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

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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

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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

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	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

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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

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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

21

	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	)

22

	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).

23

	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

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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;

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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.

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