99,948	88,050	78,943
Total Probable	74,060	47,874	33,291	24,278	18,282
Total Proved Plus Probable	213,901	164,076	133,239	112,328	97,225

Additional Information Concerning Future Net Revenue (Undiscounted)

	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Income Taxes	Future Income Tax Expenses	Future Net Revenue After Income Taxes
	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved Reserves	275,345	35,032	78,889	9,429	6,611	145,384	5,542	189,842
Total Proved Plus Probable	467,873	62,210	136,627	19,624	8,195	241,217	27,315	213,901

18

Future Net Revenue By Production Group

	Future Net Revenue Before Income Taxes and Discounted at 10%(3)
	(M$)
Proved
Light and Medium Crude Oil(1)	31,490
Natural Gas(2)	65,628
Non-Conventional Oil and Gas Activities (CBM)	6,699
Total	103,817
Proved Plus Probable
Light and Medium Crude Oil(1)	50,495
Natural Gas(2)	86,048
Non-Conventional Oil and Gas Activities (CBM)	11,813
Total	148,356

Notes:

(1)Including solution gas and other by-products.

(2)Including by-products but excluding solution gas.

(3)Other company revenue and cost not related to a specific production group have been allocated proportionately to production groups.

PRICING ASSUMPTIONS - CONSTANT PRICES AND COSTS

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2007 in estimating the Corporation’s reserves data using constant prices and costs.

December 31, 2007 Constant Prices (2) 
Crude Oil and Natural Gas Prices

				NYMEX Futures WTI at Cushing		Brent Blend Crude Oil FOB		Light Sweet Crude Oil (40 API 0.3%S) at		Bow River Crude Oil Stream Quality at		LLB Crude Oil at		Medium Crude Oil (29 API, 2.0%S at		Alberta Natural Gas Liquids
Year	Infla-tion %	Exchange Rate		Oklahoma Then Current		North Sea Then Current		Edmonton Then Current		Hardisty Then Current		Hardisty Then Current		Cromer Then Current		Spec Ethane	Edmonton Propane	Edmonton Butane	Edmonton Pentanes Plus
		$US/$ Cdn		$US/bbl		$US/bbl		$Cdn/bbl		$Cdn/bbl		$Cdn/bbl		$Cdn/bbl		$Cdn/bbl	$Cdn/bbl	$Cdn/bbl	$Cdn/bbl
1999 Average	1.7	0.673		19.29		17.81		27.69		23.84		22.14		25.42		n/a	15.89	18.70	27.71
2000 Average	2.7	0.673		30.22		28.35		44.56		35.25		32.61		39.91		n/a	32.18	35.60	46.31
2001 Average	2.6	0.646		25.97		24.37		39.40		27.70		23.48		31.56		n/a	31.85	31.17	42.48
2002 Average	2.2	0.637		26.08		24.99		40.33		31.83		30.60		35.48		n/a	21.39	27.08	40.73
2003 Average	2.8	0.721		31.07		28.93		43.66		32.11		31.18		37.55		n/a	32.14	34.36	44.23
2004 Average	1.8	0.768		41.38		38.20		52.96		36.86		35.64		45.75		n/a	34.70	39.97	54.07
2005 Average	2.2	0.825		56.58		55.12		69.11		44.97		43.15		56.62		n/a	43.04	51.80	69.47
2006 Average	2.1	0.882		66.22		66.08		73.16		51.85		50.41		62.24		n/a	43.97	66.64	75.69
2007 Average	2.1	0.935		72.24		72.46		77.02		54.45		53.15		66.30		n/a	46.84	58.35	77.33
Dec. 31, 2007	0.0	1.012	(1)	95.95	(2)	94.00	(3)	93.39	(4)	53.23	(5)	53.74	(6)	74.26	(7)	22.32	59.77	74.71	94.24	(8)
Constant Thereafter

19

Natural Gas and Sulphur Price Forecast

Year (Average)	NYMEX Futures Henry Hub Then Current		Midwest at Chicago Then Current		AECO-C Spot Then Current		Spot Plant Gate	ARP Plant Gate	Aggregator Plant Gate	Alliance Plant Gate	Sask Energy Plant Gate	Sask Spot Plant Gate	Sumas Spot		Westcoast Stn. 2		BC Spot Plant Gate	Sulphur FOB Vancouver		Alberta Sulphur at Plant Gate
	$US/ mmbtu		$US/ mmbtu		$Cdn/ mmbtu		$Cdn/ mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$US/ mmbtu		$mmbtu		$mmbtu	$US/LT		$Cdn/ LT
1999	2.27		2.33		2.92		2.75	2.48	n/a	n/a	2.83	2.97	2.15		2.90		2.78	33.74		6.93
2000	3.91		3.96		5.08		4.92	4.50	4.60	n/a	4.79	5.13	4.17		5.00		4.88	38.14		13.59
2001	4.38		4.45		5.21		6.07	5.41	5.30	5.61	5.71	6.13	4.56		6.35		6.29	18.29		(14.66	)
2002	3.25		3.25		4.04		3.88	3.88	3.83	3.82	4.04	4.08	2.68		4.00		3.93	29.36		3.04
2003	5.11		5.46		6.66		6.49	6.13	5.89	6.69	6.40	6.68	4.66		6.40		6.32	59.81		39.83
2004	6.09		6.13		6.88		6.70	6.31	6.16	6.44	6.48	6.78	5.26		6.55		6.45	62.99		38.61
2005	8.55		8.24		8.58		8.42	8.30	8.32	8.45	8.36	8.30	7.13		8.20		8.10	63.50		33.77
2006	7.26		6.93		7.02		6.96	6.45	6.40	6.45	6.69	6.95	6.27		6.80		6.45	55.69		19.82
2007	6.92		6.83		6.65		6.43	6.14	6.11	5.86	6.07	6.38	6.52		6.39		6.23	81.62		41.34
Dec. 31, 2007	6.80	(9)	6.88	(10)	6.63	(11)	6.41	6.32	6.05	5.34	6.45	6.57	7.42	(10)	6.39(	12)	6.20	120	(13)	75.58
Constant Thereafter

Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate.

The plant gate price represents the price before raw gas gathering and processing charges are deducted.

Spot refers to weighted average one-month price.

Note:These prices are actual posted prices at the referenced date; other reference prices are derived based on historical price differentials.

(1)Noon Rate for the Bank of Canada

(2)U.S. Energy Information Administration (Cushing, OK WTI Spot Price FOB)

(3)Spot prices for dated Brent from Bloomberg

(4)Average December 31, 2007posted price reported by Imperial, Shell, Flint Hill, Petro-Canada, BP and Suncor

(5)Average December 31, 2007posted price reported by Imperial, Flint Hill, EnCana and BP

(6)Average December 31, 2007posted price reported by Petro-Canada, Flint Hill, Encana and BP

(7)Average December 31, 2007posted price reported by Flint Hill and Encana

(8)Average December 31, 2007posted price reported by Shell, Flint Hill and BP

(9)Platts gas daily for gas flow Dec. 28-31, 2007. Transaction date December 27, 2007

(10)Platts gas daily for gas flow Dec. 28-31, 2007. Transaction date December 27, 2007

(11)Same day settlement price from NGX

(12)Next day settlement price from NGX

(13)Utilized current GLJ forecast price

PRICING ASSUMPTIONS - FORECAST PRICES AND COSTS

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2007 in estimating the Corporation’s reserves data using forecast prices and costs.

Table 1

GLJ Petroleum Consultants

Crude Oil and Natural Gas Liquids

Price Forecast

Effective January 1, 2008

	Inflla- tion %	Bank of Canada Average Noon Exchange Rate	NYMEX WTI  Near Month Futures Contract Crude  Oil at Cushing Oklahoma		ICE BRENT  Near Month Futures Contract Crude Oil FOB North Sea		Light Sweet Crude Oil (40 API, 0.3%S) at Edmonton		Lloyd Blend Stream Quality at Hardisty		Heavy Crude Oil Proxy (12 API) at Hardisty		Medium Crude Oil (29 API, 2.0%S) at Cromer			Alberta Natural Gas Liquids (Then Current Dollars)		Edmonton
Year			Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Spec Ethane	Edmonton Propane	Edmonton Butane	Pentanes Plus
		$US/ $Cdn	$US/ bbl	$US/ bbl	$US/ bbl	$US/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl
1996	1.5	0.733	27.98	21.98	25.85	20.31	37.40	29.38	26.66	20.95	25.55	20.06	33.20	26.08	n/a	23.13	17.83	30.05
1997	1.6	0.722	25.83	20.62	24.21	19.32	34.90	27.85	25.04	19.98	18.06	14.41	29.72	23.72	n/a	19.41	19.76	30.91

20

		Bank of Canada Average	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		Lloyd Blend Stream Quality at Hardisty		Heavy Crude Oil Proxy (12 API) at Hardisty		Medium Crude Oil (29 API, 2.0%S) at Cromer			Alberta Natural Gas Liquids (Then Current Dollars)
Year	Inflla- tion %	Noon Exchange Rate	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Constant 2007	Then Current	Spec Ethane	Edmonton Propane	Edmonton Butane	Edmonton Pentanes Plus
		$US/ $Cdn	$US/ bbl	$US/ bbl	$US/ bbl	$US/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl	$Cdn/ bbl
1998	1.0	0.675	17.80	14.44	16.45	13.34	25.10	20.36	18.44	14.95	11.66	9.45	20.91	16.96	n/a	11.74	12.69	21.87
1999	1.7	0.673	23.53	19.25	21.99	17.99	33.78	27.63	27.07	22.14	23.83	19.49	31.01	25.37	n/a	15.86	18.65	27.64
2000	2.7	0.673	36.30	30.23	34.10	28.41	53.51	44.57	39.16	32.61	33.03	27.49	47.93	39.92	n/a	32.15	35.59	46.31
2001	2.5	0.646	30.41	26.00	29.09	24.87	46.13	39.44	27.46	23.47	19.62	16.77	36.95	31.58	n/a	31.92	31.25	42.48
2002	2.2	0.637	29.73	26.08	28.52	25.02	45.98	40.33	34.89	30.60	30.29	26.57	40.45	35.48	n/a	21.39	27.08	40.73
2003	2.8	0.716	34.64	31.07	31.74	28.47	48.70	43.66	34.79	31.18	29.31	26.26	41.88	37.55	n/a	32.14	34.36	44.23
2004	1.8	0.770	44.90	41.38	41.26	38.02	57.46	52.96	39.39	36.31	31.59	29.11	49.52	45.64	n/a	34.70	39.97	53.94
2005	2.2	0.826	60.27	56.58	58.74	55.14	73.52	69.02	45.84	43.03	36.29	34.07	60.47	56.77	n/a	43.04	51.80	69.57
2006	2.0	0.882	69.01	66.22	68.95	66.16	76.30	73.21	52.49	50.36	43.62	41.84	64.88	62.26	n/a	43.85	60.18	75.41
2007 (e)	2.1	0.935	73.82	72.24	74.04	72.46	78.69	77.02	54.30	53.15	45.33	44.37	67.74	66.30	n/a	46.85	58.35	77.33
2008 Q1	2.0	1.000	92.00	92.00	90.50	90.50	91.10	91.10	61.95	61.95	51.66	51.66	79.26	79.26	22.73	58.30	72.88	92.92
2008 Q2	2.0	1.000	92.00	92.00	90.50	90.50	91.10	91.10	65.59	65.59	56.39	56.39	79.26	79.26	22.73	58.30	72.88	92.92
2008 Q3	2.0	1.000	92.00	92.00	90.50	90.50	91.10	91.10	65.59	65.59	56.39	56.39	79.26	79.26	21.01	58.30	72.88	92.92
2008 Q4	2.0	1.000	92.00	92.00	90.50	90.50	91.10	91.10	61.95	61.95	51.66	51.66	79.26	79.26	24.46	58.30	72.88	92.92
2008 Full Year	2.0	1.000	92.00	92.00	90.50	90.50	91.10	91.10	63.77	63.77	54.02	54.02	79.26	79.26	22.73	58.30	72.88	92.92
2009	2.0	1.000	86.28	88.00	84.80	86.50	85.39	87.10	59.78	60.97	50.60	51.61	74.29	75.78	25.49	55.74	69.68	88.84
2010	2.0	1.000	80.74	84.00	79.30	82.50	79.87	83.10	55.91	58.17	47.28	49.19	69.49	72.30	25.66	53.18	66.48	84.76
2011	2.0	1.000	77.27	82.00	75.86	80.50	76.42	81.10	53.50	56.77	45.22	47.98	66.49	70.56	25.66	51.90	64.88	82.72
2012	2.0	1.000	75.76	82.00	74.37	80.50	74.92	81.10	52.45	56.77	44.33	47.98	65.18	70.56	25.66	51.90	64.88	82.72
2013	2.0	1.000	74.27	82.00	72.91	80.50	73.46	81.10	52.15	57.58	44.42	49.04	63.91	70.56	25.66	51.90	64.88	82.72
2014	2.0	1.000	72.81	82.00	71.48	80.50	72.01	81.10	51.85	58.39	44.48	50.09	62.65	70.56	26.35	51.90	64.88	82.72
2015	2.0	1.000	71.39	82.00	70.08	80.50	70.60	81.10	51.54	59.20	44.53	51.15	61.42	70.56	26.94	51.90	64.88	82.72
2016	2.0	1.000	70.00	82.02	68.72	80.52	69.23	81.12	51.23	60.03	44.56	52.21	60.23	70.57	27.52	51.91	64.89	82.74
2017	2.0	1.000	70.00	83.66	68.75	82.16	69.25	82.76	51.25	61.24	44.59	53.29	60.25	72.00	28.11	52.97	66.21	84.42
2018+	2.0	1.000	70.00	+2.0%/yr	68.75	+2.0%/yr	69.25	+2.0%/yr	51.25	+2.0%/yr	44.59	+2.0%/yr	60.25	+2.0%/yr	Escalate at 2.0% per year
Historical futures contract price is an average of the daily settlement price of the near month contract over the calendar month.

Table 2
GLJ Petroleum Consultants
Natural Gas and Sulphur Price Forecast
Effective January 1, 2008

	NYMEX Futures Contract		Midwest		Alberta Plant Gate					Saskatchewan Plant Gate			British Columbia
	Last 3  Day Price		Price @	AECO/NIT
			Chicago	Spot	Spot										Sulphur	Alberta
Year	Constant 2008 $	Then Current	Then Current	Then Current	Constant 2008 $	Then Current	ARP	Aggregator	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot Plant Gate	FOB Vancouver	Sulphur at Plant Gate
	$US/ mmbtu	$US/ mmbtu	$US/ mmbtu	$Cdn/ mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$US/LT	$Cdn/LT
1996	3.24	2.55	2.73	1.39	1.60	1.26	1.63	N/A	N/A	1.52	1.28	1.32	1.49	1.47	36.28	6.48
1997	3.30	2.63	2.75	1.85	2.13	1.70	1.97	N/A	N/A	1.85	1.75	1.71	1.90	1.98	34.75	5.12
1998	2.64	2.14	2.21	2.03	2.31	1.87	1.94	N/A	N/A	2.05	2.13	1.60	2.15	2.00	24.59	(6.51	)
1999	2.78	2.27	2.33	2.92	3.37	2.75	2.48	N/A	N/A	2.82	2.97	2.15	2.93	2.78	33.74	6.93
2000	4.69	3.91	3.96	5.08	5.91	4.93	4.50	4.44	N/A	4.79	5.15	4.15	5.06	4.88	38.14	13.59
2001	5.13	4.38	4.45	6.23	7.11	6.07	5.41	4.97	5.29	5.72	6.20	4.57	6.32	6.29	18.29	(14.67	)
2002	3.71	3.25	3.25	4.04	4.43	3.88	3.88	3.64	3.66	4.04	4.08	2.68	4.18	3.93	29.38	3.04
2003	6.07	5.44	5.46	6.66	7.24	6.49	6.13	5.87	6.15	6.41	6.68	4.66	6.45	6.32	59.81	39.83
2004	6.61	6.09	6.13	6.88	7.27	6.70	6.31	6.16	6.39	6.48	6.85	5.26	6.56	6.45	62.99	38.61
2005	9.11	8.55	8.24	8.58	8.96	8.42	8.30	8.27	8.29	8.36	8.31	7.13	8.22	8.12	63.50	33.77
2006	7.57	7.26	6.93	7.16	7.25	6.96	6.57	6.36	6.34	6.67	6.97	6.27	6.58	6.45	55.07	19.27

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	NYMEX Futures Contract		Midwest		Alberta Plant Gate					Saskatchewan Plant Gate			British Columbia
	Last 3  Day Price		Price @
			Chicago	AECO/NIT Spot	Spot										Sulphur	Alberta
Year	Constant 2008$	Then Current	Then Current	Then Current	Constant 2008 $	Then Current	ARP	Aggre- gator	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot Plant Gate	FOB Vancouver	Sulphur at Plant Gate
	$US/ mmbtu	$US/ mmbtu	$US/ mmbtu	$Cdn/ mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$mmbtu	$US/LT	$Cdn/LT
2007 (e)	7.07	6.92	6.83	6.65	6.57	6.43	6.14	6.11	5.86	6.07	6.38	6.52	6.39	6.23	81.62	41.34
2008 Q1	7.50	7.50	7.40	6.75	6.53	6.53	6.44	6.17	5.92	6.57	6.69	6.90	6.55	6.35	120.00	77.00
2008 Q2	7.50	7.50	7.40	6.75	6.53	6.53	6.44	6.17	5.92	6.57	6.69	6.90	6.55	6.35	120.00	77.00
2008 Q3	7.00	7.00	6.90	6.25	6.04	6.04	5.95	5.70	5.44	6.08	6.19	6.40	6.05	5.86	120.00	77.00
2008 Q4	8.00	8.00	7.90	7.25	7.03	7.03	6.93	6.63	6.40	7.06	7.19	7.40	7.05	6.85	120.00	77.00
2008 Full Year	7.50	7.50	7.40	6.75	6.53	6.53	6.44	6.17	5.92	6.57	6.69	6.90	6.55	6.35	120.00	77.00
2009	8.25	8.25	8.20	7.55	7.18	7.33	7.24	6.99	6.68	7.37	7.49	7.70	7.35	7.15	90.00	47.00
2010	8.25	8.25	8.25	7.60	7.09	7.37	7.31	7.11	6.73	7.44	7.54	7.70	7.40	7.20	70.00	27.00
2011	8.25	8.25	8.35	7.60	6.95	7.37	7.31	7.11	6.83	7.44	7.54	7.70	7.40	7.20	70.00	27.00
2012	7.62	8.25	8.35	7.60	6.81	7.37	7.31	7.11	6.83	7.44	7.54	7.70	7.40	7.20	70.00	27.00
2013	7.47	8.25	8.35	7.60	6.68	7.37	7.31	7.11	6.83	7.44	7.54	7.70	7.40	7.20	70.00	27.00
2014	7.50	8.45	8.55	7.80	6.72	7.57	7.51	7.30	7.02	7.64	7.74	7.90	7.60	7.40	71.40	28.40
2015	7.50	8.62	8.72	7.97	6.74	7.74	7.67	7.47	7.18	7.80	7.91	8.07	7.77	7.57	72.83	29.83
2016	7.50	8,79	8.89	8.14	6.75	7.91	7.84	7.63	7.34	7.97	8.05	8.24	7.94	7.73	74.28	31.28
2017	7.50	8.96	9.06	8.31	6.76	8.08	8.01	7.79	7.51	8.14	8.22	8.41	8.11	7.90	75.77	32.77
2018	7.50	9.14	9.24	8.48	6.76	8.24	8.17	7.95	7.66	8.30	8.38	8.58	8.27	8.06	77.29	33.43
2019+	7.50	+2.0%/yr	+2.0%/yr	+2.0%/yr	6.76	+2.0%/yr	Escalate at 2.0%/yr								+2.0%/yr

Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate.

The plant gate price represents the price before raw gas gathering and processing charges are deducted.

AECO – C Spot refers to the one month price averaged for the year.

Historical futures contract price is an average of the daily settlement prices over the last 3 days of the near month contract.

The weighted average realized sales prices by the Corporation for the year ended December 31, 2007 was $6.72/Mcf for natural gas, $67.95/Bbl for crude oil and NGL’s.

RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

Reserves Reconciliation

The following table sets forth a reconciliation of the Corporation’s total net proved, probable and total net proved plus probable reserves as at December 31, 2007 against such reserves as at December 31, 2006 based on forecast price and cost assumptions.

RECONCILIATION OF COMPANY GROSS RESERVES AT DECEMBER 31, 2007
BY PRINCIPAL PRODUCT TYPE

FORECAST PRICES AND COSTS

	Light and Medium Oil			Unconventional Gas (CBM)						Conventional Natural Gas					Natural Gas Liquids						BOE
Factors	Net Proved	Net Probable	Net Proved Plus Probable	Net Proved		Net Probable		Net Proved Plus Probable		Net Proved	Net Probable		Net Proved Plus Probable		Net Proved		Net Probable		Net Proved Plus Probable		Net Proved	Net Probable		Net Proved Plus Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)		(MMcf)		(MMcf)		(MMcf)	(MMcf)		(MMcf)		(Mbbl)		(Mbbl)		(Mbbl)		(Mboe)	(Mboe)		(Mboe)
Dec. 31, 2006	835	647	1,482	4,756		4,057		8,813		20,119	9,030		29,149		212		111		323		5,193	2,939		8,132
Extensions	61	32	93	2,193		2,634		4,827		3,214	1,247		4,461		41		16		57		1,003	695		1,698
Improved Recovery	—	—	0	58		(37	)	21		210	80		290		3		1		4		48	8		56
Technical Revisions	86	163	248	(1,956	)	(1,457	)	(3,413	)	1,591	(1,644	)	(73	)	(20	)	(41	)	(61	)	5	(399	)	(394	)

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	Light and Medium Oil					Unconventional Gas (CBM)					Conventional Natural Gas					Natural Gas Liquids					BOE
Factors	Net Proved		Net Probable	Net Proved Plus Probable		Net Proved		Net Probable	Net Proved Plus Probable		Net Proved		Net Probable	Net Proved Plus Probable		Net Proved		Net Probable	Net Proved Plus Probable		Net Proved		Net Probable	Net Proved Plus Probable
	(Mbbl)		(Mbbl)	(Mbbl)		(MMcf)		(MMcf)	(MMcf)		(MMcf)		(MMcf)	(MMcf)		(Mbbl)		(Mbbl)	(Mbbl)		(Mboe)		(Mboe)	(Mboe)
Discoveries	—		—	—		—		—	—		—		—	—		—		—	—		—		—	—
Acquisitions	—		—	—		—		—	—		—		—	—		—		—	—		—		—	—
Dispositions	—		—	—		—		—	—		—		—	—		—		—	—		—		—	—
Economic Factors	8		6	15		—		—	—		—		—	—		—		—	—		8		6	15
Production	(173	)	—	(173	)	(366	)	—	(366	)	(4,486	)	—	(4486	)	(44	)	—	(44	)	(1026	)	—	(1,026	)
Dec. 31, 2007	817		848	1665		4,685		5,197	9,882		20,648		8,693	29,341		192		87	279		5,231		3,250	8,481

UNDEVELOPED RESERVES

Proved and probable undeveloped reserves have been estimated in accordance with procedures and standards contained in the COGE Handbook.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. The Corporation’s reserves are evaluated by GLJ, an independent engineering firm.

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 table below sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant prices and costs and forecast prices and costs) and proved plus probable reserves (using forecast prices and costs only).

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	Constant Prices and Costs	Forecast Prices and Costs
	Total Proved Reserves	Total Proved Reserves	Total Proved Plus Probable Reserves
	(M$)	(M$)	(M$)
2008	7,146	7,146	16,067
2009	2,140	2,183	3,458
2010	—	—	—
Remaining Years	75	100	35
Total Undiscounted	9,371	9,429	19,624
Total Discounted 10% Per Year	8,704	8,748	18,352

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 could 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, 2007.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	79	59.6	28	17.9	269	125	113	68
Saskatchewan	—	—	—	—	—	—	—	—
Total	79	59.6	28	17.9	269	125	113	68

PROPERTIES WITH NO ATTRIBUTED RESERVES

The following table sets out the Corporation’s undeveloped land holdings as at December 31, 2007.

	Undeveloped Acres
	Gross	Net
British Columbia	1,974	694
Alberta	105,060	85,847
Saskatchewan	40	40
Offshore Nova Scotia(1)	1,234,546	1,234,546
Offshore Trinidad and Tobago	102,292	71,604
Total	1,443,912	1,392,731

Note:

(1)The Corporation can extend the expiration dates under various terms.

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EXPIRATIONS AND WORK COMMITMENTS

The following table sets forth the expirations and work commitment for the undeveloped lands of the Corporation, as at December 31, 2007:

Work Commitments Offshore Nova Scotia (Marquis, Mariner, Mayflower, Marauder, Marconi)

Gross Acres	1,234,546
Net Acres	1,234,546
Work Expenditure Commitment	$	55,069,046
Deposits Tendered	$	14,017,262

Note:In Trinidad and Tobago, for Block 5(c), there is a confidential work commitment guarantee that is part of the confidential PSC between the Government of the Republic of Trinidad and Tobago and Canadian Superior. It is anticipated that this work commitment will be more than fully met during the ongoing drilling program.

UNDEVELOPED LAND DUE TO EXPIRE

The following table represents the undeveloped land of the Corporation due to expire in 2008:

	Gross Undeveloped Acres	Net Undeveloped Acres
Alberta	11,553	8,040
British Columbia	—	—
Offshore Nova Scotia*	1,082,552	1,082,552
Total	1,094,105	1,090,612

* The Corporation can extend the expiration dates under various terms.

FORWARD CONTRACTS AND FUTURE COMMITMENTS

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. At December 31, 2007, the Corporation had no contracts in place.

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

The following table represents the Corporation’s projected abandonment costs for future drilling, in thousands of dollars, using constant pricing:

	Annual Abandonment Costs
	Proved Producing	Total Proved	Total Proved Plus Probable
2008	215	215	165
2009	303	328	188
2010	351	351	224
2011	182	220	276
2012	508	547	216
2013	270	358	277

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	Annual Abandonment Costs
	Proved Producing	Total Proved	Total Proved Plus Probable
2014	417	438	266
2015	351	400	449
2016	277	277	372
2017	171	203	323
2018	150	175	322
2019	149	240	178
Subtotal	3,344	3,796	3,255
Remainder	1,247	1,732	2,996
Total	4,591	5,528	6,251
10% Discounted	2,352	2,690	2,338

The following table represents the Corporation’s projected abandonment costs for future drilling, in thousands of dollars, using forecast prices:

	Annual Abandonment Costs
	Proved Producing	Total Proved	Total Proved Plus Probable
2008	195	195	144
2009	251	277	122
2010	340	340	254
2011	398	439	328
2012	441	484	340
2013	299	396	199
2014	450	523	284
2015	380	435	535
2016	346	346	427
2017	192	231	385
2018	420	450	380
2019	227	340	231
Subtotal	3,940	4,456	3,630
Remainder	1,474	2,155	4,566
Total	5,413	6,611	8,195
10% Discounted	2,624	3,027	2,710

The Corporation estimates the costs to abandon and reclaim all its shut in and producing wells, facilities, gas plants and pipelines. The Corporation’s model for estimating the amount and timing of future abandonment and reclamation expenditures was done on an operating area level. Estimated expenditures for each operating area are based on the Alberta Energy and Utilities Board methodology, which details the cost of abandonment and reclamation in each specific geographic region. Each region was assigned an average cost per well to abandon and reclaim the wells in that area. Facility reclamation costs are scheduled to be incurred in the year following the end of the reserve life of its associated reserves. 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. As at December 31, 2007, the Corporation expected to incur reclamation and abandonment costs in respect of 549 gross (331.4 net) wells located on its properties and assets.

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TAX HORIZON

The Corporation does not expect to be cash taxable in 2008 or 2009 and with continued exploration activity, we could push our tax horizon further.

DRILLING ACTIVITY

The following table summarizes the Corporation’s drilling results for the year ended December 31, 2007.

	2007
	Gross	Net
Oil	4	3.8
Natural Gas (1)	54	11.8
Coal Bed Methane	8	2.4
Dry and Abandoned	7	7.0
Total	73	25.0

Note:

(1)Natural Gas wells includes 38 wells drilled to earn a 10% GORR and two wells to earn a 15% GORR.

PRODUCTION ESTIMATES

The following tables set out the volume of the Corporation’s production estimated using both constant and forecast prices and costs for the year ended December 31, 2007, which is reflected in the estimate of future net revenue disclosed in the tables contained under “Disclosure of Reserves Data”.

	2007 Estimated Daily Production
	Light and Medium Oil		Natural Gas		Natural Gas Liquids		Oil Equivalent
Entity Description	W.I.	Net	W.I.	Net	W.I.	Net	W.I.	Net
	bbl/d	bbl/d	mcf/d	mcf/d	bbl/d	bbl/d	bbl/d	bbl/d
PROVED PRODUCING
Aerial-Michichi	46	40	3,238	2,593	38	25	623	498
Other Properties	382	349	9,558	7,375	78	51	2,053	1,630
TOTAL: PROVED PRODUCING	428	389	12,795	9,968	115	76	2,676	2,127
PROVED DEVELOPED NON-PRODUCING
Aerial-Michichi	—	—	54	46	1	—	10	8
Other Properties	5	5	505	429	5	4	94	80
TOTAL: PROVED DEVELOPED NON-PRODUCING	5	5	559	475	5	4	104	88
PROVED UNDEVELOPED
Aerial-Michichi	—	—	—	—	—	—	—	—
Other Properties	—	—	200	195	—	—	33	33
TOTAL: PROVED UNDEVELOPED	—	—	200	195	—	—	33	33
TOTAL PROVED
Aerial-Michichi	46	40	3,292	2,639	38	25	633	506
Other Properties	388	354	10,263	7,998	83	55	2,181	1,742

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	2007 Estimated Daily Production
	Light and Medium Oil		Natural Gas		Natural Gas Liquids		Oil Equivalent
Entity Description	W.I.	Net	W.I.	Net	W.I.	Net	W.I.	Net
	bbl/d	bbl/d	mcf/d	mcf/d	bbl/d	bbl/d	bbl/d	bbl/d
TOTAL: TOTAL PROVED	433	394	13,555	10,637	121	81	2,813	2,248
TOTAL PROBABLE
Aerial-Michichi	5	4	204	140	2	2	42	29
Other Properties	12	11	914	675	8	6	173	129
TOTAL: TOTAL PROBABLE	17	15	1,118	814	11	7	215	158
TOTAL PROVED PLUS PROBABLE
Aerial-Michichi	51	45	3,496	2,779	41	27	674	535
Other Properties	400	365	11,177	8,673	91	61	2,354	1,871
TOTAL: TOTAL PROVED PLUS PROBABLE	451	409	14,673	11,451	132	88	3,028	2,406

PRODUCTION HISTORY, PRICES RECEIVED AND CAPITAL EXPENDITURES

The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

	Quarter Ended 2007
	2007
	Dec. 31		Sept. 30		June 30		Mar. 31
Average Daily Production(1)
Light Medium Crude Oil & NGL’s (Bbls/d)	636		516		656		566
Gas (Mcf/d)	15,366		12,838		11,802		13,984
Combined (BOE/d)	3,197		2,656		2,623		2,897
Average Price Received
Light Medium Crude Oil & NGL’s/Bbl After Hedging	$	80.82	$	76.81	$	57.38	$	56.81
Gas ($/Mcf)	$	5.88	$	5.59	$	7.83	$	7.71
Combined ($/BOE) After Hedging	$	44.33	$	41.95	$	49.56	$	48.32
Royalties Paid ($/BOE)	$	6.29	$	6.61	$	8.86	$	8.88
Operating Expenses ($/BOE)	$	11.53	$	10.74	$	7.70	$	7.95
Netback Received ($/BOE)(2)	$	26.51	$	24.60	$	32.36	$	31.48

Notes:

(1)Before deduction of royalties.

(2)Netbacks are calculated by subtracting royalties and operating costs from revenues.

For the year ended December 31, 2007, net average daily production from the Corporation’s Aerial/Michichi properties was 594 bbls/d light oil and 13,496 mmcf/d natural gas, or 2,843 boe/d.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, Saskatchewan, Nova Scotia and Trinidad and Tobago, 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 from how they would affect other oil and gas

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companies of similar size. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

PRICING AND MARKETING - OIL AND NATURAL GAS

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council.

The governments of Alberta, British Columbia, Saskatchewan and Nova Scotia also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

PIPELINE CAPACITY

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas.

THE NORTH AMERICAN FREE TRADE AGREEMENT

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, United States of America, and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer

29

disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

PROVINCIAL ROYALTIES AND INCENTIVES

General

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, 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, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the Western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

The Canadian federal corporate income tax rate levied on taxable income is 22.1% effective January 1, 2007 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the 2006 Federal Budget, and not withdrawn in the 2007 Federal Budget, the federal corporate income tax rate will decrease to 19% in three steps: 20.5% on January 1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010.

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil in “new oil” and “old oil” depending on when the oil pools were discovered. If discovered prior to March 31, 1974 it is considered “old oil”, if discovered after March 31, 1974 and before September 1, 1992, it is considered “new oil”.

The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced

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from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program (“ARTC”) was to be eliminated, effective January 1, 2007. The programs affected by this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy Technologies Program (the “IETP”) which is intended to promote the producers’ investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions which are presumed to reduce financial risk. Alberta Energy will be the one to decide which projects qualify and the level of support that will be provided. The deadline for the IETP’s third round of applications was May 31, 2007.

On February 16, 2007, the Alberta Government announced that a review of the province’s royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil, gas and oil sands will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The purpose of this process was to ensure that Albertans are receiving a fair share from energy development through royalties, taxes and fees.

On October 25, 2007, the Government of Alberta unveiled a new royalty regime. The new regime will introduce new royalties for conventional oil, natural gas and bitumen effective January 1, 2009 that are linked to price and production levels and will apply to both new and existing oil sands projects and conventional oil and gas activities.

Royalties payable pursuant to Crown petroleum and natural gas leases are royalties, assessed on a sliding scale where the rate changes depending on oil or natural gas prices and the level of production. As described above, the maximum Crown royalties currently payable in the case of conventional oil range from 30% to 35%. In the case of natural gas, current Crown royalties range from 5% to 35% and from 15% to 50% in the case of natural gas liquids.

The new royalty formula for conventional oil will operate on a sliding rate formula containing separate elements that account for oil price and well production. Royalty rates for conventional oil will range up to 50%, with rate caps once the price of conventional oil reaches $120 per barrel.

Under the new royalty regime, natural gas royalties will be set by a sliding rate formula sensitive to price and production volume. New natural gas royalty rates will range from 5% to 50% with rate caps once the price of natural gas reaches $17.50/mmbtu. Royalties for natural gas liquids will be set at 40% for pentanes and 30% for butanes and propane.

The implementation of the proposed changes to the royalty regime in Alberta is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof.

The Corporation expects the economics of production from its properties will be acceptable under the new royalties. This is due, in part, to the potential decreased industry activity leading to reduced costs of services, which would offset the potential nominal decline in rates of return due to a higher royalty.

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British Columbia

Producers of oil and natural gas in the Province of British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m3 produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands (“Strategy”). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities.

In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:

Royalty credits of up to $30 million annually towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry.

Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season.

On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province’s strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world’s leader in sustainable environmental management. With regards to the oil and gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coal bed gas; and (vii) new the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves.

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Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered “heavy oil”, “southwest designated oil”, or “non-heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil” introduced October 1, 2002, “third tier oil”, “new oil”, or “old oil”) of oil production are applicable to each of the three crude oil types.

The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all “fourth tier oil” to 20% for “old oil”. Marginal royalty rates are 30% for all “fourth tier oil” to 45% for “old oil”.

The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are “fourth tier gas” introduced October 1, 2002, “third tier gas”, “new gas”, and “old gas”. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for “fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45% for “old gas”.

On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan:

A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic metres in a month.

A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent.

The elimination of the re entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002, will receive the “fourth tier” royalty/ tax rates and new incentive volumes.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate (“RTR”) as a response to the federal government disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes.

As of January 1, 2007, the remaining balance of any unused RTR will be limited in its carry forward to five years since the federal government had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.

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 from two years, 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.

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ENVIRONMENTAL REGULATION

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.

Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”), which came into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry. No additional expenses are foreseen that are associated with complying with the new regulations. The Corporation will be committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment, and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

British Columbia’s Environmental Assessment Act became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process.

In December, 2002, the Government of Canada ratified the Kyoto Protocol (“Protocol”). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 “business-as-usual” levels between 2008 and 2012. Given revised estimates of Canada’s normal emissions levels, this target translates into an approximately 40% gross reduction in Canada’s current emissions. It remains uncertain whether the Kyoto target of 6% below 1990 emission levels will be enforced in Canada. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using an “intensity based” approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. As details of the implementation of this legislation have not yet been announced, the effect on our operations cannot be determined at this time.

TRENDS

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business.

The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply-demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility.

Crude oil is influenced by the world economy, Organization of the Petroleum Exporting Countries’ ability to adjust supply to world demand, and weather. Crude oil prices have been kept high by political events

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causing disruptions in the supply of oil, increasing demand from countries like China and India that are experiencing rapid industrial growth, concern over potential supply disruptions triggered by unrest in the Middle East and more recently have been impacted by weather and increased storage levels. The economy of the United States has cooled and value of its’ currency has declined, and it is expected that its’ demand for oil will also decline. Given the worldwide demand for oil various political events can trigger large fluctuations in price levels.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

A second trend within the Canadian oil and gas industry is the fairly consistent “renewal” of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel. The Corporation will have to compete with these companies and others to attract qualified personnel.

A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Protocol, and other environmental initiatives, will have on the sector. On October 31, 2006 the federal government imposed a distribution tax on distributions to investors in income trusts and publicly traded partnerships (also known as “specified investment flow-through” entities, or “SIFTs”), and thereby effectively eliminated the tax efficacy of SIFTS as investment vehicles.  Existing SIFTs were generally grandfathered until 2011.  These business structures had been attractive to investors primarily because distributions were not taxed prior to receipt by the investors, which enabled the investors to obtain a greater return on their invested funds. Under the October 31, 2006 distribution tax, SIFTs will be liable for tax at a rate consistent with the taxes currently imposed on corporations commencing in January 2011, provided that the SIFT experiences only “normal growth” and no “undue expansion” before then, in which case the tax could be imposed prior to the January 2011 deadline. Although the October 31, 2006 distribution tax will not affect the method in which the Corporation will be taxed, it may have an impact on the ability of a SIFT to purchase producing assets from junior oil and gas companies (as well as the price that a SIFT is willing to pay for such an acquisition) thereby affecting exploration and production companies’ ability to be sold to a SIFT, a plan which has been a common “exit strategy” in recent years for small to mid-sized oil and gas companies. This may be a benefit for the Corporation as it will compete with SIFTs for the acquisition of oil and gas properties from junior producers. However, it may also limit the Corporation’s ability to sell producing properties or pursue an exit strategy.

Generally during the past year the exploration activity slowdown that followed the announcement of the October 31, 2006 distribution tax, and the changes to the Alberta royalty regime, has largely been reversed as a result of increased commodity prices.  Access to capital for oil and gas exploration and for acquisitions is generally good, however the competitive nature of the oil and gas industry will cause opportunities for equity financings to continue to be selective. The Corporation will have to compete with existing companies and with numerous new companies and their new management teams and development plans in its access to capital. The Corporation may have to rely on internally generated funds to conduct their exploration and developmental programs.

RISK FACTORS

A number of factors, including but not limited to, those discussed in this section could cause the Corporation’s results to differ materially from its expectations.

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EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS

An investment in the Corporation’s securities would be speculative due to the nature of the Corporation’s involvement in the exploration, development and production of oil and natural gas and its present stage of development.

Oil and natural gas exploration involves a high degree of risk and there is no assurance that expenditures made on future exploration by the Corporation will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

Management will evaluate exploration and development prospects on an ongoing basis in a manner consistent with industry standards. The long-term commercial success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. No assurance can be given that the Corporation will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Corporation may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While close 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.

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial condition.

SUBSTANTIAL CAPITAL REQUIREMENTS AND LIQUIDITY

The Corporation anticipates that it will make 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, the Corporation may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation. Moreover, future activities may require the Corporation to alter its capitalization significantly. 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.

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ADDITIONAL FUNDING REQUIREMENTS

The Corporation’s cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time to time, the Corporation may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Corporation’s revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Corporation’s ability to expend the necessary capital to replace its reserves or to maintain its production. If the Corporation’s cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing 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. Neither the Corporation’s articles nor its by-laws limit the amount of indebtedness that the Corporation may incur. The level of the Corporation’s indebtedness from time to time could impair the Corporation’s ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.

PRICES, MARKETS AND MARKETING OF CRUDE OIL AND NATURAL GAS

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond the control of the Corporation. World prices for oil and natural gas have fluctuated widely in recent years. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and natural gas prices, leading to a reduction in the volume of the Corporation’s oil and gas reserves. The Corporation might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Corporation’s future net production revenue, causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to the Corporation are in part determined by the borrowing base of the Corporation. A sustained material decline in prices from historical average prices could limit the Corporation’s borrowing base, therefore reducing the bank credit available to the Corporation, and could require that a portion of any then existing bank debt of the Corporation be repaid.

In addition to establishing markets for its oil and natural gas, the Corporation must also successfully market its oil and natural gas to prospective buyers. The marketability and price of oil and natural gas which may be acquired or discovered by the Corporation will be affected by numerous factors beyond its control. The Corporation will be affected by the differential between the price paid by refiners for light quality oil and the grades of oil produced by the Corporation. The ability of the Corporation to market its natural gas may depend upon its ability to acquire space on pipelines which deliver natural gas to commercial markets. The Corporation will also likely be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and related to operational problems with such pipelines and facilities and extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and other aspects of the oil and natural gas business.

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 the Corporation has obtained 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

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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

Litigation may be time consuming, expensive, and distracting from the conduct of our business, and the outcome of litigation may be difficult to predict. The Corporation is unable to determine the ultimate aggregate amount of monetary liability or financial impact in these legal matters, which unless otherwise specified, seek damages of indeterminate amounts. The Corporation cannot determine whether these matters will, individually or collectively, have a material adverse effect on our 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 our cash position. The Corporation, and any of our named directors or officers, intend to vigorously defend these actions suits, claims, proceedings and investigations. The Corporation may in the future be subject to  other litigation arising in the normal course of our business.

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 national, provincial and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and 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 may result in the imposition of fines and penalties, some of which may be material. The Corporation believes that it is in substantial compliance with existing legislation. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. 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 the Corporation’s financial condition, results of operations or prospects.

In 2002, the Government of Canada ratified the Kyoto Protocol, which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada’s ability to meet these targets and the Government’s strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of the Corporation. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Corporation and its operations and financial condition.

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

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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.

EXCHANGE RATE RISKS

The Canadian to U.S. dollar exchange rate has strengthened and may fluctuate over time. As product prices are generally U.S. dollar based, the Corporation’s exposure to currency exchange rate risks are primarily limited to Canadian capital expenditures, Canadian operating costs and the majority of the Corporation’s general and administrative expenses which are paid for in Canadian dollars.

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.

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. Without the continual addition of new reserves, any existing reserves the Corporation may have at any particular time and the production therefrom will decline overtime as such existing reserves are exploited. 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.

RELIANCE ON OPERATORS AND KEY EMPLOYEES

To the extent the Corporation is not the operator of its oil and natural gas properties, the Corporation will be dependent on such operators for the timing of activities related to such properties and will largely be unable to direct or control the activities of the operators. In addition, the success of the Corporation will be

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largely dependent upon the performance of its management and key employees. The Corporation has no key-man insurance policies, and therefore there is a risk that the death or departure of any member of management or any key employee could have a material adverse effect on the Corporation.

PERMITS AND LICENSES

The operations of the Corporation may require licenses and permits from various governmental authorities. There can be no assurance that the Corporation will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at its projects.

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, British Columbia and Saskatchewan 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

The Corporation has not obtained a legal opinion as to the title to its freehold properties and cannot guarantee or certify that a defect in the chain of title may not arise to defeat the Corporation’s interest in certain of such properties. Remediation of title problems could result in additional costs and litigation. If title defects are unable to be remedied, the Corporation may lose some of its interest in the disputed properties resulting in reduced production.

Although title reviews have been conducted for past purchases, and may be conducted prior to the purchase of other oil and natural gas producing properties or the commencement of drilling wells, such reviews may not discover unforeseen title defects that could adversely affect the Corporation’s title to or proportionate interest in the property or entitlement to revenue from the property.

MULTI-JURISDICTIONAL LEGAL RISKS

The Corporation is incorporated under the laws of the Province of Alberta, Canada, and all but one 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 Securities Exchange Act of 1934, as amended (United States). Furthermore, it may be difficult for investors to enforce judgments

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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.

CORPORATE MATTERS

To date, the Corporation has not declared any dividends payable on its outstanding common shares. The Board of Directors of the Corporation will consider the Corporation’s dividend policy from time to time to assess whether the declaration of dividends payable on its outstanding common shares is appropriate. 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 Business Corporations Act (Alberta).

DIVIDENDS

To date, the Corporation has not declared any dividends payable on its outstanding Common Shares. The Board of Directors of the Corporation will consider the Corporation’s dividend policy from time to time to assess whether the declaration of dividends payable on its outstanding common shares is appropriate.

DESCRIPTION OF CAPITAL STRUCTURE

The Corporation’s authorized share capital consists of an unlimited number of Common Shares and an unlimited number of Preferred Shares.

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 share. The holders of Common Shares are entitled to receive such dividends as the Board of Directors may declare and, upon liquidation, to receive such assets of Canadian Superior as are distributable to holders of Common Shares.

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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 directors of the Corporation. The directors are authorized, before the issue of the series, to determine the designation, rights, restrictions, conditions and limitations attaching to the Preferred Shares of each series. The Preferred Shares of each series rank equally with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up and in priority to the Common Shares and any other shares of the 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.

SHAREHOLDER RIGHTS PLAN

The Corporation has adopted a shareholder rights plan in accordance with the Rights Plan Agreement. Pursuant to the terms of the Rights Plan Agreement, the Rights Plan shall have a term of 10 years, expiring January 22, 2011, provided that the Rights Plan is re-approved by the Shareholders of the Corporation at every third annual meeting of Shareholders. The Rights Plan was last re-approved at the annual and special meeting of Shareholders held on April 27, 2007.

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 of the Corporation without undue pressure, (b) allow competing bids to emerge and (iii) give the board of directors of the Corporation 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 of directors.

Under the Rights Plan, one right (a “Right”) is attached to each Common Share in the capital of the Corporation. 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, on payment of $15, Common Shares with a market value of $30. 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 Board of Directors 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.

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This summary is qualified in its entirety by reference to the Rights Plan Agreement. Shareholders may obtain a copy of the Rights Plan Agreement on written request to the Corporate Secretary of the Corporation.

MARKET FOR SECURITIES

TRADING PRICE AND VOLUME

The Common Shares of Canadian Superior are listed and posted for trading on the Toronto Stock Exchange and the American Stock Exchange under the symbol “SNG”. The following table sets forth the reported high, low and close sale prices and volume of trading of the Common Shares as reported by the Toronto Stock Exchange for the periods indicated.

		High ($)	Low ($)	Close ($)	Volume
2007	January	2.88	2.29	2.83	2,039,800
	February	2.44	2.11	2.33	1,310,300
	March	3.09	2.56	3.00	2,515,900
	April	2.98	2.74	2.98	3,732,400
	May	3.89	2.79	3.98	3,479.300
	June	3.85	3.25	3.78	2,238,800
	July	3.66	2.86	3.62	1,815,400
	August	3.18	2.80	3.15	1,898,500
	September	3.09	2.52	3.04	2,066,100
	October	3.65	2.79	3.37	2,867,900
	November	3.13	2.55	3.08	1,361,000
	December	3.46	2.52	3.29	1,471,500
2008	January	4.05	2.90	3.80	4,715,900
	February	3.74	3.18	3.64	3,446,700

DIRECTORS AND OFFICERS

NAMES, OCCUPATIONS AND SECURITY HOLDERS

The following sets forth the names and municipalities of residence of the directors and officers of the Corporation, their offices or positions with the Corporation, their principal occupations during the past five years and the period or periods during which each director has served as a director. The term of the directors’ office expires at the next annual general meeting of the Corporation. Officers of the Corporation are appointed by the directors until they resign or until their successors are appointed.

Name and Municipality of Residence	Office or Position	Director Since	Present and Principal Occupation During the Last Five Years
Leigh Bilton Calgary, Alberta	Non-Executive Vice Chairman	Not Applicable	Manager of all Canadian Superior Western Canadian operations from 2001 to present.
Charles Dallas (1),(4) Innisfail, Alberta	Director	2000	Rancher and independent businessman.
Thomas J. Harp(2),(5) Calgary, Alberta	Director	2000	President of Harp Resources Ltd., a private resources company.

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Name and Municipality of Residence	Office or Position	Director Since	Present and Principal Occupation During the Last Five Years
Gregory S. Noval(3),(4),(5) Turner Valley, Alberta	Executive Chairman of the Board	1996	Executive Chairman of the Corporation from June 26, 2007 to present. Prior thereto, was Chairman and Chief Executive Officer of Canadian Superior.
Michael E. Coolen(4) Halifax, Nova Scotia	President, Chief Operating Officer and a Director	2006	President and Chief Operating Officer of the Corporation from April 10, 2006 to present. Vice President, East Coast Operations of the Corporation from March 12, 2004 to April 10, 2006. Prior thereto, was a Director of East Coast Operations of the Corporation.
Alexander Squires(1),(3) Toronto, Ontario	Director	2004	Managing Partner and Director of Brant Securities Ltd., an independent full service securities firm.
Craig McKenzie Calgary, Alberta	Chief Executive Officer and a Director	2007	CEO of the Corporation from October 1, 2007 to present. Prior thereto, was President of BG Trinidad and Tobago, BG Group PLC.
Robb D. Thompson Calgary, Alberta	Chief Financial Officer	Not applicable	Chief Financial Officer of the Corporation from January 31, 2008 to present. Prior thereto, Mr. Thompson was CFO of Berkana Energy Inc. from January 15, 2007 and CEO of Dynetek Industries Ltd. from September 2000.
Kaare Idland(2),(5) Red Deer, Alberta	Director	2005	Independent businessman. Formerly President and Chief Executive Officer of Kidd Construction Ltd., an independent oil and gas construction service companies.
Richard Watkins(1),(2),(3) Houston, Texas	Director	2006	Energy consultant

Notes:

(1)   Member of the Corporation’s Audit Committee.

(2)   Member of the Corporation’s Compensation Committee.

(3)   Member of the Corporation’s Disclosure Committee

(4)   Member of the Corporation’s Special Projects Committee.

(5)   Member of the Corporation’s Reserves Committee.

As at December 31, 2007, the number of Common Shares beneficially owned, directly or indirectly, or controlled by the directors and executive officers of the Corporation, as a group, was 2,583,387 Common Shares, being 1.9% of the outstanding Common Shares of the Corporation.

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

Other than as described below, to the knowledge of management of the Corporation, there has been no director or officer, or any shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation, that is, as at the date hereof, or, within the 10 years before the date of this Annual Information Form:

1.has been a director or officer of any issuer that, while that person was acting in that capacity;

(a)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;

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(b)was subject to an event that resulted, after the director or officer ceased to be a director or officer, in the issuer being subject of a cease trade order 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;

(c)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.

2.has become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or shareholder.

Further, other than as described below, to the knowledge of management of the Corporation, no director or officer of the Corporation, or any shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation, has been subject to:

1.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 the securities regulatory authority; or

2.any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

On October 15, 1997, the ASC and OSC issued orders relating to a settlement agreement entered into by Canadian 88, Mr. Noval and two other parties (the “Respondents”) in respect of their involvement in a take-over bid made in early 1997 by Canadian 88 for the common shares of Morrison Petroleums Ltd., a corporation whose common shares were listed on the TSX and the Montreal Stock Exchange. In a joint submission with the ASC and the OSC, the Respondents agreed that their actions and the public statements of Mr. Noval on behalf of Canadian 88 were contrary to the public interest. Under the terms of the settlement agreement, Canadian 88 was required to make a $200,000 payment to the ASC and was reprimanded by the OSC. Mr. Noval was prohibited from trading securities and from relying on most exemptions available under the securities legislation of Alberta and Ontario for a period of 12 months.

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 Business Corporations Act (Alberta), 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.

LEGAL PROCEEDINGS

The Corporation is involved in various claims and litigation arising in the ordinary course of its business. In the opinion of Canadian Superior, the various claims and litigation arising therefrom are not expected to have a material adverse effect on the Corporation’s financial position. The Corporation also maintains insurance to address any unforeseen claims.

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INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Within the last three financial years or the current financial year of the Corporation, other than as disclosed herein, none of the directors or officers of the Corporation or any person that beneficially owns, directly or indirectly, or who exercises control or direction over, more than 10% of the outstanding securities of the Corporation, and no associate or affiliate of any such persons, has or has had any material interest in any transaction or any proposed transaction which materially affects Corporation or any of its affiliates.

During the year ended December 31, 2007, Canadian Superior paid $1.9 million (2006 - $0.8 million) for equipment rentals to a related party company controlled by Mr. Gregory Noval, an officer and director of Canadian Superior.  Also, during 2007, the Corporation invoiced $0.7 million (2006 - nil), at market rates, to this company for payroll services.  In addition, Canadian Superior paid $0.2 million (2006 - $0.2 million) to a company controlled by Mr. Kaare Idland, a director of the Corporation, for oilfield construction services on industry terms.

At December 31, 2007, Canadian Superior was carrying a receivable in the amount of US$19.7 million (2006 - nil) from a company related to Mr. Gregory Noval, an officer and director of Canadian Superior.  These receivables pertain to transactions for Canadian Superior’s Trinidad “Intrepid” Block 5(c) project in Trinidad.  These transactions were incurred under normal industry terms and conditions.  Subsequent to year end, the Corporation received payment of US$20.0 million from this related party.

In November 2004, the Corporation entered into participation agreements in respect of the Corporation’s offshore Nova Scotia and offshore Trinidad and Tobago prospects with a company controlled by Mr. Noval at the time. Pursuant to the participation agreements, the Corporation has the right to participate on a promoted basis for 16 2/3% of Canadian Superior’s costs of the offshore Nova Scotia wells (this was subsequently increased to 33 1/3%) and the company controlled by Mr. Noval has the right to participate on a promoted basis for 33 1/3% of Canadian Superior’s costs of certain earning wells in Trinidad and Tobago.

The transactions described in this section were in the normal course of operations and agreed to by the related company and the Corporation based on extensive negotiations and Board approval and approval by the Corporation.

TRANSFER AGENT AND REGISTRAR

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

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by the Corporation during, or related to, the Corporation’s most recently completed financial year other than GLJ, the Corporation’s independent engineering evaluator and Meyers Norris Penny LLP, the Corporation’s auditors. Neither GLJ nor any of directors, officers or employees had any registered or beneficial interests, direct or indirect, in any securities or other property of the Corporation or of the Corporation’s associates or affiliates either at the time they prepared the statement, report or valuation prepared by it nor at any time thereafter, nor are any securities or other property of the Corporation to be received by them. Meyers Norris Penny LLP, the Corporation’s auditors, are independent in accordance with the auditor’s rules of professional conduct in a jurisdiction of Canada.

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In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Corporation or of any associate or affiliate of the Corporation.

AUDIT COMMITTEE

The Audit Committee of the Corporation consists of Messrs. Alexander Squires, Richard Watkins and Charles Dallas, each of whom is considered “independent” and “financially literate” within the meaning of Multilateral Instrument 52-110 - - Audit Committees.

MANDATE OF THE AUDIT COMMITTEE

The Audit Committee is appointed by the Board of Directors of the Corporation to assist the Board of Directors in fulfilling its oversight responsibilities, including with respect to:

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;

4.the external auditors’ qualifications and independence; and

5.the external audit process and the Corporation’s processes for monitoring compliance with laws and regulations.

The Charter of the Audit Committee of the Board of Directors of Canadian Superior is attached hereto as Appendix “C”.

RELEVANT EDUCATION AND EXPERIENCE OF AUDIT COMMITTEE MEMBERS

The following is a brief summary of the education or experience of each member of the Audit Committee that is relevant to the performance of his responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles used by the Corporation.

Name of Audit Committee Member	Relevant Education and Experience
Alexander Squires, CFA	Since 1997, Mr. Squires has been a Manager Partner and Director of Brant Securities Ltd. and independent full service securities firm.
Richard Watkins	Has held a variety of accounting and corporate governance positions spanning a period of over 20 years in the oil and gas industry.
Charles Dallas	Mr. Dallas has over 40 years of oil and gas experience in various supervisory positions, including being a controller. He has also during much of that time managed his own independent ranch and farm businesses, including the financial management of these enterprises.

AUDIT COMMITTEE OVERSIGHT

At no time since the commencement of the Corporation’s most recently completed financial year has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the Board of Directors of the Corporation.

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EXTERNAL AUDITOR FEES

For the year ended December 31, 2007 and 2006, Meyers Norris Penny LLP and its affiliates were paid approximately $311,365 and $227,955, respectively, as detailed below:

AUDIT FEES

Audit fees consist of fees for the audit of the Corporation’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. The aggregate audit fees billed by the Corporation’s external auditor in each of the last two financial years were $201,798 in 2007 and $141,820 in 2006.

AUDIT-RELATED FEES

Audit-related fees include fees relating to the review of the Corporation’s quarterly financial statements. The aggregate audit-related fees billed by the Corporation’s external auditor in each of the last two financial years were $52,115 in 2007 and $35,490 in 2006

TAX FEES

Tax fees include fees relating to tax compliance, tax planning, tax advice and various taxation matters. The aggregate tax fees billed by the Corporation’s external in each of the last two financial years were $7,420 in 2007 and $6,400 in 2006.

ALL OTHER FEES

All other fees consists of fees for services provided by Meyers Norris Penny LLP other than audit, audit-related and tax services, including prospectus and other offering related work. The aggregate fees billed by the Corporation’s external auditor in each of the last two financial years other than audit fees, audit-related fees and tax fees, were $50,032 in 2007 and $44,245 in 2006.

ADDITIONAL INFORMATION

Additional information relating to the Corporation may be found on the internet on the System for Electronic Document Analysis and Retrieval (SEDAR) which can be accessed at www.sedar.com. Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of the Corporation’s securities and securities authorized for issuance under equity compensation plans, if applicable, is contained in the Corporation’s Management Information Circular for its most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided in the Corporation’s financial statements and management’s discussion and analysis for its most recently completed financial year. Additional copies of this Annual Information Form and the documents set forth in this section are available upon request by contacting the Corporation at 2700, 605 – 5th Avenue SW T2P 4K9 or by phone at (403) 294-1411 or fax at (403) 216-2374.

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APPENDIX “A”

FORM 51-101F2

REPORT ON RESERVES DATA

BY

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

This is the form referred to in Item 2 of section 2.1 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

1.Terms to which meaning is ascribed in NI 51-101 have the same meaning in this form 1.

2.The report on reserves data referred to in item 2 of section 2.1 of NI 51-101, to be executed by one or more qualified reserves evaluator or auditors independent of the reporting issuer, must in all material respects be as follows:

Report on Reserves Data

To the board of directors of Canadian Superior Energy Inc. (the “Company”):

1.We have prepared an evaluation of the Company’s reserves data as at December 31, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2007, estimated using forecast prices and costs.

2.The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2007, and identifies the respective portions thereof that we have audited, evaluated, and reviewed and reported on to the Company’s board of directors:

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			Net Present Value of Future Net Revenue
Independent Qualified Reserves	Description and Preparation Date	Location of Reserves (Country	(before income taxes, 10% discount rate — $M)
Evaluator or Auditor	of Evaluation Report	or  Foreign Geographic Area)	Audited	Evaluated		Reviewed	Total
GLJ Petroleum Consultants	Corporate Summary March 31, 2008	Canada	—	$	148,356	—	$	148,356
Totals			—	$	148,356	—	$	148,356

5.In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

6.We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

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

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 30, 2008.

(Signed) “Dana B. Laustsen, P. Eng.”

Executive Vice President

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APPENDIX “B”

Report of Management and Directors
on Reserves Data and Other Information

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 reserves and probable reserves and related future net revenue as at [last day of the reporting issuer’s most recently completed financial year], estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated and reviewed the Corporation’s reserves data. The report of the independent qualified reserves evaluator is presented in Appendix “A” to the Annual Information Form of the Corporation dated March 30, 2008.

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.

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Because the reserves data are based on judgments 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.

DATED   March 30, 2008.

(signed) “Gregory S. Noval”	(signed) “Michael E. Coolen”
GREGORY S. NOVAL	MICHAEL E. COOLEN
Executive Chairman and Member of Reserves Committee	President and Chief Operating Officer & Director

(signed) “Thomas J. Harp”	(signed) “Kaare Idland”
THOMAS J. HARP	KAARE IDLAND
Director & Member of Reserves Committee	Director & Chairman of Reserves Committee

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APPENDIX “C”

CHARTER OF THE AUDIT COMMITTEE OF THE
BOARD OF DIRECTORS OF 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; and

4.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; and

3.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;

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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; and

8.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; and

5.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;

54

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; and

7.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”), in

6.conjunction with the report of the external auditors and obtain explanation from management of all significant variances between comparative reporting periods; and

7.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.

55

EX-99.2

Exhibit 99.2

MANAGEMENT’S REPORT TO THE SHAREHOLDERS

The preparation of the accompanying consolidated financial statements in accordance with accounting principles generally accepted in Canada with a reconciliation to generally accepted accounting principles in the United States is the responsibility of management.  Financial information contained elsewhere in this Annual Report is consistent with that in the consolidated financial statements.

Management is responsible for the integrity and objectivity of the financial statements.  Where necessary, the financial statements include estimates, which are based on management’s informed judgments.  Management has established systems of internal controls, which are designed to provide reasonable assurance that transactions are authorized, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial information.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control.  It exercises its responsibilities primarily through the Audit Committee, whose members are non-management directors.  The Audit Committee has reviewed the consolidated financial statements with management and the auditors and has reported to the Board of Directors who have approved the consolidated financial statements.

MEYERS NORRIS PENNY LLP are independent auditors appointed by Canadian Superior Energy Inc.’s shareholders. The auditors have audited the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards established by the Public Company Accounting and Oversight Board (PCAOB) to enable them to express an opinion on the fairness of the presentation of the financial statements in accordance with Canadian generally accepted accounting principles.

(Signed) “Craig McKenzie”

Chief Executive Officer

Calgary, Canada

March 27, 2008

1

AUDITORS’ REPORT TO SHAREHOLDERS

We have audited the consolidated balance sheets of Canadian Superior Energy Inc. as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive loss and deficit and cash flows for each of the years in the three year period ended December 31, 2007.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2007 in accordance with Canadian generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established by Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report as at March 27, 2008 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

(Signed) “Meyers Norris Penny LLP”

Independent Registered Public Accounting Firm

March 27, 2008

Calgary, Canada

2

REPORT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

To the Board of Directors and Shareholders of Canadian Superior Energy Inc.:

We have audited Canadian Superior Energy Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit includes performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.  The following material weaknesses have been identified and are included in management’s assessment:

·      There are no effective controls or procedures related to all significant accounts and processes to provide reasonable assurance that transactions are recorded accurately, are recorded timely and are complete.

·      The Company was not adequately staffed with accounting personnel possessing an adequate level of technical expertise and did not maintain effective segregation of duties over automated and manual transactions leading to ineffective monitoring, supervision and reviews.

·      The Company did not maintain effective controls over the safeguarding of monetary assets.  This material weakness affects cash and short-term investments.

3

In our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as at December 31, 2007 and 2006 and the statements of operations, comprehensive loss and deficit and cash flows for each of the years in the three year period ended December 31, 2007, of the Company and our report dated March 27, 2008 expressed an unqualified opinion. The aforementioned material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 consolidated financial statements, and this report does not affect our opinion on those consolidated financial statements.

Yours truly,

(Signed) “Meyers Norris Penny LLP”

Independent Registered Public Accounting Firm

Calgary, Canada

March 27, 2008

4

CANADIAN SUPERIOR ENERGY INC.

CONSOLIDATED BALANCE SHEETS

As at December 31

($ thousands)	2007		2006
Assets (note 7)
Current
Cash and short-term investments	13,658		7,338
Accounts receivable	36,448		17,114
Prepaid expenses and deposits	2,571		785
	52,677		25,237
Nova Scotia offshore term deposits (note 4)	14,559		14,805
Long term portion of lease prepayment (note 5)	1,309		—
Property, plant and equipment, net (note 6)	186,154		185,426
	254,699		225,468
Liabilities
Current
Accounts payable and accrued liabilities	22,230		17,997
Revolving credit facility (note 7)	17,784		7,910
	40,014		25,907
Convertible preferred shares (note 8)	13,571		15,472
Asset retirement obligations (note 9)	11,325		9,482
Future income taxes (note 10)	8,853		10,958
	73,763		61,819
Contingencies and commitments (note 15)
Subsequent event (note 18)
Shareholders’ Equity
Share capital (note 11)	186,557		162,276
Equity portion of preferred shares (note 11)	2,320		2,320
Contributed surplus (note 11)	14,314		11,372
Deficit	(22,255	)	(12,319	)
	180,936		163,649
	254,699		225,468

See accompanying notes to the consolidated financial statements

On behalf of the Board,

(Signed) Craig McKenzie	(Signed) Alex Squires
Director	Director

5

CANADIAN SUPERIOR ENERGY INC.

CONSOLIDATED STATEMENT OF OPERATIONS, COMPREHENSIVE LOSS AND DEFICIT

For the years ended December 31

($ thousands, except per share amounts)	2007			2006			2005
Revenue
Petroleum and natural gas sales	48,492			49,428			55,223
Transportation	(645		)	(662		)	(678		)
Royalties net of royalty tax credit	(7,914		)	(8,245		)	(9,716		)
	39,933			40,521			44,829
Interest and other income (expense)	925			1,371			(674		)
	40,858			41,892			44,155
Expenses
Operating	9,883			9,042			7,239
General and administrative	13,315			9,312			5,398
Stock based compensation (note 11)	4,218			5,891			3,657
Depletion, depreciation and accretion	26,595			25,686			23,539
Interest	3,352			2,047			1,015
Foreign exchange (gain) loss	(653		)	312			41
Loss on investment	—			600			—
Loss on abandonment (note 9)	42			—			—
	56,752			52,890			40,889
Income (loss) before income taxes	(15,894		)	(10,998		)	3,266
Income taxes (reduction)
Capital	55			33			129
Future income tax (reduction)	(6,013		)	(118		)	81
	(5,958		)	(85		)	210
Net income (loss) and comprehensive income (loss)	(9,936		)	(10,913		)	3,056
Deficit, beginning of year	(12,319		)	(1,406		)	(4,462		)
Deficit, end of year	(22,255		)	(12,319		)	(1,406		)
Basic and diluted income (loss) per share (note 11)	$	(0.07	)	$	(0.09	)	$	0.03

See accompanying notes to the consolidated financial statements

6

CANADIAN SUPERIOR ENERGY INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

For the years ended December 31

($ thousands)	2007		2006		2005
Cash provided by (used in):
Operating
Net Income (loss)	(9,936	)	(10,913	)	3,056
Items not involving cash:
Depletion, depreciation and accretion	26,595		25,686		23,539
Stock based compensation	4,218		5,891		3,657
Share dividends paid on preferred shares	711		641		—
Accretion expense on preferred shares	442		357		—
Forfeiture of Nova Scotia offshore term deposits	500		558		—
Loss on investment	—		600		—
Future income tax (reduction)	(6,013	)	(118	)	81
Loss on abandonment (note 9)	42		—		—
Change in the carrying cost of preferred shares	(2,343	)	381		—
Asset retirement expenditures (note 9)	(361	)	—		—
	13,855		23,083		30,333
Changes in non-cash working capital (note 12)	(4,993	)	(8,453	)	11
	8,862		14,630		30,344
Financing
Issue of shares	26,200		26,968		20,316
Issue of Nova Scotia offshore term deposits	(254	)	(963	)	(252	)
Cash dividends paid on preferred shares	(187	)	—		—
Convertible preferred share issue	—		17,455		—
Revolving credit facility (repayments) advances	9,874		(4,941	)	2,101
Changes in non-cash working capital (note 12)	238		—		—
	35,871		38,519		22,165
Investing
Exploration and development expenditures	(66,282	)	(59,548	)	(44,083	)
Exploration and development divestitures	41,310		—		—
Purchase of investments	—		(3,106	)	—
Disposal of investments	—		2,506		—
Change in non-cash working capital (note 12)	(13,441	)	2,539		1,647
	(38,413	)	(57,609	)	(42,436	)
Increase (decrease) in cash and short-term investments	6,320		(4,460	)	10,073
Cash and short-term investments, beginning of year	7,338		11,798		1,725
Cash and short-term investments, end of year	13,658		7,338		11,798

See accompanying notes to the consolidated financial statements

7

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2007 and 2006

(all tabular amounts in $ thousands, except where otherwise noted)

1.     Nature of operations

Canadian Superior Energy Inc. (“Canadian Superior” or the “Company”) is engaged in the exploration for, and acquisition, development and production of petroleum and natural gas primarily in Western Canada and offshore Nova Scotia, Canada and Trinidad and Tobago.

2.     Summary of accounting policies

These consolidated financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). Certain comparative amounts have been reclassified to conform to current period presentation.

(a)   Principles of consolidation

The consolidated financial statements include the accounts of Canadian Superior and its wholly owned subsidiary companies.  All material intercompany accounts and transactions have been eliminated.

(b)   Cash and short-term investments

Cash and short-term investments consist of balances with banks and investments in highly liquid short-term deposits with a maturity date of less than ninety days.

(c)   Measurement uncertainty

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting period.  Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements.  Accordingly, actual results may differ from these estimates.

Amounts recorded for depreciation, depletion and accretion, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of natural gas and crude oil reserves and the future costs required to develop those reserves.  By their nature, these estimates are subject to measurement uncertainty and the impact on the consolidated financial statements of changes in such estimates in future periods could be material.

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal and regulatory environments.  To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment is made to the property, plant and equipment balance.

(d)   Property, plant and equipment

(i)Capitalized costs

The Company is engaged in the acquisition, exploration, development and production of oil and gas in Canada and Trinidad and Tobago. The Company follows the full-cost method of accounting for oil and gas operations whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized.  Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and nonproductive wells, costs of production equipment and overhead charges related to acquisition, exploration and development activities.

Proceeds received from disposals of properties and equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20%, in which case a gain or loss on disposal is recorded.

8

(ii)Depletion and depreciation

Depreciation and depletion of producing oil and gas properties is recorded based on units of production.  Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves.  Proved reserves are estimated by independent engineers and are subject to future revisions based on availability of additional information.  Asset retirement costs are amortized over proved reserves using the unit-of-production method.  Gains and losses on asset disposals or retirements are included in income as a separate component of revenue.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  These unevaluated properties are assessed periodically to ascertain whether impairment has occurred.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Corporate assets are depreciated on a declining balance basis over its estimated useful life at rates varying from 20% to 100%.

(iii)Ceiling test

The Company performs a ceiling test in a two-stage test performed quarterly.  Impairment is recognized if the carrying value of the oil and gas assets less accumulated depletion and the lesser of cost and fair value of unproven properties exceeds the estimated future cash flows from proved oil and gas reserves, on an undiscounted basis, using forecast prices and costs.  If impairment is recognized, the Company will measure the amount of the impairment by comparing the carrying value of the oil and gas assets less accumulated depletion and the lesser of cost and fair value of unproven properties to the estimated future cash flows from the proved and probable oil and gas reserves, discounted at the Company’s credit adjusted risk-free rate of interest, using forecast prices and costs.  Any impairment is included in the statement of operations for the respective year.

(e)Joint ventures

The Company’s exploration and development activities related to oil and gas are conducted jointly with others, which may include related parties (Note 13). The accounts reflect only the Company’s proportionate interest in such activities.

(f)Income taxes

The Company follows the asset and liability method of accounting for future income taxes.  Under this method, future income tax assets and liabilities are recorded based on temporary differences between the carrying amount of balance sheet items and their corresponding tax bases.  In addition, the future benefits of income tax assets, including unused tax losses, are recognized, subject to a valuation allowance, to the extent that it is more likely than not that such future benefits will ultimately be realized.  Future income tax assets and liabilities are measured using enacted tax rates and laws expected to apply when the tax liabilities or assets are to be either settled or realized.

(g)Revenue recognition

Revenue from the sale of oil and gas is recognized based on volumes delivered to customers at contractual delivery points and rates.  The costs associated with the delivery, including operating and maintenance costs, transportation, and production-based royalty expenses are recognized in the same period in which the related revenue is earned and recorded.

9

(h)Flow-through shares

The Company, from time to time, issues flow-through shares to finance a portion of its oil and gas exploration activities.  The exploration and development expenditures funded by flow-through shares are renounced to subscribers in accordance with the Income Tax Act (Canada).  The estimated value of the tax pools foregone is reflected as a reduction in share capital with a corresponding increase in the future income tax liability at the time the relevant expenditures are renounced.

(i)Basic and diluted per share amounts

Basic per share amounts are calculated by dividing net earnings or loss by the weighted average number of common shares outstanding during the period.  The Company utilizes the treasury stock method in the determination of diluted per share amounts.  Under this method, the diluted weighted average number of shares is calculated assuming that proceeds arising from the exercise of in-the-money options and other dilutive instruments are used to purchase, for cancellation, common shares of the Company at their average market price for the period.

(j)Foreign currency translation

Transaction amounts denominated in foreign currencies are translated into their Canadian dollar equivalents at exchange rates prevailing at the transaction dates. Carrying values of monetary assets and liabilities reflect the exchange rates at the balance sheet date. Gains and losses on translation or settlement are included in determination of net income or loss for the current period.

(k)Stock based compensation

Under the Company’s stock option plan described in note 11, options to purchase common shares are granted to directors, officers, employees and consultants at current market prices or higher on the date of grant.  Stock-based compensation expense is recorded in the statement of operations for all options granted with a corresponding increase recorded as contributed surplus.  Compensation expense is based on the estimated fair values of the options at the time of the grant as determined using a Black-Scholes option pricing model.  The expense is recognized on a straight-line basis over the vesting period of the option.  Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase in share capital.  In the event that vested options expire, previously recognized compensation expense associated with such stock options is not reversed.  The Company incorporates an estimated forfeiture rate for stock options that will not vest.

(l)Asset retirement obligation

The Company recognizes the estimated liability associated with an asset retirement obligation (“ARO”) in the financial statements at the time the asset is acquired and the liability is incurred. The estimated fair value of the ARO liability is recorded as a long term liability, with a corresponding increase in the carrying amount of petroleum and natural gas properties. The capitalized amount is depleted on a unit-of-production method over the life of the proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. The ARO can also increase or decrease due to changes in the estimates of timing of cash flows or changes in the original estimated undiscounted cost. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.

10

(m)Convertible preferred shares

The Company’s convertible debt instruments are segregated into their debt and equity components at the date of issue, based on the relative fair market values of these components in accordance with the substance of the contractual agreements.  The debt component of the instruments is classified as a liability, and recorded as the present value of the Company’s obligation to make future interest payments in cash, and settle the redemption value of the instrument in cash or in a variable number of shares.  The carrying value of the debt component is accreted to the original face value of the instruments, over their deemed life, using the effective interest method.  The conversion option, which makes up the equity component of the instruments, is recorded using the residual value approach.  Upon conversion, any gain or loss arising from extinguishment of the debt is recorded in income of the current period.

3.Adoption of new accounting policies

On January 1, 2007, Canadian Superior adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (“CICA”): Comprehensive Income (Section 1530), Financial Instruments – Recognition and Measurement (Section 3855), Financial Instruments – Disclosure and Presentation (Section 3861) and Hedges (Section 3865).  In accordance with the new standards, changes are adopted retroactively without restatement of prior period information.  The other effects of the implementation of these new standards are discussed below.

a)Comprehensive Income

Section 1530 provides for a new Statement of Comprehensive Income and establishes Accumulated Other Comprehensive Income (“AOCI”) as a separate component of shareholders’ equity.  The Statement of Comprehensive Income is defined as a change in net assets arising from transactions and other events from non-owner sources.  The statement would present net income and each component recognized in other comprehensive income (“OCI”) when such amounts exist.  For the year ended December 31, 2007, the Company did not recognize any OCI.  Any future OCI recognized by the Company will be recognized in AOCI.

b)Financial Instruments – Recognition and Measurement

Section 3855 requires all financial assets and liabilities, including derivatives, to be carried at fair value on the Company’s balance sheet with the exception of loans and receivables, investments that are intended to be held to maturity and non-trading financial liabilities which are carried at cost or amortized cost.

The Company has reviewed and classified its financial instruments as follows:

· Cash, short-term investments and Nova Scotia offshore term deposits are classified as financial assets held for trading and are measured at their fair value. Gains or losses related to periodic revaluation are recorded to net income or loss.

· Accounts receivable are classified as loans and receivables and are initially measured at their fair value. Subsequent periodic revaluations are recorded at their amortized cost using the effective interest rate method.

· Accounts payable, accrued liabilities, revolving credit facility and convertible preferred shares are classified as other liabilities and are initially measured at fair value. Subsequent periodic revaluations are recorded at their amortized cost using the effective interest rate method.

11

c)Derivatives and Hedge Accounting

Derivatives may be embedded in other financial instruments (the “host instruments”).  Prior to the adoption of the new standards, such embedded derivatives were not accounted for separately from the host instrument.  Under the new standard, embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not clearly and closely related to those of the host instrument, the terms of the embedded derivative are the same as those of the stand-alone derivative, and the combined contract is not held for trading or designated at fair value.  A review of the Company’s financial contracts determined that there were no embedded derivatives.  In the event that the Company enters into a contract that contains an embedded derivative, the embedded derivative will be measured at fair value with subsequent changes recognized in earnings or loss.

At January 1, 2007 no transitional adjustments were required to the opening balance of retained earnings or to the opening balance of AOCI arising from the adoption of sections 1530, 3855, and 3865.

In addition, the Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Company:

As of January 1, 2008, the Company will be required to adopt the following two new CICA standards: Financial Instruments - Disclosures (Section 3862) and Financial Instruments - Presentation (Section 3863), which will replace Financial Instruments - Disclosure and Presentation (Section 3861).  The new disclosure standard increases the emphasis on the risks associated with both recognized and unrecognized financial instruments and how those risks are managed.  The new presentation standard carries forward former presentation requirements.

As of January 1, 2008, the Company will be required to adopt CICA standards, Capital Disclosures (Section 1535), which will require companies to disclose their objectives, policies and processes for managing capital.  In addition, disclosures are to include whether companies have complied with externally imposed capital requirements.

A strategic plan has been adopted by the Accounting Standards Board for the future direction of accounting standards in Canada.  It is expected that Canadian accounting standards for public companies will converge with International Financial Reporting Standards (“IFRS”).  On December 31, 2008, the Company will be required to provide a preliminary disclosure of policy impacts of upon adopting IFRS.  The Company is in the initial stages of assessing IFRS and its impacts on the consolidated financial statements.

4.Nova Scotia offshore term deposits

Under the terms of the licenses referred to in Note 15, the Company has assigned term deposits totalling $14.6 million (2006 - $14.8 million).  Accordingly, this amount has been classified as a non-current asset.  To the extent that the expenditures are not incurred within the period allowed, the Company would forfeit its proportionate share of any remaining deposits relating to the unexpended work commitment.  During 2007 $0.5 million (2006 - $0.6 million) was forfeited and recorded to operating expenses.  The following table summarizes the work commitment and work deposit which would be forfeited in proportion to the amount of work commitment not completed by the expiry date:

License	Work Deposit ($)	Remaining Commitment ($)	Expiry Date
EL 2406	11,032,500	40,962,046	December 31, 2008
EL 2415	3,214,250	12,857,000	December 31, 2008
EL 2416	312,500	1,250,000	December 31, 2008
Total	14,559,250	55,069,046

5.Long term portion of lease prepayment

In February 2007, the Company paid a lump payment to acquire new office space with lease payments under the prevailing lease rates. This lump payment is being allocated over the life of the lease with any portions more than a year in advance being classified as a long term asset. As at December 31, 2007 there are 39 months left on the lease with 27 months classified as a long term asset.

12

6.Property, plant and equipment, net

	2007			2006
December 31	Cost	Accumulated DD&A	Net book value	Cost	Accumulated DD&A	Net book value
Oil and Gas
Canada	278,624	117,491	161,133	245,963	91,831	154,132
Trinidad	24,836	—	24,836	31,132	—	31,132
	303,460	117,491	185,969	277,095	91,831	185,264
Corporate assets	883	698	185	788	626	162
Total PP&E	304,343	118,189	186,154	277,883	92,457	185,426

The calculation of 2007 depletion and depreciation included an estimated $8.7 million (2006 - $9.3 million) for future development capital associated with proven undeveloped reserves and excluded $54.4 million (2006 - $67.0 million) related to unproved properties and projects under construction or development.  Of the costs excluded $20.8 million (2006 - $22.7 million) relates to Western Canada, $8.8 million (2006 - $8.8 million) to East Coast Canada and $24.8 million (2006 - - $35.5 million) to Trinidad and Tobago.

The Company is in the process of negotiating the recovery of substantial Trinidad drilling costs relating to drilling problems on the Victory well on “Intrepid” Block 5(c) offshore Trinidad.

On August 11, 2007, Canadian Superior farmed out a portion of its interest in the “Intrepid” Block 5(c) Production Sharing Contract (“PSC”) offshore Trinidad and Tobago.  The farmee paid US$38.7 million to the Company representing their share of certain capital and administrative costs incurred by Canadian Superior.  This transaction has been recorded as reduction to Trinidad capital and general and administrative costs in 2007 (Note 16).

During the year ended December 31, 2007, the Company capitalized $2.8 million of general and administrative (“G&A”) expenses (2006 - $7.6 million) related to exploration and development activities.

The Company performed a ceiling test calculation at December 31, 2007 resulting in the undiscounted cash flows from proved reserves and the lower of cost and market of unproved reserves exceeding the carrying value of oil and gas assets. The prices used in the ceiling test evaluation of the Company’s oil and gas assets is summarized in the following chart:

	Crude Oil				Natural Gas
	West Texas Intermediate (Cdn$/bbl)(1)		Edmonton Par Price (Cdn$/bbl)		AECO Gas Price (Cdn$/mmbtu)
2008	92.00		91.10		6.75
2009	88.00		87.10		7.55
2010	84.00		83.10		7.60
2011	82.00		81.10		7.60
2012	82.00		81.10		7.60
2013-2017 (2)	82.34		81.43		7.96
Thereafter (3)	2.0	%	2.0	%	2.0	%

(1)Future prices incorporate a $1.00 US/Cdn exchange rate

(2)Prices shown are the average over the period

(3)Percentage change of 2.0% represents the change in the future prices each year after 2017 to the end of the reserve life.

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7.Revolving credit facility

The Company has a $45 million demand revolving credit facility (the “credit facility”).  The credit facility is secured by a $100 million first floating charge demand debenture on the assets of the Company and a general security agreement covering all of the assets of the Company.  The credit facility has covenants that require the Company to maintain its working capital ratio at 1:1 or greater, tangible net worth to total liabilities at 1.5:1.0 or greater and tangible net worth at greater than $100 million while the credit facility is outstanding.  The borrowing base of the credit facility is subject to an annual review by the lender.  As at December 31, 2007, the Company had drawn $17.8 million (2006 - $7.9 million) against the credit facility at a variable interest rate of prime plus 1.0% (2006 – prime plus 0.5%).

8.Convertible preferred shares

On February 1, 2006, the Company completed a private placement in the amount of US$15.0 million by way of the issuance of Units consisting of 5% US Cumulative Redeemable Convertible Preferred Shares (the “Preferred Shares”) and Common Share Purchase Warrants. Each Preferred Share will be convertible into forty Common Shares of Canadian Superior (6,000,000 Common Shares in aggregate) at a price of US$2.50 per Common Share. If Canadian Superior elects, it also has the option to pay the quarterly dividend by way of issuance of Common Shares at market, based on a 5.75% annualized dividend rate in lieu of the 5% annualized cash dividend rate. In addition, the Preferred Shares are redeemable and retractable five years from the date of issue or earlier, subject to earlier redemption or retraction in certain events.  The Company, issued 15,000 Units, each consisting of 10 US$100 Preferred Shares and 1,200,000 Common Share Purchase Warrants. The Warrants comprising part of the Units are exercisable for a period of thirty six months from the date of issue at an exercise price of US $3.00 per Common Share.

The following table summarizes the face and carrying value of the liability and equity component of the convertible preferred shares:

	Liability component			Equity component
	Face value	Carrying value		Fair value
Balance, December 31, 2005	—	—		—
Issuance of convertible preferred shares	17,053	14,734		2,320
Foreign exchange	—	381		—
Accreted non-cash interest	—	357		—
Balance, December 31, 2006	17,053	15,472		2,320
Foreign exchange	—	(2,343	)
Accreted non-cash interest	—	442
Balance, December 31, 2007	17,053	13,571		2,320

9.Asset Retirement Obligations

The following table presents the reconciliation of the carrying amount of the obligations associated with the retirement of the property, plant and equipment:

December 31,	2007		2006
Balance, beginning of year	9,482		8,302
Liabilities settled	(319	)	—
Liabilities incurred	1,352		532
Accretion expense	810		648
Balance, end of year	11,325		9,482

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The following significant assumptions were used to estimate the asset retirement obligation:

December 31,	2007	2006
Undiscounted cash flows	19,691	17,350
Credit adjusted discount rate (%)	7.62	7.38
Inflation rate (%)	1.50	1.50
Weighted average expected timing of cash flows (years)	17.5	18.0

10.  Future Income Taxes

The Company’s computation of future income tax expenses (recovery) is as follows:

December 31,	2007		2006		2005
Income (loss) before income taxes	(15,894	)	(10,998	)	3,266
Combined federal and provincial income tax rate (%)	32.1		34.0		37.6
Computed income tax expense (reduction)	(5,102	)	(3,740	)	1,228
Increase (decrease) resulting from:
Non deductible crown royalties, net	—		1,442		1,863
Resource allowance	—		(606	)	(2,168	)
Stock based compensation	1,354		2,003		1,376
Unsuccessful take over costs	—		725		—
Tax adjustment – rate change and other	(358	)	58		95
Tax pool amendments	(1,907	)	—		(2,313	)
	(6,013	)	(118	)	81

The net future tax liability is comprised of:

	2007		2006
Non-capital loss carryforwards	(817	)	906
Asset retirement obligations	(3,114	)	(2,892	)
Share issue costs	(1,127	)	(1,191	)
Net book value of assets in excess of tax basis	18,537		14,135
Foreign exploration expense	(4,413	)	—
Other	(213	)	—
	8,853		10,958

As at December 31, 2007, the Company had approximately $149.7 million in tax pools and $3.0 million in non-capital losses available for deduction against future taxable income.

Non-capital losses expire as follows:

2008	—
2009	—
2010	—
2011 and thereafter	2,970
	2,970

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11.  Share Capital

(a)   Authorized

Unlimited number of common shares, no par value.

Unlimited number of preferred shares, no par value.

(b)Common shares issued

	2007			2006
	Number(#)	Amount($ )		Number(#)	Amount($ )
Balance, beginning of year	131,216	161,964		119,135	135,650
Issued upon the conversion of purchase warrants	500	1,385		375	948
Issued upon the exercise of stock options	1,864	3,518		1,198	1,639
Issued in settlement of lawsuit	—	—		260	711
Issued for cash	—	—		3,500	8,301
Issued for Canada Southern shares	—	—		472	1,116
Issued for preferred share dividend	259	712		276	641
Issued for cash on flow-through shares	6,473	22,654		6,000	15,420
Issue costs, net of future tax reduction	—	(889	)	—	(649	)
Tax benefits renounced on flow-through-shares	—	(4,241	)	—	(2,723	)
Stock based compensation for exercised options	—	1,454		—	910
Balance, end of the year	140,312	186,557		131,216	161,964

On November 16, 2007, the Company completed a private placement of 6,472,500 flow-through common shares at $3.50 per share for gross proceeds of $22.7 million.

On December 31, 2007, 500,000 warrants were exercised into 500,000 common shares at US$2.50 per share for gross proceeds of US$1.3 million.

On February 9, 2006, the Company completed a private placement financing consisting of 1.0 million Units at a price of $2.40 per Unit for gross proceeds of $2.4 million. Each Unit consists of one Common Share and one-half of one Common Share Purchase Warrant.

On December 13, 2006 the Company completed a private placement of 6,000,000 flow-through common shares at $2.57 per share for gross proceeds of $15.4 million.

On December 29, 2006 the Company completed a private placement of 2,500,000 shares at $2.37 per share for gross proceeds of $5.9 million.

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(c)Purchase warrants issued

	2007				2006
	Number(#)		Amount($ )		Number(#)		Amount($ )
Balance, beginning of year	500		312		2,750		165
Issued	—		—		1,000		158
Exercised	(500	)	(134	)	(750	)	(11	)
Expired	—		(178	)	(2,500	)	—
Balance, end of the year	—		—		500		312

On February 9, 2006, the Company completed a private placement financing consisting of 1.0 million Units at a price of $2.40 per Unit for gross proceeds of $2.4 million. Each Unit consists of one Common Share and one-half of one Common Share Purchase Warrant. The Warrants comprising part of the Units were exercisable until December 31, 2006 at an exercise price of $2.40 per common share. These warrants have all expired as of December 31, 2006.

On June 18, 2006 the Company issued 500,000 share purchase warrants in arranging financing for the Canada Southern Acquisition. On December 31, 2007, the warrants were exercised into 500,000 common shares at US$ 2.50 per share.

In August 2005, the Company filed a short form prospectus qualifying the distribution of 2,750,000 common share purchase warrants which expired on June 30, 2006.

(d)Total Share Capital

	2007		2006
	Number(#)	Amount($ )	Number(#)	Amount($ )
Common shares issued	140,312	186,557	131,216	161,964
Purchase warrants issued	—	—	500	312
Balance, end of the year	140,312	186,557	131,716	162,276

        (e)   Stock options

The Company has a stock option plan for its directors, officers, employees and key consultants.  The exercise price for stock options granted is no less than the quoted market price on the grant date with options vesting in equal increments over a three year period.  An option’s maximum term is ten years.

	2007			2006
	Number of options		Weighted average price ($ )	Number of options		Weighted average price ($ )
Balance, beginning of year	13,062		2.05	9,488		1.83
Forfeited	(875	)	2.45	(747	)	2.31
Exercised	(1,864	)	1.89	(1,198	)	1.37
Granted	5,263		2.70	5,519		2.30
Balance, end of the year	15,586		2.27	13,062		2.05

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The following table summarizes stock options outstanding under the plan at December 31, 2007:

	Options outstanding			Options exercisable
Exercise price ($ )	Number of options (#)	Average remaining contractual life (years)	Weighted average exercise price($)	Number of options(#)	Weighted average exercise price($)
0.80-1.00	97	2.57	0.81	97	0.81
1.01-1.50	925	4.73	1.30	925	1.30
1.51-2.00	2,892	6.54	1.78	2,736	1.78
2.01-3.00	11,247	8.12	2.45	8,864	2.40
3.01-3.50	425	9.15	3.18	191	3.21
0.80-3.00	15,586	7.63	2.27	12,813	2.19

The following table summarizes stock options outstanding under the plan at December 31, 2006:

	Options outstanding			Options exercisable
Exercise price ($ )	Number of options (#)	Average remaining contractual life (years)	Weighted average exercise price($)	Number of options(#)	Weighted average exercise price($)
0.80-1.00	155	3.57	0.81	155	0.81
1.01-1.50	1,110	5.73	1.30	1,110	1.30
1.51-2.00	3,748	7.54	1.79	2,666	1.76
2.01-3.00	8,049	9.12	2.30	3,784	2.31
0.80-3.00	13,062	8.31	2.05	7,715	1.95

(f)Stock based compensation

The Company uses the fair value method to account for its stock based compensation plan.  Under this method, compensation costs are charged over the vesting period for stock options granted to directors, officers, employees and consultants, with a corresponding increase to contributed surplus.

The following table reconciles the Company’s contributed surplus:

December 31,	2007		2006
Balance, beginning of year	11,372		6,391
Issuance of stock options	4,218		5,891
Exercise of stock options	(1,454	)	(910	)
Expiry of warrants	178		—
Balance, end of year	14,314		11,372

The fair value of options granted during the period was estimated based on the date of grant using the Black-Scholes option pricing model with weighted average assumptions and resulting values for grants as follows:

December 31,	2007	2006
Risk free interest rate (%)	4.1	4.1
Expected life (years)	10.0	10.0
Expected dividend yield (%)	—	—
Expected volatility (%)	41.7	44.3
Weighted average fair value of options granted ($)	1.57	1.41

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(g)Employee stock savings plan

The Company has an employee stock savings plan (“ESSP”) in which employees are provided with the opportunity to receive a portion of their salary in common shares, which is then matched on a share for share basis by the Company.  The Company purchased approximately 95,000 shares under the ESSP in 2007 (2006 – 122,000).

(h)Basic and diluted earnings and loss per share

The Company used the treasury stock method to calculate net income (loss) per common share.

December 31,	2007			2006			2005
(thousands, except per share amounts)
Weighted average common shares
Basic	133,719			121,911			112,170
Diluted	133,719			121,911			114,279
Basic and diluted loss per share	$	(0.07	)	$	(0.09	)	$	0.03

For the calculation of diluted net loss per share the Company excluded the following securities that are anti-dilutive:

December 31,	2007	2006	2005
(thousands)
Stock options	15,586	13,062	593
Convertible preferred shares	15,000	15,000	—
Warrants	—	500	2,750

Subsequent to December 31, 2007, Canadian Superior issued 1,650,000 stock options with a weighted average exercise price of $3.53 per share.  These transactions would have changed the potential common stock outstanding at the end of the period if the transactions had occurred prior to December 31, 2007.

(i)Equity portion of preferred shares

Warrant equity on preferred shares	351
Conversion equity on preferred shares	1,969
Balance, December 31, 2007 and 2006	2,320

12.  Supplemental cash flow information

a) Changes in non-cash working capital

	2007		2006		2005
Accounts receivable	(19,334	)	(8,146	)	(3,160	)
Prepaid expenses	(1,786	)	(11	)	(181	)
Long term portion of lease prepayment	(1,309	)	—		—
Accounts payable	4,233		2,243		4,999
Change in non-cash working capital	(18,196	)	(5,914	)	1,658

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The change in non-cash working capital has been allocated to the following activities:

	2007		2006		2005
Operating	(4,993	)	(8,453	)	11
Financing	238		—		—
Investing	(13,441	)	2,539		1,647
	(18,196	)	(5,914	)	1,658

b) Other cash flow information

	2007	2006	2005
Interest paid	2,482	2,061	854
Taxes paid	55	—	143

13.  Related parties transactions

During the year ended December 31 2007, the Company paid $1.9 million (2006 - $0.8 million), on industry terms, for equipment rentals to a company controlled by an officer and director of Canadian Superior.  Also during 2007, the Company invoiced $0.7 million (2006 - nil), at market rates, to this related party company for payroll services.  In addition, Canadian Superior paid $0.2 million (2006 - $0.2 million) to a Company controlled by a director, for oil field construction services on industry terms.

At December 31, 2007, Canadian Superior is carrying a receivable in the amount of US$19.7 million (2006 – nil) from a company which one of Canadian Superior’s officers and directors is a shareholder and director.  These receivables pertain to transactions for Canadian Superior’s “Intrepid” Block 5(c) project at Trinidad (note 15).  These transactions were incurred under normal industry terms and conditions.  Subsequent to year end, the Company received payment of US$20.0 million from this company.

14.  Financial Instruments

(a)Fair value of financial assets and liabilities

The carrying values of financial assets and liabilities approximate their fair value due to their short periods of maturity and the credit facility bearing interest at market rates.

(b)Credit risk

The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business under normal industry sale and payment terms and are subject to normal credit risks.  Purchasers of the Company’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment.

(c)Foreign exchange risk

The Company is exposed to foreign currency fluctuations as oil and gas prices received are referenced to U.S. dollar denominated prices and convertible preferred shares are denominated in U.S. dollars.  The Company also has assets and liabilities based in U.S. currency that are subject to interest rate fluctuations.

(d)Interest rate risk

The Company is exposed to interest rate risk as the credit facility bears interest at floating market interest rates.  The Company has no interest rate swaps or hedges at December 31, 2007.

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(d)Commodity price risk

The Company 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. At December 31, 2007, the Company had no contracts in place.

15.  Contingencies and commitments

a)Nova Scotia

During 2000, 2001 and 2003, the Company acquired six exploration licenses from the Canada-Nova Scotia Offshore Petroleum Board (“CNSOPB”).  Each of these licenses is for a specific period of nine years, subject to certain requirements being met during the first five years or six years.  As a condition of the licenses, the Company is required to post security in the amount of 25% of its work expenditure bids. The deposit is refundable only to the extent of approved allowable expenditures.  The duration of the initial five year term, for a given license, can be extended one additional year to six years by posting an additional security drilling deposit in an amount of $250,000. Recently the CNSOPB implemented an additional extension program that allows the six year period to be further extended up to nine years by payment of annual extension fees.  As of December 31, 2007, as a result of the Company incurring certain expenditures and drilling two exploration wells, the Company had fully fulfilled its work expenditures on two of the exploration licenses, allowed three licenses to return to the Crown, extended one license and held the remaining two under the regular licensing process.  At December 31, 2007, the Company’s owned 100% of five exploration licenses that have aggregate work expenditure outstanding of $55.1 million and $14.6 million in term deposits assigned to the Canadian Receiver General through the CNSOPB (Note 4).

b)Trinidad and Tobago

The Company is committed to drill three exploration wells on its “Intrepid” Block 5(c) under its Block 5(c) Production Sharing Contract (“PSC”) with the Government of Trinidad and Tobago funded in part by a related party participating on a promoted basis, paying 1/3 of Canadian Superior’s Block 5(c) exploration program to obtain 25% of Canadian Superior’s net revenue share of these prospects; and, also by a non-related party paying approximately 40% of the exploration cost, plus other considerations, for a 30% interest in the Block 5(c) PSC.  The Company has contracted the Kan Tan IV Semi-Submersible Drilling Rig for a three well commitment on the Company’s Trinidad and Tobago “Intrepid” Block 5 (c). In 2007, the Company drilled and commenced testing of the first well.  The second well in this program was spudded in February 2008.  The Company estimates that the costs to drill the remaining two wells to be in the range of US $65.0 million to US $75.0 million gross per well.  The wells will be drilled and evaluated back to back, with this three well program expected to be completed in 2008.

During the third quarter of 2007, the Company received an exploration and development license from the Government of Trinidad and Tobago on the Mayaro-Guayaguayare block (“MG Block”) and as a result is committed to conducting 3D seismic and to drill two exploration wells on the MG block in a joint venture with the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”).  The first well has to be drilled to a depth of 3,000 meters by January 2010 and the second to a depth of 1,800 meters by July 2010. The Company estimates that its share of the cost of these wells to be in the range of US $15.0 million per well, with the 3D seismic program to be completed in 2008 at a net cost to the Company of approximately US$ 20.0 million.

c)Flow-through shares

At December 31, 2007, the Company had yet to incur approximately $22.7 million of Canadian exploration expenses which were renounced for tax purposes.  These expenses must be incurred by December 31, 2008.

d)Litigation and claims

The Company is involved in various claims and litigation arising in the ordinary course of business.  In the opinion of Canadian Superior the various claims and litigations arising there from are not expected to have a material adverse effect on the Company’s financial position.  The Company maintains insurance, which in the opinion of the Company, is in place to address any unforeseen claims.

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e)     Lease obligations

At December 31, 2007, the Company is committed to future payments for office leases and equipment.  Payments required under these commitments for each of the next five years are as follows:

	2008	2009	2010	2011	Thereafter
Office rent	317	249	226	57	—
Equipment	155	77	42	—	—
	472	326	268	57	—

16.  Trinidad Farm Out

In 2007, the Company entered into a farm in and joint operating agreement with BG International Limited (“BG”) to participate in the exploration drilling and development of the “Intrepid” Block 5(c) approximately sixty miles off the east coast of the island of Trinidad. Under the terms of the farm-in and joint operating agreements, BG acquired a 30% working interest in Canadian Superior’s “Intrepid” Block 5(c) Production Sharing Contract; the agreement was approved by the Government of Trinidad and Tobago on October 29, 2007. Also, under the terms of the agreement with Canadian Superior, BG paid Canadian Superior approximately US$38.7 million and on a go forward basis will pay approximately 40% of the exploration costs associated with the drilling of the three commitment wells required on Block 5(c).

17.  Canada Southern

In June 2006, Canadian Superior made a takeover bid for all of the issued and outstanding shares of Canada Southern Petroleum Ltd. Canadian Superior offered 2.75 common shares of Canadian Superior plus $2.50 for each issued and outstanding share of Canada Southern Petroleum Ltd.  On July 17, 2006, Canadian Superior revised its offer for Canada Southern Petroleum Ltd. to 2.0 Canadian Superior shares, $2.50. cash and a 25% net profit interest in Canada Southern’s approximately 927 bcfe of natural gas, being the estimated net amount of natural gas Canada Southern attributed to it’s interest in the Canadian Arctic Islands. The offer was for Canada Southern’s approximately 1,100 boe/d of oil and gas production and various lands including Canada Southern’s Canadian Arctic island interests.  The minimum condition attached to the revised offer was not met and there were 171,495 shares tendered to the original offer. Canadian Superior Issued 471,612 shares and paid $0.4 million to take up these shares. The costs incurred, including the fair value of the Canadian Superior shares issued, exceeded the $2.5 million received on the sale of the 171,495 Canada Southern shares. The difference has been recorded to loss on investment in the statement of operations, comprehensive loss and deficit.

18.  Subsequent event

On March 26, 2008, Canadian Superior closed the acquisition of Seeker Petroleum Ltd. (“Seeker”), a private company for consideration of approximately $51.2 million, before closing adjustments and including assumed net debt of approximately $8.5 million.  The purchase was funded through the issuance of common shares of the Company and advances from the credit facility.

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19.  Reconciliation with United States Generally Accepted Accounting Principals

The Company follows Canadian generally accepted accounting principles (“Canadian GAAP”) which differs in some respects with generally accepted accounting principles in the United States (“U.S. GAAP”). Significant differences in accounting principles that impact the Company’s financial statements are described below:

	2007	2006		2005
($ thousands, except per share amounts)		As restated	As previously reported	As restated	As previously reported
Net income (loss) in accordance with Canadian GAAP, as reported	(9,936)	(10,913)	(10,913)	3,056	3,056
Flow through shares
Income taxes	(2,685)	(1,005)	(3,147)	--	(1,283)
Property acquisitions
Depletion, amortization and accretion expense	304	339	339	452	452
Income taxes	(93)	(103)	(103)	(152)	(152)
Ceiling test
Write down of petroleum and natural gas properties	(5,709)	(2,873)	(2,873)	--	--
Income taxes	1,741	876	876	--	--
Depletion, depreciation and accretion expense	3,975	3,884	3,884	5,181	5,181
Income taxes	(1,212)	(1,185)	(1,185)	(1,742)	(1,742)
Stock based compensation	--	--	--	3,657	3,657
Change in valuation allowance	(2,542)	2,811	2,811	1,754	1,754
Convertible preferred share treatment	(1,186)	1,244	1,244	--	--
Net income (loss) in accordance with U.S. GAAP	(17,343)	(6,925)	(9,067)	12,206	10,923
Convertible preferred share treatment	(915)	(662)	(662)	--	--
Net income (loss) attributable to common shareholders in accordance with U.S. GAAP	(18,258)	(7,587)	(9,729)	12,206	10,923
Net income (loss) per share in accordance with U.S. GAAP
Basic	(0.13)	(0.06)	(0.08)	0.11	0.10
Diluted	(0.13)	(0.06)	(0.08)	0.11	0.10

The application of U.S. GAAP results in differences to the following balance sheet items:

	2007				2006
									As previously
							As restated		reported
Year ended December 31,	Canadian		United States		Canadian		United States		United States
Property, plant and equipment, net	186,154		154,724		185,426		155,425		155,425
Accounts payable and accrued liabilities	22,230		26,308		17,997		19,555		17,997
Convertible preferred shares	13,571		—		15,472		—		—
Future income tax liability	8,853		—		10,958		—		—
Share capital	186,557		226,487		162,276		202,043		207,026
Share capital – preferred shares	—		16,311		—		16,107		16,107
Contributed surplus	14,314		8,834		11,372		5,892		5,892
Equity portion of preferred shares	2,320		—		2,320		—		—
Deficit, opening	(12,319	)	(65,522	)	(1,406	)	(57,935	)	(59,218	)
Deficit, closing	(22,255	)	(83,780	)	(12,319	)	(65,522	)	(68,947	)

(a)   Flow-through shares

The Company finances a portion of its activities with flow through share issues whereby the tax deductions are renounced to the share subscribers.  The tax cost of the deductions renounced to shareholders is reflected as an increase in the future income tax liability and a reduction from the stated value of the shares. Under U.S. GAAP, share capital for flow-through shares issued after 1998 is stated at the quoted value of the shares at the date of issuance; the tax cost resulting from deduction renouncements, less any proceeds received in excess of the quoted value of the shares, must be included in the determination of the tax expense.

During the year, the Company determined that the 2006 and 2005 financial statements contained erroneously recorded adjustments related to the issuance and renouncement of flow through shares for U.S. GAAP. The table above outlines the adjustments to the 2005 and 2006 financial statements for U.S. GAAP purposes.

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(b)   Property Acquisitions

In prior years, the Company recorded property acquisitions from related parties in exchange for common shares at the exchange amount, pursuant to Canadian GAAP. Under U.S. GAAP, these related party acquisitions are recorded at the seller’s carrying amount. The resulting differences in the recorded carrying amounts of the properties results in differences in depletion and amortization expense in subsequent years.

(c)   Ceiling Test

At December 31, 2007, the Company applied a ceiling test to its petroleum and natural gas properties. Under Canadian GAAP, the application of this test required no adjustment to the carrying value of the Company’s petroleum and natural gas properties.

At December 31, 2007, under U.S. GAAP the Company applied a full cost ceiling test using a 10% discount rate to its petroleum and natural gas properties using December 31, 2007 prices of:

Gas (per thousand cubic feet)	$	6.97 CDN
Oil and natural gas liquids (per barrel)	$	93.39 CDN

The application of the test resulted in a $5.7 million pre-tax reduction ($4.0 million after tax) in the carrying value of the Company’s petroleum and natural gas properties under U.S. GAAP.

At December 31, 2006, the Company applied a ceiling test to its petroleum and natural gas properties. Under Canadian GAAP, the application of this test required no adjustment to the carrying value of the Company’s petroleum and natural gas properties.

At December 31, 2006, the Company applied a ceiling test to its petroleum and natural gas properties using December 31, 2006 prices of:

Gas (per thousand cubic feet)	$	6.25 CDN
Oil and natural gas liquids (per barrel)	$	67.58 CDN

The application of the test resulted in a $2.9 million pre-tax reduction ($2.0 million after tax) in the carrying value of the Company’s petroleum and natural gas properties under U.S. GAAP.

At December 31, 2005, the Company applied the ceiling test to its petroleum and natural gas properties using December 31, 2005 prices of:

Gas (per thousand cubic feet)	$	10.35 CDN
Oil and natural gas liquids (per barrel)	$	66.25 CDN

The application of the test resulted in no reduction in the carrying value of the Company’s petroleum and natural gas properties under either U.S. or Canadian GAAP for 2005.

The resulting differences in the recorded carrying amounts of the properties results in differences in depletion, amortization and accretion expenses in subsequent years.

(d)   Stock Based Compensation

On January 1, 2006 the Company adopted Statement of Financial Standards (SFAS), “Share-Based Payment.” This statement requires the Company to recognize the cost of employee services received in exchange for the Company’s equity instruments. Under SFAS No. 123(R) the Company is required to record compensation expense over an award’s vesting period based on the award’s fair value at the date of grant. The Company has elected to adopt SFAS No. 123(R) on a modified prospective basis; accordingly the financial statements for the period prior to January 1, 2006 will not include compensation cost calculated under the fair value method.

Prior to January 1, 2006 the Company applied Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees” and therefore recorded the intrinsic value of stock – based compensation as expense and applied the disclosure provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.”

24

(e)   Valuation Allowance

This adjustment reflects the accounting of an additional valuation allowance for U.S. GAAP purposes arising from the differences in treatment regarding write downs of Petroleum and Natural Gas Properties and reduced depletion, depreciation and accretion expense.

(f)    Preferred shares

The Company has reviewed the Convertible preferred shares and their treatment under SFAS No. 150 “accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” and SFAS No. 133 “accounting for Derivative Instruments and Hedging Activities”. While the shares are redeemable they are not manditoraly redeemable as defined by SFAS No. 150 and therefore would not cause the shares to be recorded as liabilities. In evaluating the embedded conversion option component in accordance with SFAS No. 133 the shares are indexed to the Company’s own stock and would not be required to be accounted for as a derivative under SFAS No. 133.  Under EITF 00-19 the preferred shares would be considered “conventional” and therefore not subject to the provisions of EITF 00-19. Accordingly the preferred shares have been accounted for as described by APB 14 resulting in the allocation of proceeds between the shares and warrants based on their relative fair values.

Additional U.S. GAAP Disclosures

FAS 133

At times the Company will use derivative financial instruments to manage commodity price exposure. Effective January 1, 2001 the Company adopted the provisions of FAS 133 which requires that all derivatives be recognized as assets and liabilities on the balance sheet and measured at fair value. Gains or losses, including unrealized amounts, on derivatives that have not been designated as hedges, or were not effective as hedges, are included in income as they arise.

For derivatives designated as fair value hedges, changes in the fair value are recognized in income together with changes in the fair value of the hedged item.  For derivatives designated as cash flow hedges, changes in the fair value of the derivatives are recognized in other comprehensive income until the hedged items are recognized in income. Any change in the fair value of the derivatives that is not effective in hedging the changes in future cash flows is included in income as they arise.

At December 31, 2007 and 2006 the Company did not have any derivative financial instruments that were not designated as fair value hedges.

FAS 153

In December 2004, the FASB issued FAS 153 which deals with the accounting for the exchanges of nonmonetary assets.  FAS 153 is an amendment of APB Opinion 29.  APB Opinion 29 requires that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged.  FAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for nonmonetary exchanges of similar productive assets and introduces a broader exception for exchanges of nonmonetary assets that do not have commercial substance.  FAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005.  The adoption of this standard did not impact the Company’s Financial Statements.

FAS 155 - Accounting for Certain Hybrid Financial Instruments

On February 16, 2006, FASB issued FASB Statement No. 155, Accounting for Certain Hybrid Instruments – an amendment of FASB Statement No. 133 and 140 (FAS 155), which allows an entity to elect to measure certain hybrid financial instruments at fair value in their entirety, with changes in fair value recognized in earnings. The fair value election will eliminate the need to separately recognize certain derivatives embedded in hybrid financial instruments under FASB Statement No. 133, Accounting for Derivative Instruments & Hedging Activities. This statement is effective for financial statements issued for fiscal years beginning after September 15, 2006.  The adoption of this standard did not impact the Company’s Financial Statements.

25

FAS 157 - Fair Value Measurement

FASB issued statement of Financial Accounting No. 157 Fair Value Measurement, this statement is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years.  Early adoption is permitted.  The standard provides enhanced guidance for using fair value to measure assets and liabilities, the information used to measure fair value, and the effect of fair value measurement on earnings.  The standard applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. It does not expand the use of fair value in any new circumstances. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the standard.

FIN 46 - Accounting for Variable Interest Entities

In January 2003, the FASB issued Financial Interpretation 46 “Accounting for Variable Interest Entities” (“FIN 46”) that requires the consolidation of Variable Interest Equities (“VIEs”).  VIEs are entities that have insufficient equity or their equity investors lack one or more of the specified elements that a controlling entity would have.  The VIEs are controlled through financial interests that indicate control (referred to as “variable interests”).  Variable interests are the rights or obligations that expose the holder of the variable interest to expected losses or expected residual gains of the entity.  The holder of the majority of an entity’s variable interests is considered the primary beneficiary of the VIE and is required to consolidate the VIE. In December 2003 the FASB issued FIN 46R which superseded FIN 46 and restricts the scope of the definition of entities that would be considered VIEs that require consolidation. The Company does not believe FIN 46R results in the consolidation of any additional entities.

FIN 47 - Conditional Asset Retirement Obligations

Effective December 31 2005, the Company adopted FIN 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. According to FIN 47, uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of a liability when sufficient information exists rather than preclude the need to record a liability. The adoption of this interpretation did not impact the Company’s Financial Statements.

FIN 48 - Accounting for Uncertainty in Income Taxes

Effective January 1, 2007, the Company adopted FIN 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.”  This interpretation requires that an entity recognize in the financial statements, the impact of a tax position, if that position is more likely than not to be sustained on examination by the taxing authorities, based on technical merits of the position.  Tax benefits resulting from such a position should be measured as the amount that is more likely than not on a cumulative basis to be sustained on examination.  FIN 48 also provides guidance on de-recognition, classification, interest and penalties on income taxes and accounting in interim periods.  The adoption of this interpretation did not impact the Company’s Financial Statements.

SAB 106

In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin 106 (“SAB 106”) regarding the application of FAS 143 by oil and gas producing entities that follow the full cost accounting method. SAB 106 states that after the adoption of FAS 143 the future cash flows associated with the settlement of asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. The Company excludes the future cash outflows associated with settling asset retirement obligations from the present value of estimated future net cash flows and does not reduce the capitalized oil and gas costs by the asset retirement obligation accrued on the balance sheet.  Costs subject to depletion and depreciation include estimated costs required to develop proved undeveloped reserves and the associated addition to the asset retirement obligations.  The adoption of SAB 106 in the fourth quarter of 2004 did not have a material effect on the results of the ceiling test or depletion, depreciation and amortization calculations.

26

SFAS No. 154 - Accounting Changes and Error Corrections

On 1 January 2006, the Company adopted the provisions of SFAS No. 154, Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.  This statement applies to all voluntary changes in accounting principle and changes the requirements for accounting for and reporting of a change in accounting principle. The statement requires retrospective application to prior periods’ Financial Statements of a voluntary change in accounting principle versus including the cumulative effect of changing to the new accounting principle in net income.  SFAS No. 154 carries forward many provisions of APB Opinion No. 20 without change, including the provisions related to the reporting of a change in accounting estimate, a change in the reporting entity, and the correction of an error.  The adoption of this standard did not impact the Company’s Financial Statements.

SFAS No. 159 - The Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115 (SFAS No. 159). This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective on January 1, 2008. The Company is currently evaluating the impact of this standard on its Financial Statements.

PRESENTATION

There are different presentations between Canadian and U.S. GAAP which are as follows:

1)Under U.S. GAAP, there is no difference between net income and other comprehensive income.

2)No subtotal is permitted under U.S. GAAP within cashflow from operations on the statement of cashflows.

27

EX-99.3

Exhibit 99.3

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) has been prepared by management as of March 27, 2008 and reviewed and approved by the Board of Directors of Canadian Superior Energy Inc. (“Canadian Superior” or the “Company”).  This MD&A is a review of the operational results of the Company with disclosure of oil and gas activities in accordance with Canadian Securities Association National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and a review of financial results of the Company based on Canadian Generally Accepted Accounting Principles (“GAAP”).  The reporting currency is the Canadian dollar.  This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2007 and 2006.

Non-GAAP Measures – This MD&A contains the term cash flow from operations and operating netback, which are non-GAAP financial measures that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other issuers.  Management believes cash flow from operations and operating netback are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures and repay debt.  Cash flow from operations and operating netback should not be considered an alternative to or more meaningful than cash flow from operating activities, as determined in accordance with GAAP, as an indicator of the Company’s performance.  In the Operating netback and cash flow from Operations section of this MD&A, a reconciliation has been prepared of cash flow from operations and operating netback to cash from operating activities, the most comparable measure calculated in accordance with GAAP.

Boe Presentation – Production information is commonly reported in units of barrel of oil equivalent (“boe”).  For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil.  This conversion ratio of 6:1 is based on an energy equivalent wellhead value for the individual products.  Such disclosure of boes may be misleading, particularly if used in isolation.  Readers should be aware that historical results are not necessarily indicative of future performance.

Forward-Looking Statements – Certain information regarding the Company presented in this document, including management’s assessment of the Company’s future plans and operations, may constitute forward-looking statements under applicable securities law and necessarily involve risk associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risk, competition from other producers and ability to access capital from internal and external resources, and as a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Statements contained in this document relate to forward-looking information, including estimates, projections, interpretations, prognoses and other information that may relate to current past or future production, development(s), testing, well test results, project start-ups and future capital spending.  Current, past and/or future actual results and/or reported results, estimates, projections, interpretations, prognoses, well results, test results, reserves, production, resource and/or resource potential, development(s), project start-ups, and capital spending, plans and/or estimated results could differ materially due to changes in project schedules, operating performance, demand for oil and gas, commercial negotiations or other technical and economic factors or revisions.  This document may contain the reference to the terms discovery, reserves and/or resources or resource potential which are those quantities estimated to be contained in accumulations.  There is no certainty that any portion of these accumulations or estimated accumulations in this document may not change materially; and that, if discovered, in this or any other discovery, the accumulations or estimated accumulations may not be economically viable or technically feasible to produce.

Statements contained in this document relating to estimates, results, events and expectations are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended.  These forward-looking statements involve known and unknown risks, uncertainties, scheduling, re-scheduling and other factors which may cause the actual results, performance, estimates, projections, interpretations, prognoses, schedules or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such statements.  Such factors include, among others, those described in the Company’s’ annual reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.

Business of Canadian Superior

Canadian Superior Energy Inc. (“Canadian Superior” or the “Company”) is engaged in the exploration for, and acquisition, development and production of petroleum and natural gas primarily in Western Canada and offshore Nova Scotia, Canada and Trinidad and Tobago.

1

Operating netback and cash flow from operations

	($ thousands)						($ per boe)
Three months ended December 31,	2007		2006		% change		2007		2006		% change
Revenue
Petroleum and natural gas sales	13,215		13,477		(2	)	44.93		46.17		(3	)
Transportation	(176	)	(158	)	(11	)	(0.60	)	(0.54	)	(11	)
Royalties net of royalty tax credit	(1,851	)	(2,346	)	21		(6.29	)	(8.04	)	22
	11,188		10,973		2		38.04		37.58		1
Operating expenses	3,392		3,302		(3	)	11.53		11.31		(2	)
Operating netback(1)	7,796		7,671		2		26.51		26.27		1
General and administrative	4,346		2,695		61		14.78		9.23		60
Asset retirement expenditures	361		—		n/a		1.23		—		n/a
Forfeiture of Nova Scotia Term Deposits	(500	)	(558	)	(10	)	(1.70	)	(1.91	)	(11	)
Interest and other income	(230	)	(1,171	)	(80	)	(0.78	)	(4.01	)	(81	)
Foreign exchange gain loss	(234	)	(191	)	23		(0.80	)	(0.65	)	22
Interest	965		309		212		3.28		1.06		210
Capital taxes	55		—		n/a		0.19		—		n/a
Cash flow from operations(1)	3,033		6,587		(54	)	10.31		22.56		(54	)
Changes in non-cash working capital	9,040		(8,307	)	209		30.74		(28.45	)	208
Cash provided (used) by operating activities	12,073		(1,720	)	802		41.05		(5.89	)	797

(1) Non-GAAP measure

	($ thousands)						($ per boe)
Twelve months ended December 31,	2007		2006		% change		2007		2006		% change
Revenue
Petroleum and natural gas sales	48,492		49,428		(2	)	46.72		46.88		0
Transportation	(645	)	(662	)	3		(0.62	)	(0.63	)	1
Royalties net of royalty tax credit	(7,914	)	(8,245	)	4		(7.63	)	(7.82	)	2
	39,933		40,521		(1	)	38.48		38.43		0
Operating expenses	9,883		9,042		9		9.52		8.58		11
Operating netback(1)	30,050		31,479		(5	)	28.95		29.86		(3	)
General and administrative	13,315		9,312		43		12.83		8.83		45
Asset retirement expenditures	361		—		n/a		0.35		—		n/a
Forfeiture of Nova Scotia Term Deposits	(500	)	(558	)	(10	)	(0.48	)	(0.53	)	(9	)
Interest and other income	(925	)	(1,371	)	(33	)	(0.89	)	(1.30	)	(31	)
Foreign exchange (gain) loss	1,690		(69	)	(2,549	)	1.63		(0.07	)	(2,588	)
Interest	2,199		1,049		110		2.12		0.99		113
Capital taxes	55		33		67		0.05		0.03		69
Cash flow from operations(1)	13,855		23,083		(40	)	13.35		21.89		(39	)
Changes in non-cash working capital	(4,993	)	(8,453	)	41		(4.81	)	(8.02	)	40
Cash provided by operating activities	8,862		14,630		(39	)	8.54		13.88		(38	)

(1) Non-GAAP measure

For the three months ended December 31, 2007, cash flow from operations was $3.0 million compared to $6.6 million in 2006 and for the year ended December 31, 2007, $13.9 million compared to $23.1 million in 2006.  The decrease in cash flow from operations is mainly due to increased general and administrative expenses for the commencement of the Trinidad and Tobago “Intrepid” Block 5(c) project, staffing increases and the payout of two management contracts in the fourth quarter of 2007.  In addition, Canadian Superior incurred higher interest costs due to increased capital expenditures for drilling of the offshore Victory well in Trinidad and Tobago.

2

Production

	Three months ended		Year ended
December 31,	2007	2006	2007	2006
Natural gas (mcf/d)	15,366	14,417	13,496	13,414
Crude oil and natural gas liquids (bbls/d)	636	770	594	653
Total Production (boe/d) (6:1)	3,197	3,173	2,843	2,889

Canadian Superior’s production for the fourth quarter averaged 3,197 boe per day and for the twelve months ended December 31, 2007 2,843 boe per day.  Successful drilling results and new well tie-ins more than offset natural declines in existing production.

Petroleum and natural gas sales, net of transportation

($ thousands, except where otherwise noted)	Three months ended		Year ended
December 31,	2007	2006	2007	2006
Petroleum and Natural Gas Sales, net of transportation
Natural gas	8,309	9,529	33,111	34,014
Crude oil and natural gas liquids	4,703	3,798	14,736	14,759
Total	13,039	13,327	47,847	48,773
Average Sales Price
Natural gas ($/mcf)	5.88	7.18	6.72	6.95
Crude oil and natural gas liquids ($/bbl)	80.82	53.62	67.95	61.95
Total ($/boe)	44.33	45.66	46.10	46.26

Petroleum and natural gas sales, net of transportation (“petroleum and natural gas sales”) were $13.0 million in the fourth quarter of 2007, consisting of $8.3 million in natural gas and $4.7 million of crude oil and natural gas liquids sales.  Benchmark natural gas prices were significantly lower in the fourth quarter of 2007 compared to 2006.  The decline in prices was marginally offset by increased production volumes in 2007 compared to prior year.  During the quarter, Canadian Superior realized an average price for crude oil and natural gas liquids of $80.82 per bbl compared to $53.62 per bbl in 2006 which more than offset the 17% decline in crude oil and natural gas liquids production in 2007.

For the twelve months ended December 31, 2007, petroleum and natural gas sales were $47.8 million compared to $48.8 million in 2006.  Increased natural gas production during the year was more than offset by the impact of lower natural gas prices in 2007 compared to 2006.  Canadian Superior continued to benefit from higher crude oil prices in 2007 which more than offset the impact of declining crude oil production during the year.

All the Company’s production is currently sold on the spot market.  Management is currently evaluating different hedging strategies to decrease the volatility of sales price and fluctuations in cash flow from operations.

3

Royalties

($ thousands, except where otherwise noted)	Three months ended			Year ended
December 31,	2007	2006		2007	2006
Royalties
Crown	1,160	2,076		5,901	6,866
Freehold and overriding	691	395		2,013	1,879
Alberta royalty tax credit	—	(125	)	—	(500	)
Total	1,851	2,346		7,914	8,245
Royalties per boe	6.29	8.04		7.63	7.82
Average royalty rate (%)	14.2	17.6		16.5	16.9

Canadian Superior pays royalties to provincial governments, freehold landowners and overriding royalty owners.  Royalties are calculated and paid based on petroleum and natural gas sales net of transportation.  Natural gas and liquids royalties for the fourth quarter of 2007 were $1.9 million or 14.2% of total petroleum and natural gas sales.  The decrease in royalties from prior year is due to certain wells reverting to low productivity status.  For the twelve months ended December 31, 2007, natural gas and liquids royalties were $7.9 million or 16.5% of total petroleum and natural gas sales compared to $8.2 million or 16.9% in 2006.

Alberta royalty review

The Government of Alberta has completed a comprehensive review of the province’s oil and natural gas royalty structure.  The Company is currently evaluating how the potential changes may impact the Company’s operations.  The Company believes that there could be a negative effect to the financial operations due to higher royalties on the Company’s petroleum and natural gas sales.

Operating expenses

Operating expenses were $3.4 million or $11.53 per boe for the fourth quarter.  For the twelve months ended December 31, 2007, operating expenses were $9.9 million or $9.52 per boe compared to $9.0 million or $8.58 per boe in 2006.  Canadian Superior incurred higher operating expenses in 2007 as a result of increased field and processing costs.

General and administrative expenses

($ thousands, except where otherwise noted)	Three months ended				Year ended
December 31,	2007		2006		2007		2006
Gross general and administrative expense	4,467		4,440		16,122		16,866
Capitalized general and administrative expense	(121	)	(1,745	)	(2,807	)	(7,554	)
Net general and administrative expense	4,346		2,695		13,315		9,312
General and administrative expense ($/boe)	14.78		9.23		12.83		8.83

For the twelve months ended December 31, 2007, G&A expense was $13.3 million or $12.83 per boe.  The increase from prior year is mainly due to the significant startup costs that Canadian Superior incurred in 2007 to develop the technical team and resources needed for the “Intrepid” Block 5(c) project in Trinidad and Tobago.  In addition, the Company recognized approximately $3.7 million in obligations to a number of officers and directors due to corporate restructuring during the year of which $1.9 million was paid.

Stock based compensation

During the year ended December 31, 2007, Canadian Superior incurred stock based compensation expenses of $4.2 million compared to $5.9 million in 2006.  The decrease from prior year is due to a lower amount of stock options being granted in 2007 compared to 2006.

4

Depletion, depreciation and accretion

Depletion, depreciation and accretion (“DD&A”) was $26.6 million or $25.62 per boe for the twelve months ended December 31, 2007 of which $7.6 million or $25.88 per boe was incurred in the fourth quarter.  In calculating DD&A expense for 2007 the Company included an estimated $8.7 million (2006 - $9.3 million) for future development capital associated with proven undeveloped reserves and excluded $54.4 million (2006 - $67.0 million) related to unproved properties and projects under construction or development.  Of the costs excluded $20.8 million (2006 - $22.7 million) relates to Western Canada, $8.8 million (2006 - $8.8 million) to East Coast Canada and $24.8 million (2006 - $35.5 million) to Trinidad and Tobago.  Canadian Superior’s DD&A per boe is high compared to other exploration and production companies its size, due to significant expenditures incurred to drill and evaluate the Company’s offshore wells in the East Coast of Canada being included in the depletable base with no associated proven reserves reflected.

Income taxes

Canadian Superior’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilled exploration and development wells.  The Company had a future income tax expense for the fourth quarter of $3.3 million and a future income tax recovery of $6.0 million for the year ended December 31, 2007.

At December 31, 2007, the Company had $149.7 million in tax pools and $3.0 million in non-capital losses that are available for future deduction against taxable income.

	December 31
($ thousands)	2007
Canadian exploration expense	32,154
Canadian oil and gas property expense	45,197
Canadian development expense	29,335
Undepreciated capital costs	22,060
Share issue costs	4,098
Foreign exploration expense	16,048
Other	781
Total	149,673

Non-capital losses expire as follows:

($ thousands)
2008	—
2009	—
2010	—
2011 and thereafter	2,970
	2,970

Capital expenditures

($ thousands)	Three months ended			Year ended
December 31,	2007	2006		2007		2006
Acquisitions (dispositions)	120	(823	)	(41,061	)	(716	)
Exploration and development	20,148	7,630		52,191		37,872
Plants, facilities and pipelines	2,753	2,209		7,246		6,675
Land and lease	1,608	665		3,789		3,984
Capitalized expenses	121	1,745		2,807		7,554
Net capital expenditures	24,750	11,426		24,972		55,369

5

The Company invested $24.8 million for capital expenditures during the fourth quarter of which the majority was spent to complete the drilling of the “Victory” well offshore Trinidad, to drill 5 gross wells (4.8 net) in the Drumheller area and to purchase Crown land at the Peace River Arch area.  During the year ended December 31, 2007, the Company expended $25.0 million of which the majority related to commencement of the Trinidad and Tobago “Intrepid” Block 5(c) project which included drilling the first well “Victory” in the three well project.  In addition, the Company drilled 73 gross (25 net) wells in Western Canada, which includes 40 wells drilled to earn gross overriding royalties ranging from 10%-15%.

In 2007, the Company entered into a farm in and joint operating agreement with BG International Limited (“BG”) to participate in the exploration drilling and development of the “Intrepid” Block 5(c) approximately sixty miles off the east coast of the island of Trinidad.  Under the terms of the farm-in and joint operating agreements, BG acquired a 30% working interest in Canadian Superior’s “Intrepid” Block 5(c) Production Sharing Contract; the agreement was approved by the Government of Trinidad and Tobago on October 29, 2007. Also, under the terms of the agreement with Canadian Superior, BG paid Canadian Superior approximately US$38.7 million and on a go forward basis will pay approximately 40% of the exploration costs associated with the drilling of the three commitment wells required on Block 5(c).  The farm in has been recorded as a reduction to Trinidad capital and general and administrative costs in 2007.

Well count

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2007:

	Oil wells				Natural gas wells
	Producing		Non-producing		Producing		Non-producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Total	79	59.6	28	17.9	269	125	113	68

Land holdings

The following table sets out the Company’s undeveloped land holdings as at December 31, 2007:

	Undeveloped
	Gross	Net
(acres)
British Columbia	1,974	694
Alberta	105,060	85,847
Saskatchewan	40	40
Offshore Nova Scotia	1,234,546	1,234,546
Offshore Trinidad and Tobago	102,292	71,604
Total	1,443,912	1,392,731

Liquidity and capital resources

($ thousands)
December 31,	2007		2006
Working capital surplus excluding revolving credit facility	30,447		7,240
Revolving credit facility	(17,784	)	(7,910	)
Working capital surplus (deficit)	12,663		(670	)

As at December 31, 2007, Canadian Superior had a working capital surplus of $12.7 million.  The Company had drawn $17.8 million against the $45 million revolving credit facility (“credit facility”) at a variable interest rate of prime + 1%.  The credit facility is secured by a $100 million first floating charge demand debenture on the assets of the Company and a general security agreement covering all of the assets of the Company.  The credit facility has covenants that require the Company to maintain its working capital ratio at 1:1 or greater, tangible net worth to total liabilities at 1.5:1.0 or greater and tangible net worth at greater than $100 million while the credit facility is outstanding.  The borrowing base of the credit facility is subject to an annual review by the lender.  The Company

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had $13.7 million in cash and short-term deposits and $14.6 million of term deposits posted as security against the remaining Offshore Nova Scotia work expenditure bids.

On November 16, 2007, the Company completed a private placement of 6,472,500 flow-through common shares at $3.50 per share for gross proceeds of $22.7 million.

On December 31 2007, 500,000 warrants were exercised into 500,000 common shares at US$ 2.50 per share for gross proceeds of US$1.3 million.

In 2007, the Company entered into a farm in and joint operating agreement with BG International Limited (“BG”) to participate in the exploration drilling and development of the “Intrepid” Block 5(c) approximately sixty miles off the east coast of the island of Trinidad. Under the terms of the farm-in and joint operating agreements, BG acquired a 30% working interest in Canadian Superior’s “Intrepid” Block 5(c) Production Sharing Contract; the agreement was approved by the Government on October 29, 2007. Also, under the terms of the agreement with Canadian Superior, BG paid Canadian Superior approximately US$38.7 million and on a go forward basis will pay approximately 40% of the exploration costs associated with the drilling of the three commitment wells required on Block 5(c).

The Company generally relies on cash flow from operations, credit facility availability and equity financings to fund its capital requirements and to provide liquidity.  Cash is primarily used, and will continue to be used, to fund acquisitions, exploration and development of petroleum natural gas properties, expenses for continued operations, G&A costs and/or repayment of principal and interest outstanding on the credit facility.

The Company’s cash flow from operations is directly related to underlying commodity prices and production volumes.  A significant decrease in commodity prices could materially impact the Company’s future cash flow from operations and liquidity.  In addition, a substantial decrease in commodity prices could impact the Company’s borrowing base under the credit facility, therefore reducing the credit facility available, and in some instances, require a portion of the credit facility to be repaid.  Canadian Superior has not entered into any risk management contracts to mitigate its commodity price risk, however management is currently considering various options.  The Company’s future liquidity is also dependent on its ability to increase reserves and production through successful drilling activity and acquisitions.

Canadian Superior’s 2008 exploration and development program will be financed through a combination of cash flow from operations, credit facility utilization, additional equity financings, potential farm outs or joint ventures and possibly through the release of secured offshore term deposits as additional work expenditures are incurred.

Contingencies and commitments

Nova Scotia

During 2000, 2001 and 2003, the Company acquired six exploration licenses from the Canada-Nova Scotia Offshore Petroleum Board (“CNSOPB”).  Each of these licenses is for a specific period of nine years, subject to certain requirements being met during the first five years or six years.  As a condition of the licenses, the Company is required to post security in the amount of 25% of its work expenditure bids. The deposit is refundable only to the extent of approved allowable expenditures.  The duration of the initial five year term, for a given license, can be extended one additional year to six years by posting an additional security drilling deposit in an amount of $250,000. Recently the CNSOPB implemented an additional extension program that allows the six year period to be further extended up to nine years by payment of annual extension fees.  As of December 31, 2007, as a result of the Company incurring certain expenditures and drilling two exploration wells, the Company had fully fulfilled its work expenditures on two of the exploration licenses, allowed three licenses to return to the Crown, extended one license and held the remaining two under the regular licensing process.  At December 31, 2007, the Company’s owned 100% of five exploration licenses that have aggregate work expenditure outstanding of $55.1 million and $14.6 million in term deposits assigned to the Canadian Receiver General through the CNSOPB.

Trinidad and Tobago

The Company is committed to drill three exploration wells on its “Intrepid” Block 5(c) under its Block 5(c) Production Sharing Contract (“PSC”) with the Government of Trinidad and Tobago funded in part by a related party participating on a promoted basis, paying 1/3 of Canadian Superior’s Block 5(c) exploration program to obtain 25% of Canadian Superior’s net revenue share of these prospects; and, also by a non-related party paying approximately 40% of the exploration cost, plus other considerations, for a 30% interest in the Block 5(c) PSC.  The Company has contracted the Kan Tan IV Semi-Submersible Drilling Rig for a three well commitment on the Company’s Trinidad and Tobago “Intrepid” Block 5 (c). In 2007, the Company had drilled and commenced testing of the first well.  The second well in

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this program was spudded in February 2008.  The Company estimates that the costs to drill the remaining two wells to be in the range of US $65.0 million to US $75.0 million gross per well.  The wells will be drilled and evaluated back to back, with this three well program expected to be completed in 2008.

During the third quarter of 2007, the Company received an exploration and development license from the Government of Trinidad and Tobago on the Mayaro-Guayaguayare block (“MG Block”) and as a result is committed to conducting 3D seismic and to drill two exploration wells on the MG block in a joint venture with the Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”).  The first well has to be drilled to a depth of 3,000 meters by January 2010 and the second to a depth of 1,800 meters by July 2010. The Company estimates that its share of the cost of these wells to be in the range of US$15.0 million per well, with the 3D seismic program to be completed in 2008 at a net cost to the Company of approximately US$20.0 million.

Flow-through shares

At December 31, 2007, the Company had yet to incur approximately $22.7 million of Canadian exploration expenses which were renounced for tax purposes.  These expenses must be incurred by December 31, 2008.

Litigation and claims

The Company is involved in various claims and litigation arising in the ordinary course of business.  In the opinion of Canadian Superior the various claims and litigations arising there from are not expected to have a material adverse effect on the Company’s financial position.  The Company maintains insurance, which in the opinion of the Company, is in place to address any unforeseen claims.

Lease obligations

At December 31, 2007, the Company is committed to future payments for office leases and equipment.  Payments required under these commitments for each of the next five years are as follows:

	2008	2009	2010	2011	Thereafter
Office rent	317	249	226	57	—
Equipment	155	77	42	—	—
	472	326	268	57	—

Related parties transactions

During the year ended December 31 2007, the Company paid $1.9 million (2006 - $0.8 million), on industry terms, for equipment rentals to a company controlled by an officer and director of Canadian Superior.  Also during 2007, the Company invoiced $0.7 million (2006 - nil), at market rates, to this related party company for payroll services.  In addition, Canadian Superior paid $0.2 million (2006 - $0.2 million) to a Company controlled by a director, for oil field construction services on industry terms.

At December 31, 2007, Canadian Superior is carrying a receivable in the amount of US$19.7 million (2006 – nil) from a company which one of Canadian Superior’s officers and directors is a shareholder and director.  These receivables pertain to transactions for Canadian Superior’s “Intrepid” Block 5(c) project at Trinidad.  These transactions were incurred under normal industry terms and conditions.  Subsequent to year end, the Company received payment of US$20.0 million from this related company.

Off-balance sheet arrangements

The Company has no off-balance sheet arrangements.

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Share capital

As at March 27, 2008, the Company had 148.1 million Class A common shares and 17.2 million stock options issued and outstanding.

Financial instruments

Fair value of financial assets and liabilities

The carrying values of financial assets and liabilities approximate their fair value due to their short periods of maturity and the credit facility bearing interest at market rates.

Credit risk

The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business under normal industry sale and payment terms and are subject to normal credit risks.  Purchasers of the Company’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment.

Foreign exchange risk

The Company is exposed to foreign currency fluctuations as oil and gas prices received are referenced to U.S. dollar denominated prices and convertible preferred shares are denominated in U.S. dollars.  The Company also has assets and liabilities based in US currency that is subject to interest rate fluctuations.

Interest rate risk

The Company is exposed to interest rate risk as the credit facility bears interest at floating market interest rates.  The Company has no interest rate swaps or hedges at December 31, 2007.

Commodity price risk

The Company 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. At December 31, 2007, the Company had no contracts in place.

Subsequent event

On March 26, 2008, Canadian Superior closed the acquisition of Seeker Petroleum Ltd. (“Seeker”), a private company for consideration of approximately $51.2 million, before closing adjustments and including assumed net debt of approximately $8.5 million.  The purchase was funded through the issuance of common shares of the Company and advances from the credit facility.

Adoption of new accounting policies

On January 1, 2007, Canadian Superior adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (“CICA”): Comprehensive Income (Section 1530), Financial Instruments – Recognition and Measurement (Section 3855), Financial Instruments – Disclosure and Presentation (Section 3861) and Hedges (Section 3865).  In accordance with the new standards, changes are adopted retroactively without restatement of prior period information.  The other effects of the implementation of these new standards are discussed below.

Comprehensive Income

Section 1530 provides for a new Statement of Comprehensive Income and establishes Accumulated Other Comprehensive Income (“AOCI”) as a separate component of shareholders’ equity.  The Statement of Comprehensive Income is defined as a change in net assets arising from transactions and other events from non-owner sources.  The statement would present net income and each component recognized in other comprehensive income (“OCI”) when such amounts exist.  For the year ended December 31, 2007, the Company did not recognize any OCI.  Any future OCI recognized by the Company will be recognized in AOCI.

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Financial Instruments – Recognition and Measurement

Section 3855 requires all financial assets and liabilities, including derivatives, to be carried at fair value on the Company’s balance sheet with the exception of loans and receivables, investments that are intended to be held to maturity and non-trading financial liabilities which are carried at cost or amortized cost.

The Company has reviewed and classified its financial instruments as follows:

·Cash, short-term investments and Nova Scotia offshore term deposits are classified as financial assets held for trading and are measured at their fair value.  Gains or losses related to periodic revaluation are recorded to net income or loss.

·Accounts receivable are classified as loans and receivables and are initially measured at their fair value.  Subsequent periodic revaluations are recorded at their amortized cost using the effective interest rate method.

·Accounts payable, accrued liabilities, revolving credit facility and convertible preferred shares are classified as other liabilities and are initially measured at fair value.  Subsequent periodic revaluations are recorded at their amortized cost using the effective interest rate method.

Derivatives and Hedge Accounting

Derivatives may be embedded in other financial instruments (the “host instruments”).  Prior to the adoption of the new standards, such embedded derivatives were not accounted for separately from the host instrument.  Under the new standard, embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not clearly and closely related to those of the host instrument, the terms of the embedded derivative are the same as those of the stand-alone derivative, and the combined contract is not held for trading or designated at fair value.  A review of the Company’s financial contracts determined that there were no embedded derivatives.  In the event that the Company enters into a contract that contains an embedded derivative, the embedded derivative will be measured at fair value with subsequent changes recognized in earnings or loss.

At January 1, 2007 no transitional adjustments were required to the opening balance of retained earnings or to the opening balance of AOCI arising from the adoption of sections 1530, 3855, and 3865.

New accounting pronouncements

The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have a significant impact on the Company:

As of January 1, 2008, the Company will be required to adopt the following two new CICA standards: Financial Instruments - Disclosures (Section 3862) and Financial Instruments - Presentation (Section 3863), which will replace Financial Instruments - - Disclosure and Presentation (Section 3861).  The new disclosure standard increases the emphasis on the risks associated with both recognized and unrecognized financial instruments and how those risks are managed.  The new presentation standard carries forward former presentation requirements.

As of January 1, 2008, the Company will be required to adopt CICA standards, Capital Disclosures (Section 1535), which will require companies to disclose their objectives, policies and processes for managing capital.  In addition, disclosures are to include whether companies have complied with externally imposed capital requirements.

Both new standards were issued in December 2006 and the Company is assessing the impact on its financial statements.

A strategic plan has been adopted by the Accounting Standards Board for the future direction of accounting standards in Canada.  It is expected that Canadian accounting standards for public companies will converge with International Financial Reporting Standards (“IFRS”).  On December 31, 2008, the Company will be required to provide a preliminary disclosure of policy impacts of upon adopting IFRS.  The Company is in the initial stages of assessing IFRS and its impacts on the consolidated financial statements.

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Sensitivities

The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices on 2007 petroleum and natural gas sales and is based on the balances disclosed in this MD&A and the consolidated financial statements for the twelve months ended December 31, 2007:

	Petroleum and
	Natural Gas
($ thousands)	Sales (1)
Change in average sales price for natural gas by $1.00/mcf	4,926
Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl	217
Change in natural gas production by 1 mmcf/d (2)	2,453
Change in crude oil and natural gas liquids production by 100 bbls/d (2)	2,480

(1)	Reflects the change in petroleum and natural gas sales for the twelve months ended December 31, 2007. Balances have not been annualized.
(2)	Reflects the change in production multiplied by the Company’s average sales prices for the twelve month period ended December 31, 2007.

Quarterly financial summary

($ thousands except per share and production amounts)

	2007							2006
	Q4		Q3		Q2	Q1		Q4		Q3		Q2	Q1
Production
Natural gas mcf/d	15,366		12,838		11,802	13,984		14,417		12,983		12,674	13,580
Oil and natural gas liquids bbl/d	636		516		656	566		770		645		570	625
Total boe/d	3,197		2,656		2,623	2,897		3,173		2,808		2,682	2,889
Petroleum and natural gas sales	13,039		10,248		11,961	12,599		13,327		11,185		10,839	13,423
Net income (loss)	(9,129	)	(2,865	)	2,187	(129	)	(4,839	)	(5,753	)	254	(575	)
Earnings (loss) per share - basic	(0.07	)	(0.02	)	0.02	0.00		(0.04	)	(0.05	)	0.00	0.00
Cash flow from operations	3,033		2,101		2,251	6,470		5,409		3,992		5,341	6,761
Cash flow per share - basic	0.02		0.02		0.02	0.05		0.05		0.03		0.04	0.06

Disclosure controls and procedures and internal control over financial reporting

Disclosure controls and procedures are designed to provide reasonable assurance that material information is gathered and reported to senior management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CEO”), as appropriate to allow timely decisions regarding public disclosure.

Our management, including the CEO and CFO, has evaluated the effectiveness of the Company’s disclosure control and procedures as of December 31, 2007. Based on this evaluation, our management concluded that the Company’s disclosure controls and procedures, as defined in Multilateral Instrument 52-109 Certification of Disclosure in Issuer’s Annual and Interim Filings (“MI 52-109”), as of December 31, 2007 was not effective to provide reasonable assurance that the information required to be disclosed in reports that are filed or submitted under Canadian Securities legislation are recorded, processed, summarized and reported within the time period specified in those rules.

During the fourth quarter of 2007 a new CEO was hired along with a new CFO and finance and accounting team in the first quarter of 2008. Although material weaknesses existed at December 31, 2007, the Corporation has taken significant steps in the first quarter of 2008 to alleviate in the near term some of the noted material weaknesses, such as segregation of duties and financial preparation and review procedures and has implemented an aggressive plan that by the end of 2008 all noted material weaknesses at December 31, 2007 will be substantially eliminated.

Management’s assessment identified the following material weaknesses in internal control over financial reporting as of December 31, 2007:

·There are no effective controls or procedures related to significant accounts or processes to provide reasonable assurance that transactions are recorded accurately, are recorded timely and are complete;

·The Corporation was not adequately staffed with accounting personnel possessing an adequate level of technical expertise and did not maintain effective segregation of duties over automated and manual transactions leading to ineffective monitoring, supervision and reviews.

·The Corporation did not maintain effective controls over the safeguarding of monetary assets. The material weakness affects cash and short-term investments.

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Remediation Effort

The Company is taking steps to augment and improve the design of procedures and controls impacting these areas of weakness in internal controls over financial reporting. These material weaknesses have been discussed with the Audit Committee by the new CFO. The Audit Committee is taking an active role in overseeing management’s implementation of the remedial measures described below. By implementing these remedial measures, management intends to improve our internal control over financial reporting to reduce the risk of material misstatements in consolidated financial statements prepared for external purposes, in the future. We have implemented or are implementing the following measures, which will improve significantly our internal control over financial reporting:

· The hiring of a new CFO and Corporate Controller and key additional operational accounting and financial reporting staff of which a number are Chartered Accountants with Canadian and US financial and regulatory reporting experience;

· The implementation of regular management meetings to provide operational, financial, and accounting updates of the Corporation;

· A budgeting process which will compare actual results to budgeted results for management to review and query on a monthly basis;

· The implementation of controls to safeguard monetary assets; and

· The initiation of an ongoing and comprehensive review of financial controls and procedures to address the issues identified above and to bring into compliance with the requirements of the Sarbanes-Oxley Act with respect to internal controls and procedures.

Management believes that, through implementation of the measures noted above, we will address the conditions identified above as material weaknesses. We will monitor the effectiveness of these measures, and our internal control over financial reporting on an ongoing basis. We will continue to asses our remediation plans and will take further action, as appropriate, to strengthen our internal control over financial reporting.

Critical accounting estimates

To prepare the financial statements in accordance with GAAP, management is required to make judgments and estimates that could influence the financial results of the Company.  Management continually reviews its estimates, but changes in facts or circumstances may result in revised estimates and actual results may differ from these estimates.  A summary of the Company’s critical accounting polices has been provided in note 1 of the consolidated financial statements.  The Company’s critical accounting estimates are discussed below.

Petroleum and Natural Gas Reserves

The Company uses the full cost method of accounting for its oil and gas activities, which are dependent on estimated reserves that management believes are recoverable from its oil and gas properties.  The process for estimating reserves is complex and subjective.  The Company’s determination of reserves is based on a combination of:

·  geological, geophysical and engineering estimates;

·  future production rates;

·  future commodity prices; and

·  future development and operating costs.

Management believes these factors to be reasonable based on the information that is available as of the time of the estimate of reserves and is subsequently reviewed by its independent engineers.  Estimates of these factors can significantly change over time as additional data relating to development, production, pricing and costs is received for its oil and gas properties.

All of the Company’s reserves are evaluated and reported on by independent engineers in accordance with NI 51-101.  In addition, the Company has established a Reserves Committee to assist the Board of Directors and the

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Audit Committee to review its oil and gas reserves and other related disclosures.  The Reserves Committee is comprised of three members of the Board of Directors.

The Company’s estimate of reserves impacts the accounting for depletion and impairment expense.  In addition, Canadian Superior’s borrowing base for the credit facility is determined based on estimates of proved reserves.

Full Cost Impairment

The Company evaluates its oil and gas properties for impairment if a significant event or change occurs.  This can include a significant decrease in oil and gas prices, revisions to proved reserves, changes in operating expenses or changes in its operating environment.

The Company’s oil and gas properties are evaluated for impairment by comparing the undiscounted future net cash flows of the property against its carrying value.  The property is written down to its fair value if the carrying value is greater than the calculated fair value.  The Company calculates the fair value based on the discounted cash flow approach.

The calculation of undiscounted future net cash flows by management requires significant assumptions to be made for future prices and reserves.  The Company’s estimates for future prices are based on benchmark prices compiled by independent engineers, adjusted to reflect risk management contracts, transportation expense or quality differentials.

Management believes the assessment of impairment of oil and gas properties is a critical accounting estimate primarily due to the complexity of the assumptions used in the calculation.

The Company’s oil and gas properties were evaluated for impairment as at December 31, 2007, and based on its estimates, no impairments were required.  In the existence of an impairment charge, the Company would record an increase in depreciation and depletion expense for the period.

Asset Retirement Obligations

The Company has a legal obligation associated with the retirement of present and former operating sites.  Management is required to make significant estimates and assumptions to calculate the estimated fair value of future retirement of its tangible assets.  This includes making estimates of future activities and environmental rules and regulations that could potentially impact the Company’s future retirement obligation.

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and records a corresponding increase in the carrying value of the related long-lived asset.  The fair value is determined through a review of engineering studies, industry guidelines and management’s estimate on a site-by-site basis.  The liability is subsequently adjusted for the passage of time and is recognized as accretion expense in the statement of operations.  The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability.  The increase in the carrying value of the asset is amortized using the unit-of-production method based on estimated proved developed reserves as determined by independent engineers.  Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded.  Any difference between the actual costs incurred upon settlement of the asset retirement obligations and the recorded liability is recognized as a gain or loss in the Company’s statement of operations in the period in which the settlement occurs.

Income Taxes

The calculation of the Company’s income tax provision and future income tax liability is complex and requires making certain judgements and constant review of laws and regulations in multiple jurisdictions.  Changes in facts and circumstances as a result of income tax audits, reassessments and changes in existing legislation could result in a corresponding increase or decrease in the Company’s provision for income taxes.

Risk assessment

There are a number of risks facing participants in the oil and gas industry.  Some of the risks are common to all business, while others are specific to a sector.  The following reviews the general and specific risks to which the Company is exposed.  The Company’s management realizes that these risks cannot be eliminated, however they are committed to monitoring and mitigating these risks.

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Risk Management

In order to manage the Company’s exposure to commodity price, interest rate and foreign exchange risk, the Company developed a risk management policy.  Under this policy, it may enter into agreements, including fixed price, forward price, physical purchases and sales, futures, currency swaps, financial swaps, option collars and put options.  The Company’s Board of Directors evaluates and approves the need to enter into such arrangements.  At this time, the Company has chosen not to enter into such risk management arrangements.

Term Deposits

At December 31, 2007, the Company had $14.6 million of term deposits posted as security against its remaining Offshore Nova Scotia work expenditure bids.  To the extent that expenditures are not incurred within the periods allowed, the Company would forfeit its proportionate share of any remaining deposits relating to the unexpended work commitment.  The Company is planning to drill offshore Nova Scotia in the future and it is expected that the majority of these funds will be returned to the Company.

Environmental and Safety

The oil and natural gas industry is subject to environmental regulations pursuant to municipal, provincial and federal legislation in Canada and similar legislation in other countries.  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 the applicable regulatory authorities.  A breach of such legislation may result in the imposition of fines or penalties, some of which could be material.  The Company is committed to meeting and exceeding environmental and safety standards.

Canadian Superior’s Board of Directors and management team monitor, develop and implement policies and procedures to mitigate the environmental and safety risks of the Company.

Reserve Replacement

The continued long-term success of Canadian Superior is dependent on its ability to find, acquire, develop and produce oil and natural gas reserves.  The Company will need to continually add new reserves to offset the natural decline and production from existing reserves.  The Company’s ability to increase reserves is dependent on its ability to explore and develop its existing properties as well as its ability to select and acquire new properties or projects.  There is no assurance that the Company will continue to be able to explore, develop or acquire the reserves necessary to offset the natural decline and production from its existing reserves.

To mitigate this risk, Canadian Superior has assembled a team of experienced technical professionals who have expertise operating and exploring in the core areas of the Company.  In addition, the Company targets prospects that have multi-zone potential and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.

Reserve Estimates

There is significant uncertainty inherent in the estimating of economically recoverable oil and gas reserves (including natural gas liquids) and the future net cash flows to be derived from these reserves.  The Company’s reserves are estimated by an independent engineering firm.  Estimates are made based on a number of variable factors and assumptions, including future oil and gas prices, projected production rates, timing and amount of capital expenditures, future operating expenses and royalties and impact of regulation by government agencies.  The Company’s actual production and future cash flows may vary from its estimates, and such variations could be material.

Operational

Oil and 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 release and oil spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury.  In accordance with industry practice, Canadian Superior is not fully insured against all of these risks, nor are all such risks insurable.  Canadian Superior maintains liability insurance in an amount that it considers consistent with industry practice.  However, due to the nature of these risks it is possible that liabilities could exceed policy limits, which could cause the Company to incur significant

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costs that could have a materially adverse effect on its financial condition.  Oil and natural gas operations are also subject to additional risks, including premature decline of reservoirs and the invasion of water into producing formations.

Canadian Superior’s future oil and gas exploration and development activities are dependent on the Company’s ability to engage drilling and related equipment in the particular areas where the activities will be conducted.  Demand for limited equipment or access restrictions may affect the Company’s ability to complete future exploration and development activities.  The Company is exposed to additional risks associated with oil and gas properties where Canadian Superior is not the operator, and is dependent on the timing and success of such operators as the Company will largely be unable to direct or control the activities.  The Company attempts to mitigate these risks by developing strong relationships with existing and potential partners, suppliers and contractors.

Commodity Prices and Marketing

Canadian Superior is exposed to fluctuations in prices for natural gas, crude oil and natural gas liquids, as all of the Company’s production is currently sold at spot prices that are subject to volatile trading activity.  Commodity prices fluctuate in response to, among other things, domestic and foreign supply and demand, import and export balances, government regulations, weather, and fluctuations in the availability and price of other replacement energy sources.  A significant drop in commodity prices could materially impact the Company’s petroleum and natural gas sales, the volume of production it could produce economically, require downward adjustments to proved reserves and could materially impact the Company’s financial condition.  In addition, a substantial decrease in commodity prices could impact the Company’s borrowing base under the credit facility, therefore reducing the credit facility available, and in some instances, require a portion of the credit facility to be repaid.

Canadian Superior’s ability to market its natural gas may depend on its ability to acquire space on pipelines that deliver natural gas to commercial markets.  The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and facilities as well as extensive government and 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.

Liquidity and Capital Resources

Canadian Superior will continue to require significant capital expenditures for the exploration, development, acquisition and production of oil and gas reserves in the future.  The Company’s capital program is currently funded by cash flow from operations, equity financing and credit facility utilization.  From time to time, the Company will consider raising additional debt or equity, on favourable terms, to finance its exploration, development, acquisition and production of oil and gas reserves.  Cash flow from operations, equity financing and credit facility utilization may not be sufficient to fund the necessary capital requirements to undertake or complete future drilling programs, and if so, there can be no assurance that additional debt or equity financing will be available to meet the requirements on acceptable terms.  Neither its articles nor by-laws limit the amount of indebtedness that the Company may incur.  The level of indebtedness of the Company, from time to time, could impair its ability to obtain additional financing in the future and to take advantage of future business opportunities.

Technology

The Company relies on information technology to manage its day-to-day operations and perform reporting obligations, including the preparation of financial statements, reporting to joint venture partners and various governments in relation to payment of royalties and taxes.

Regulatory

Oil and gas operations are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time.  Canadian Superior’s operations may require licenses and permits from various governmental authorities.  There can be no assurance that Canadian Superior will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development of its projects.

Title to Properties

Although title reviews may be conducted prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain

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of title will not arise to defeat a claim of Canadian Superior, which could result in a reduction of the revenue received by the Company.

Conflicts of Interest

Certain of the directors and officers of Canadian Superior are also directors and officers of other oil and gas companies involved in oil and gas exploration and development, and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions.

Reliance on Key Personnel

Canadian Superior is largely dependent on the performance of its management and key employees.  The Company does not carry any key person insurance in effect for management or key employees, and therefore, there is a risk that the loss of services of such key personnel could have a material adverse effect on the Company.  In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company can continue to attract and retain all personnel necessary to ensure the continued exploration, development and operation of its business.  Investors must rely on the ability, expertise, judgement, discretion, integrity and good faith of management.

Additional information

Additional information relating to Canadian Superior is filed on SEDAR and can be viewed at www.sedar.com.  Information can also be obtained by contacting the Company at Canadian Superior Energy Inc., Suite 2700, 605 – Fifth Avenue S.W., Calgary, Alberta, Canada T2P 3H5 and on the Company’s website at www.cansup.com.

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EX-99.4

Exhibit 99.4

CODE OF BUSINESS CONDUCT AND ETHICS

Formally Approved March 30, 2005

CANADIAN SUPERIOR ENERGY INC.

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TABLE OF CONTENTS

	Page
CODE OF BUSINESS CONDUCT AND ETHICS	3
SUMMARY OF THE CODE	3
EXPLANATION OF THE CODE	4
1. BUSINESS ETHICS AND PRACTICES
Protecting Canadian Superior Assets and Resources	4
Policy Regarding E-Mail, the Internet, Telephones and Other Forms of Communication	4
Media, Public and Governmental Inquiries	5
Conflicts of Interest	5
Membership on Boards of Other Organizations	5
Personal Opportunities	6
Confidential Information	6
Accuracy of Books and Records	7
Accounting, Auditing or Disclosure Concerns	7
2. WORK ENVIRONMENT
Discrimination and Harassment Free Environment	8
Safe Working Conditions	8
3. LEGAL AND REGULATORY COMPLIANCE
Compliance with Laws, Rules and Regulations	9
Securities Laws and Insider Trading	9
Fair Dealing	10
Gifts to Persons	10
Gifts from Persons	10
COMPLIANCE WITH THE CODE	10
Reports And Complaints	11
Treatment of Reports and Complaints	11
Penalties for Violating The Code	11
Disciplinary Action for Code Violations	12
Waivers	12
LEGAL NOTICE	12

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CODE OF BUSINESS CONDUCT AND ETHICS

To all Directors, Officers and Employees of Canadian Superior Energy Inc.

This Code of Business Conduct and Ethics (the “Code”) applies to the directors, officers and employees of Canadian Superior Energy Inc. (“Canadian Superior” or the “Corporation”).

It has always been the policy at Canadian Superior that all our activities should be conducted with the highest standards of honesty and integrity and in compliance with all legal and regulatory requirements. In varying degrees, as a director, officer or employee of Canadian Superior, each of us represents the Corporation in our dealings with others, whether they be other employees, customers, suppliers, competitors, governments or the general public.

At Canadian Superior, we are all expected, as directors, officers and employees, to conduct our dealings on behalf of the Corporation in accordance with this policy. So that there can be no doubt as to what is expected of each of us in this regard, the Board of Directors of Canadian Superior (the “Board”) has endorsed this Code, which is to be followed by each Canadian Superior director, officer and employee.

SUMMARY OF THE CODE

As a director, officer or employee, when acting on behalf of Canadian Superior you are expected to:

1.Protect the Corporation’s assets, and use them properly and with care for the benefit of Canadian Superior, and not for personal use.

2.Use email, the internet, telephone and other forms of communication provided by Canadian Superior appropriately, which means primarily for business-related purposes.

3.Not speak on behalf of Canadian Superior unless authorized to do so.

4.Avoid situations in which your personal interests conflict or might conflict with the interests of Canadian Superior.

5.Obtain permission before joining the board of directors of another company or related organization.

6.Not take personal opportunities discovered by using property of Canadian Superior or in your role with Canadian Superior.

7.Protect the confidentiality of Canadian Superior’s “non-public information”.

8.Ensure that Canadian Superior’s books and records are complete and accurate.

9.Provide accurate and fair public disclosure.

10.Investigate and report any accounting, auditing or disclosure concerns.

11.Be committed to the prevention of workplace discrimination and harassment.

12.Be committed to ensuring the health and safety of fellow employees, officers and directors.

13.Know and comply with all laws, rules and regulations applicable to your position.

14.Not trade in Canadian Superior securities or any other company’s securities if you possess material “non-public information”.

15.Deal fairly with Canadian Superior’s customers, suppliers and competitors.

16.Not offer expensive gifts or other benefits to persons, including public officials and political parties, that might influence or be perceived as influencing a business decision.

17.Not accept expensive gifts or other benefits from persons doing or seeking to do business with Canadian Superior.

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EXPLANATION OF THE CODE

The Code prescribes the minimum moral and ethical standards of conduct required of all directors, officers and employees of Canadian Superior. Violations of the Code can have severe consequences and will result in the appropriate discipline being taken, up to and including discharge where warranted by the circumstances.

An explanation of each of the rules is set forth below. If you are an employee or an officer who has questions regarding the application of any rule or about the best course of action in a particular situation, you should seek guidance from your supervisor.

1.BUSINESS ETHICS AND PRACTICES

PROTECTING CANADIAN SUPERIOR ASSETS AND RESOURCES

Canadian Superior assets are to be used only for the purposes of fulfilling your corporate responsibilities.

The Corporation’s assets are meant for business use, not for personal use. We all have a responsibility to protect and safeguard Canadian Superior’s assets from loss, theft, misuse and waste.

The Corporation’s property should never be used for personal gain, and you should not allow Canadian Superior’s property to be used for illegal activities. If you become aware of theft, misuse or waste of our assets or funds or have any questions about your proper use of them, you should speak with your supervisor. However, if you feel uncomfortable approaching your supervisor with your concern, you may contact Canadian Superior’s President and CEO.

Misappropriation of Canadian Superior’s assets is a breach of your duty to the Corporation and may be an act of fraud against the Corporation. Taking the Corporation’s property from Canadian Superior facilities without permission is regarded as theft and could result in dismissal. In addition, carelessness or waste of Canadian Superior’s assets may also be a breach of your duty to the Corporation and could result in dismissal.

The Corporation’s assets include all memos, notes, lists, records and other documents (and copies of each of these) that you make or compile relating to Canadian Superior’s business. All of these are to be delivered to the Corporation promptly after your employment ceases, or at any time that Canadian Superior requests.

POLICY REGARDING E-MAIL, THE INTERNET, TELEPHONES AND OTHER FORMS OF COMMUNICATION

Use Canadian Superior’s various forms of communication properly and appropriately.

We provide our employees with access to e-mail, the internet, telephones and other forms of communication for business purposes, and while we understand the need for limited and occasional use of these tools for personal purposes, this use should not be excessive or cause detriment to Canadian Superior. Internet use must be conducted in a professional manner. For example, accessing internet sites containing obscene or offensive material, or sending e-mails that are derogatory or harassing to another person or group of people or chain e-mails, is prohibited. In addition, employees must be vigilant to ensure that the network security is maintained.

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MEDIA, PUBLIC AND GOVERNMENTAL INQUIRIES

Do not speak on behalf of Canadian Superior unless you are authorized to do so.

As outlined in Canadian Superior’s Corporate Disclosure Policy, we have professionals who are trained and qualified as spokespersons to release information to the public. When members of the media, financial analysts or government authorities contact the Corporation to request information, the response can have far-reaching implications, including effects on Canadian Superior’s stock price and ability to compete. When we provide information on the Corporation’s operational strategies or financial results, we must ensure both that the information is accurate and that it is an appropriate time to “go public” with that information.

In addition, we must comply with the requirements of securities regulators and stock exchanges about how and when we disclose information, and understand that there are strict consequences for doing so improperly.

If you receive a request for information from outside the Corporation, you must forward it to the Investor Relations department if you are not authorized to speak on behalf of Canadian Superior.

CONFLICTS OF INTEREST

Avoid situations in which your personal interests conflict, might conflict or might appear to conflict with the interests of Canadian Superior.

As an employee, officer or a director, we expect that you will act honestly and ethically and in the best interests of Canadian Superior by avoiding conflicts of interest in your personal and professional relationships. While we respect your right to manage your personal affairs and investments and we do not wish to intrude on your personal life, Canadian Superior employees should place the Corporation’s interest in any business transaction ahead of any personal interest or gain.

As an employee, officer or director, you may have a conflict of interest if you are involved in any activity that prevents you from performing your duties to Canadian Superior properly, or that may create a situation that would affect your judgment or ability to act in the best interests of Canadian Superior. For example, no employee should have a significant interest in a business that supplies goods or services to, or secures goods or services from, Canadian Superior, without receiving approval of his or her supervisor. Directors should look to the Corporate Governance Guidelines for guidance on potential conflict of interest situations.

To avoid conflicts of interest, you should identify potential conflicts when they arise and notify your supervisor if you are unsure whether a relationship or transaction poses a conflict or appears to pose a conflict. Your supervisor will be able to clear or resolve certain conflicts, or will be able to contact someone else who can. Directors should consult with the Chairman of the Board.

MEMBERSHIP ON BOARDS OF OTHER ORGANIZATIONS

If you are an officer or employee of Canadian Superior, obtain permission before you join the board of directors of another company or government organization.

Serving as a director of another company, even one in which Canadian Superior has an interest, may create a conflict of interest. Being a director or serving on a standing committee of some organizations, including government agencies, may also create a conflict.

Before accepting an appointment to the board or a committee of any organization whose interests may conflict with Canadian Superior’s interests, employees must receive written approval from Canadian Superior’s Chairman.

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Employees are permitted, however, to serve on boards of charities or non-profit organizations or in private family businesses that have no relation to Canadian Superior and its businesses. Prior approval is not required for these types of situations. If you hold a position with a charity or non-profit organization and if you speak publicly for the entity, you should ensure that you are seen as speaking on behalf of the entity or as an individual, and not on behalf of Canadian Superior.

PERSONAL OPPORTUNITIES

Do not take personal opportunities that are discovered through the use of property or information of Canadian Superior or in your role with Canadian Superior.

As an employee, officer or director, you are prohibited from taking for yourself opportunities that you discover through the use of Canadian Superior property, information or position; from using Canadian Superior property, information or position for personal gain; and from competing with the Corporation. Employees, officers and directors owe a duty to Canadian Superior to advance its legitimate interests when the opportunity arises.

CONFIDENTIAL INFORMATION

Protect the confidentiality of “non-public information” concerning Canadian Superior.

“Non-public information” is information that is not generally available to the investing public through a press release, disclosure to shareholders or widely reported media coverage. The circulation of rumors, or “talk on the street”, even if accurate, is not considered public disclosure. The most common example of “material non-public information” is information about earnings or financial performance that has not yet been publicly disclosed.

Except where it is authorized or legally required, all directors, officers and employees must keep confidential, and not use for themselves or other persons including relatives or friends, all information concerning Canadian Superior or its business that is not generally available to the investing public.

Information is considered to be public if it has been disclosed in an annual report, annual information form, management information circular, press release or interim report. The obligation to keep certain information confidential applies both during appointment or employment with Canadian Superior, and after termination of appointment, or employment, including on retirement.

Protect the confidentiality of “non-public information” about customers and others.

We also respect confidentiality of information regarding other companies. If you learn of confidential information about another company in the course of your position, you should protect it the same way that you would protect confidential information about Canadian Superior. Data protection and privacy laws that affect the collection, use and transfer of personal customer information are rapidly changing areas of law, and you should consult with your supervisor if you have any questions regarding appropriate uses of customer information.

Disclosure of confidential information can be harmful to Canadian Superior and could be the basis for legal action against the Corporation and/or the employee, officer or director responsible for the disclosure.

For more information you should refer to Canadian Superior’s Corporate Disclosure Policy.

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ACCURACY OF BOOKS AND RECORDS

Ensure that the books and records of Canadian Superior are complete and accurate.

The books and records of Canadian Superior must reflect in reasonable detail all its transactions in a timely and accurate manner in order to, among other things, permit the preparation of accurate financial statements in accordance with generally accepted accounting principles. All assets and liabilities of Canadian Superior must be recorded as necessary to maintain accountability for them.

All business transactions must be properly authorized. All transactions must be supported by accurate documentation in reasonable detail and recorded properly. The recorded value for assets must be compared to the existing assets at reasonable intervals and appropriate action taken with respect to any differences.

No information may be concealed from the auditors, the internal audit function, the Audit Committee or the Board.

In addition, it is unlawful to fraudulently influence, coerce, manipulate or mislead any independent public or certified accountant who is auditing our financial statements.

ACCOUNTING, AUDITING OR DISCLOSURE CONCERNS

Provide accurate and fair public disclosure.

We are required to provide full, fair, accurate, timely and understandable disclosure in reports and documents that we file with, or submit to, the Securities and Exchange Commission (SEC), the Ontario Securities Commission (OSC) and other Canadian securities regulators, the Toronto Stock Exchange (TSX) and the American Stock Exchange (AMEX), as well as in other public communications made by Canadian Superior. All employees who are responsible for the preparation of Canadian Superior public disclosures, or who provide information as part of the process, have a responsibility to ensure that disclosures and information are made honestly, accurately and in compliance with Canadian Superior’s disclosure controls and procedures.

We all have a responsibility to submit good faith questions and concerns regarding accounting, auditing or disclosure matters. Complaints and concerns related to such matters include, among others, actions involving:

(a)	fraud or deliberate errors in the preparation, maintenance, evaluation, review or audit of any financial
	statement or financial record;
(b)	deficiencies in, or noncompliance with, internal accounting controls;
(c)	misrepresentation or false statements to or by a senior officer or accountant regarding a matter
	contained in the financial records, financial reports or audit reports; or
(d)	deviations from full and fair reporting of Canadian Superior’s financial condition.

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2.WORK ENVIRONMENT

DISCRIMINATION AND HARASSMENT FREE ENVIRONMENT

Canadian Superior has zero tolerance for workplace discrimination and harassment, and all directors, officers and employees must be committed to preventing an inhospitable work environment.

All directors, officers and employees must ensure that Canadian Superior is a safe and respectful environment, free of discrimination and harassment where high value is placed on equity, fairness and dignity. Harassment on the basis of race, gender, sexual orientation, colour, national or ethnic origin, religion, marital status, family status, citizenship status, veteran status, age or disability is prohibited. Harassment generally means offensive verbal or physical conduct that singles out a person to the detriment or objection of that person. Harassment covers a wide range of conduct, from direct requests of a sexual nature to insults, offensive jokes or slurs, which results in an inhospitable work environment. Harassment may occur in a variety of ways and may, in some circumstances, be unintentional. Regardless of intent, such conduct is not acceptable and may also constitute a violation of human rights legislation.

No officer or employee may harass another employee, customer, vendor, supplier, visitor or any other person on Canadian Superior’s premises or while doing its business regardless of location.

SAFE WORKING CONDITIONS

We are committed to ensuring the health and safety of our employees.

We all have the right to work in an environment that is safe and healthy. In this regard, we must:

(a)	comply strictly with the letter and spirit of applicable occupational, health and safety laws and the public policies they represent;
(b)	follow work instructions or procedures on health and safety laws;
(c)	not engage in illegal or dangerous behaviors; and
(d)	not possess or use weapons or firearms or any type of combustible materials in Canadian Superior’s facilities or at Canadian
Superior-sponsored functions unless you are authorized by Canadian Superior or the law to do so.

Canadian Superior has zero tolerance for acts of violence, threats of violence, acts of intimidation and hostility towards another person or group of persons. Promptly report to your supervisor or in accordance with the Reports and Complaints section of this Code, any accident, injury or unsafe equipment, practices or conditions, violent behavior or weapons possession.

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3.LEGAL AND REGULATORY COMPLIANCE

COMPLIANCE WITH LAWS, RULES AND REGULATIONS

Know and comply with all laws, rules and regulations applicable to your position.

Many of Canadian Superior’s activities are subject to complex and changing laws, rules and regulations. Ignorance of the law is not, in general, a defense to an action for contravention. We expect directors, officers and employees to make every reasonable effort to become familiar with laws, rules and regulations affecting their activities and to exert due diligence in complying with these laws, rules and regulations and, to ensure that those individuals reporting to them are also aware of these laws, rules and regulations. Our objective is to restrict willful or negligent violations of these laws, rules and regulations.

We will make information concerning applicable laws, rules and regulations available to directors, officers and employees. If you have any doubts as to the applicability of any law, you should refer the matter to your supervisor who may obtain advice from Canadian Superior’s Counsel. Directors should seek guidance in accordance with the Corporate Governance Guidelines.

Canadian Superior’s policy is to meet or exceed all applicable governmental requirements regarding its activities. As an employee, you must be aware of the applicable governmental requirements and report any violations thereof to your supervisors or in accordance with the Reports and Complaints section of this Code. Similarly, no employee, officer or director may enter into any arrangement contrary to applicable requirements or laws.

SECURITIES LAWS AND INSIDER TRADING

Do not trade in Canadian Superior securities if you possess material “non-public information”. If you have material information about a company with which Canadian Superior does business that is not known to the investing public, you should not buy or sell securities of that company until after the information has become public.

Information about Canadian Superior is “material”:

(a)if publicly known, results in or would reasonably be expected to result in a significant change in the market price or value of any Canadian Superior securities; or

(b)if there is a substantial likelihood that a reasonable shareholder or investor would consider it important in making a decision to buy, sell or hold Canadian Superior securities.

If you are not sure whether information is material or “non-public”, consult with Canadian Superior’s President and CEO for guidance before engaging in any transaction in Canadian Superior securities.

You are also prohibited from disclosing material “non-public information” about Canadian Superior to other people, such as relatives or friends, who may trade on the basis of the information. Securities laws also prohibit trades made on the basis of these “tips”. In addition, you should avoid trading in puts and calls relating to Canadian Superior securities.

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FAIR DEALING

Deal fairly with Canadian Superior’s customers, suppliers and competition.

You must endeavor to deal fairly with securityholders, Canadian Superior’s customers, suppliers, competitors and employees, and should not take unfair advantage of anyone through manipulation, concealment, abuse of privileged information, misrepresentation of material facts, or any other unfair-dealing practice.

GIFTS TO PERSONS

Use your best judgment in giving and receiving gifts.

Directors, officers and employees should not offer expensive gifts or other benefits to persons, including public officials and political parties, that might influence or be perceived as influencing a business decision.

Employees whose duties permit them to do so, such as employees in marketing, may offer modest gifts, entertainment or other benefits to persons who have a business relationship with the Corporation. The benefits must be given in accordance with generally accepted ethical business practices. For example, it is acceptable to take a customer to dinner but it is not acceptable to give a customer cash.

Any donation or benefit to a public official or political party must be in accordance with Canadian Superior’s Code. We encourage you to become involved in political activity acting on your own behalf, but not as a representative of Canadian Superior.

GIFTS FROM PERSONS

Directors, officers and employees must not accept expensive gifts or other benefits from persons doing or seeking to do business with Canadian Superior.

As a director, officer or employee, you cannot solicit, encourage or receive bribes or other payments, contributions, gifts or favors that could influence your or another person’s decisions. It is acceptable to accept modest gifts, entertainment or other benefits from persons doing or seeking to do business with Canadian Superior, provided the benefits are given in accordance with generally accepted ethical business practices.

For example, a pair of tickets to a baseball game may be accepted from a supplier. However, it is not appropriate to accept a trip from a supplier, unless there is a specific business purpose and the trip has been approved by the head of the employee’s department.

COMPLIANCE WITH THE CODE

Each director, officer and employee of Canadian Superior will be provided with a copy of the Code.

The Code is intended to serve as a guide for your own actions and decisions and for those of your co-workers.

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REPORTS AND COMPLAINTS

As an employee, if you believe that a violation of the Code or any law, rule or regulation has been or is likely to be committed by you or someone else who is a representative of Canadian Superior, you have an obligation to promptly report the relevant information to your supervisor, since your supervisor will generally be in the best position to resolve the issue. However, if you feel uncomfortable approaching your supervisor with your concern, or if you have any specific or general questions, you may contact Canadian Superior’s President and CEO.

If you believe it is inappropriate to raise your complaint or report of a violation with either your supervisor or the President and CEO, you can write to the Chairperson of the Audit Committee (for issues related to accounting controls, auditing or disclosure) or the Chairperson of the Board (for all other types of issues such as harassment or discrimination, misuse of the internet, conflicts of interest or inappropriate gift giving or receiving).

Directors should promptly report violations to the Chairperson of the Board, or to the relevant committee Chairperson.

Directors, officers and employees can raise concerns either orally or in writing although reports to the Chairpersons of the Board or of the committees can only be made in writing.

The most important thing to remember when dealing with these types of questions or concerns is: When in doubt, ask.

TREATMENT OF REPORTS AND COMPLAINTS

Confidentiality of reported violations will be maintained to the fullest extent possible, consistent with the need to conduct an adequate review and subject to law. You may make a report anonymously, in which case you should write a letter and include as specific details as possible, including back-up documentation where feasible, in order to permit adequate investigation of the concern or conduct reported. Vague, non-specific or unsupported allegations are inherently more difficult to pursue.

The party receiving the complaint must make a record of its receipt, document how the situation was dealt with and file a report with Canadian Superior’s President and CEO. The President and CEO will retain all such reports, but will also maintain a separate log that will track the receipt, investigation and resolution of reported complaints specifically related to accounting controls, auditing and disclosure matters. Based on this log, the President and CEO will periodically compile a comprehensive summary of all of these types of complaints and the corrective actions taken and will bring the summary to the attention of the Chairperson of the Audit Committee for his or her review, since the Chairperson of the Audit Committee is ultimately responsible for Canadian Superior’s compliance with the accounting, auditing and disclosure-related aspects of the Code.  The President and CEO will bring any other complaints or reported violations that are not related to accounting controls, auditing or disclosure but are significant to the attention of the Chairperson of the Governance and Nominating Committee.

PENALTIES FOR VIOLATING THE CODE

Retaliation is prohibited. We want you to know that we will not discharge, demote or suspend you if you, in good faith, bring forward concerns about actual or potential violations of laws, rules or regulations, or the Code. However, we reserve the right to discipline you if you make an accusation without a reasonable, good faith belief in the truth and accuracy of the information or if you knowingly provide or make false information or accusations. “Good faith” does not mean that you have to be right - but it does mean that you must believe you are providing truthful information.

If you believe that you have been unfairly or unlawfully retaliated against, you may file a complaint with your supervisor or Canadian Superior’s President and CEO.

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DISCIPLINARY ACTION FOR CODE VIOLATIONS

We will impose discipline for each Code violation that fits the nature and particular facts of the violation. If you fail to comply with laws or regulations governing Canadian Superior’s businesses, this Code or any other Canadian Superior policy or requirement, you may be disciplined up to and including immediate termination, and if warranted, legal proceedings may be brought against you.

WAIVERS

Waivers of the Code for employees may be granted only in writing by Canadian Superior’s President and CEO. Any waiver of the Code for Canadian Superior executive officers or directors may only be made in writing by the Board or the Governance and Nominating Committee and will be promptly disclosed to shareholders to the extent required by law, regulation or stock exchange requirement.

LEGAL NOTICE

This Code serves as a reference to you. Canadian Superior reserves the right to modify, suspend or revoke this Code and any and all policies, procedures, and programs in whole or in part, at any time. Canadian Superior also reserves the right to interpret and amend this Code and these policies in its sole discretion as it deems appropriate. Any amendments to the Code will be disclosed and reported as required by law.

Neither this Code, these policies nor any statements made by any employee of Canadian Superior, whether oral or written, confer any rights, privileges or benefits on any employee, create an entitlement to continued employment at Canadian Superior, establish conditions of employment, or create an express or implied employment contract of any kind between employees and Canadian Superior. In addition, all employees should understand that this Code does not modify their employment relationship, whether at will or governed by a written contract.

The version of the Code that appears online at www.cansup.com may be more current and up to date and supersedes any paper copies, should there be any discrepancy between paper copies and what is posted online.

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EX-99.5

Exhibit 99.5

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Canadian Superior Energy Inc.:

We have audited Canadian Superior Energy Inc.’s (the “Company”)internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit includes performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.  The following material weaknesses have been identified and are included in management’s assessment:

·      There are no effective controls or procedures related to all significant accounts and processes to provide reasonable assurance that transactions are recorded accurately, are recorded timely and are complete.

·      The Company was not adequately staffed with accounting personnel possessing an adequate level of technical expertise and did not maintain effective segregation of duties over automated and manual transactions leading to ineffective monitoring, supervision and reviews.

·      The Company did not maintain effective controls over the safeguarding of monetary assets.  This material weakness affects cash and short-term investments.

In our opinion, because of the effect of the material weaknesses described above on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as at December 31, 2007 and 2006 and the statements of operations, comprehensive loss and deficit and cash flows for each of the years in the three year period ended December 31, 2007, of the Company and our report dated March 27, 2008 expressed an unqualified opinion. The aforementioned material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2007 consolidated financial statements, and this report does not affect our opinion on those consolidated financial statements.

Yours truly,

MEYERS NORRIS PENNY LLP

Calgary, Canada

March 27, 2008

EX-99.6

Exhibit 99.6

Consent of Meyers Norris Penny LLP, Chartered Accountants

To the Board of Directors

CANADIAN SUPERIOR ENERGY INC.

We hereby consent to the use in the Annual Report on Form 40-F of:

– our Auditors’ Report dated March 27, 2008 with respect to the consolidated balance sheets of Canadian Superior Energy Inc. (the “Company”) as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive loss and deficit and cash flows for each of the years in the three year period ended December 31, 2007; and

– our Report of Independent Registered Public Accounting Firm dated March 27, 2008 on the effectiveness of internal control over financial reporting as at December 31, 2007;

each of which is contained in this annual report on Form 40-F of the Company for the fiscal year ended December 31, 2007.

/s/ Meyers Norris Penny LLP

Chartered Accountants

Calgary, Canada

March 27, 2008

EX-99.7

Exhibit 99.7

CONSENT OF INDEPENDENT PETROLEUM ENGINEERING CONSULTANTS

We refer to our report entitled “Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor” dated March 14, 2008 evaluating the reserves attributable to Canadian Superior Energy Inc. (the “Company”) as of December 31, 2007 (the “Report”).

We hereby consent to references to our name and to the Report in the Company’s Annual Report on Form 40-F to be filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended. We also confirm that we have read the Annual Information Form included in the Annual Report on Form 40-F and that we have no reason to believe that there are any misrepresentations in the information contained in it that are derived from the Report or that are within our knowledge as a result of the services we performed in connection with the Report. We also consent to the incorporation by reference in the Registration Statement on Form F-3 (No. 333-137035) of the Report.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

/s/ John H. Stilling, P. Eng.

John H. Stilling, P. Eng.

Vice–President

Calgary, Alberta

March 30, 2007

EX-99.8

Exhibit 99.8

CERTIFICATIONS PURSUANT TO

RULE 13a-14(a)

I, Craig McKenzie, certify that:

1.I have reviewed this Annual Report on Form 40-F of Canadian Superior Energy Inc.;

2.Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report;

3.Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this Annual Report;

4.The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated:  March 30, 2008

By:	/s/ CRAIG MCKENZIE
	Name:	Craig McKenzie
	Title:	Chief Executive Officer

EX-99.9

Exhibit 99.9

CERTIFICATIONS PURSUANT TO

RULE 13a-14(a)

I, Robb D. Thompson, certify that:

1.I have reviewed this Annual Report on Form 40-F of Canadian Superior Energy Inc.;

2.Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report;

3.Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this Annual Report;

4.The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5.The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Dated:  March 30, 2008

By:	/s/ ROBB D. THOMPSON
	Name:	Robb D. Thompson
	Title:	Chief Financial Officer

EX-99.10

Exhibit 99.10

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Canadian Superior Energy Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Craig McKenzie, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March 30, 2008

By:	/s/ CRAIG MCKENZIE
	Name:	Craig McKenzie
	Title:	Chief Executive Officer

EX-99.11

Exhibit 99.11

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Canadian Superior Energy Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robb D. Thompson, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.             The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.             The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:  March 30, 2008

By:	/s/ ROBB THOMPSON
	Name:	Robb D. Thompson
	Title:	Chief Financial Officer