ex1-1.htm

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.

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, 2008, 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.

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

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

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.

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 1-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 Common Shares are listed and posted for trading on the Toronto Stock Exchange and the NYSE Euronext (successor to the American Stock Exchange) under the symbol "SNG".

The Corporation's head office is located at 3200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6 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, an office in New Jersey at 15 Exchange Place, Suite 1120, Jersey City, NJ,a field office at P.O. Box 2259 Drumheller, Alberta, T0J 0Y0, a field office in the West Indies located at 5 Herbert Street, St. Clair, Port of Spain, Trinidad & Tobago, West Indies, and a field office in Tunisia at 6 Rue Virgile,Gammarth, Tunis, Tunisia.

The Corporation is the owner of 100% of all of the issued and outstanding shares of Seeker Petroleum Ltd., a corporation incorporated under the laws of Canada and continued in Alberta on August 25, 2008.

The Corporation has a total of 48 full-time staff, including 3 staff members in its Halifax, Nova Scotia office, 4 staff members in its New Jersey office, 9 staff members in its Drumheller, Alberta field office and 8 staff members in its Trinidad and Tobago field office.

GENERAL DEVELOPMENT OF THE BUSINESS

Canadian Superior is engaged in the exploration for, and acquisition, development and production of petroleum and natural gas, and LNG projects, with operations in Western Canada, offshore Nova Scotia, offshore Trinidad and Tobago, the United States and North Africa.

The most significant general conditions that have affected the Corporation's business in the past three completed financial years have been the volatility of commodities markets, and more recently the global economic recession and the attendant drop in investment capital and in equity market capitalization. Like all companies engaged in the business of exploring for and producing crude oil and natural gas, the significant drop in the market price for oil and natural gas in the past twelve months has affected revenue from the sale of these commodities and also the economics of proposed exploration projects. The share values of virtually all crude oil and natural gas exploration and production companies have fallen as a result of these factors.

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

On April 29, 2009 Mr. Leif Snethun was named as the Corporation's COO, acting in the capacity of principal executive officer.

On April 24, 2009 Messrs. Gregory Noval, the Executive Chairman of the Board, and Michael Coolen, the President and CEO, departed as officers and employees of the Corporation. Mr. Jake Harp was named as Interim Chairman of the Board. In addition, Messrs Noval and Coolen no longer serve on the Corporation's various Board committees.

On April 22, 2009 the Corporation attended a hearing with the NYSE Alternext US LLC (the “Exchange” or “NYSE Alternext US”) regarding the March 6th decision by the Exchange's staff to file a delisting application with the S.E.C. Following the hearing the Exchange staff advised the Corporation that it had decided to withdraw its proposed delisting application, and that the Corporation's Common Shares would instead continue to be halted/suspended from trading for an interim period pending the resolution of the Corporation's protection under the Companies' Creditors Arrangement Act (Canada) (“CCAA”).

On April 3, 2009 the committee of independent directors retained Jennings Capital Inc. as its financial advisor pursuant to an engagement letter dated April 2, 2009. Under this agreement Jennings Capital agrees to assist the committee of independent directors in exploring and reviewing alternatives potentially available to the Corporation including, but not limited to, a sale of the Corporation, a recapitalization, an equity injection or a sale of certain assets with a view to the Corporation's successful emergence from the CCAA proceedings.

On April 3, 2009, the Corporation announced that the membership of a committee of independent directors, that was established to assist the board of directors in fulfilling its oversight responsibilities, was amended by the addition to the committee of Messrs. Alexander Squires and Charles Dallas. The committee of independent directors is now comprised of Messrs. T. Jake Harp (Chair), Kaare Idland, Richard Watkins, Alex Squires and Charles Dallas.

On March 26, 2009, the Corporation announced that its application of March 25, 2009, to the Court of Queen's Bench of Alberta for an Order under the CCAA, to extend its CCAA protection was successful; allowing the Corporation to continue to prepare a plan of arrangement for its creditors, and continuing to stay all claims and actions against the Corporation and its assets. The March 25th Order extended CCAA protection until May 4, 2009, at which time the matter is scheduled to be reviewed by the court. The Order permits the Corporation to remain in possession and control of its property, carry on its business, retain employees and other service providers. While the Order is in effect, the Corporation will work with a court-appointed Monitor and it will continue to implement a plan of arrangement for its creditors, which includes, among other things, the initiative to sell an undivided 25% or larger interest in its "Intrepid" Block 5(c) in Trinidad and Tobago.

On March 11, 2009, the Corporation advised that the NYSE Alternext US LLC (the “Exchange” or “NYSE Alternext US”) has halted trading in its common shares on March 5, 2009. The NYSE Alternext US has advised the Corporation, in a letter dated March 6, 2009, that the Exchange intends to file a delisting application with the S.E.C. due to determinations by the Exchange staff that the Corporation had continuing listing deficiencies.

On March 6, 2009, the Corporation announced that its application to the Court of Queen's Bench of Alberta for an Order under the CCAA was successful, allowing the Corporation to prepare a plan of arrangement for its creditors, and staying all claims and actions against the Company and its assets. The Order was made under section 11 of the CCAA and would be in effect until March 25, 2009, at which time the matter would be reviewed by the court. While the Order is in effect the Corporation would work with a court-appointed Monitor and continue to implement a plan of arrangement for its creditors, which included the initiative to sell an undivided 25% or larger interest in its “Intrepid” Block 5(c) in Trinidad and Tobago. The Corporation advised that a successful sale of the Trinidad asset could allow the Corporation to re-structure in an organized manner and reemerge from CCAA in due course.

On March 5, 2009, the Corporation announced that it filed an application with the Court of Queen's Bench of Alberta for an order allowing the Corporation to prepare a plan of arrangement for its creditors, and staying all claims and actions against the Corporation and its assets.

On March 3, 2009, the Corporation announced the successful flow testing of the "Endeavour" well, the third well drilled by the Corporation offshore Trinidad, and the discovery of quantities of natural gas.

On February 23, 2009, the Corporation advised that it had reached an accommodation with Canadian Western Bank (“Bank”) whereby the demand for repayment of all amounts outstanding under the Corporation's credit facility with the Bank was extended to February 27, 2009 (further extended on March 2, 2009 to March 12, 2009). The credit facility had been permanently reduced the previous week from $45 million to $37.5 million with a payment of approximately $9 million made to the Bank by the Corporation from the sale of certain Western Canadian properties.

On February 20, 2009, the Corporation announced that it had entered into an agreement with Scotia Waterous (USA) Inc. (“Scotia Waterous”) under which Scotia Waterous would immediately commence to act as advisor to the Corporation for the sale of a 25% or larger interest in its “Intrepid” Block 5(c) in Trinidad and Tobago. Among the services provided under the advisory agreement, Scotia Waterous would identify and prioritize purchasers for the assets, develop marketing and sales documentation, organize and facilitate access to all technical data, and support and assist sales negotiations and documentation.

On February 17, 2009, the Corporation advised that it had received a demand letter from the Canadian Western Bank (“Bank”) for repayment of all amounts outstanding under Canadian Superior’s $45 million credit facility with the Bank by February 23, 2009. The Corporation advised that it was in discussions with the Bank to extend the time for repayment in order to provide for the orderly and timely repayment of the full credit facility.

On February 12, 2009, the Corporation announced the appointment, upon the application of BG International Limited ("BG"), a wholly owned subsidiary of the BG Group plc, of an interim Receiver of its participating interest in “Intrepid” Block 5(c). Pursuant to the Court Order the Receiver, in conjunction with BG, will operate the property and conduct the flow testing of the “Endeavour” well which Canadian Superior believes will validate its operations to date. The Court Order allowed the Receiver to charge the Corporation's interest in Block 5(c) with an amount up to U.S. $47 million to pay for its share of the costs under the joint operating agreement with BG. The Corporation announced that it would continue with the monetization of its interest in Block 5(c) as previously announced and the proceeds from any sale would be applied to its share of the costs charged against Block 5(c) and to discharge the Receiver.

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

On February 9, 2009 BG initiated arbitration proceedings under the provisions of the Block 5(c) joint operating agreement, alleging various breaches of the joint operating agreement by the Corporation. As of the date of this Annual Information Form BG and the Corporation have each nominated an arbitrator to serve as two of the three members of an arbitration panel.

On February 8, 2009 BG served on the Corporation a default notice under the provisions of the Block 5(c) joint operating agreement, alleging various breaches of the joint operating agreement by the Corporation. The terms of the Block 5(c) joint operating agreement are complex and, in a worst-case scenario, could have resulted in the forfeiture of the Corporation's interest in Block 5(c) to BG. The CCAA Order obtained by the Corporation on March 6, 2009, and continued on March 25th, had the effect of staying these provisions of the Block 5(c) joint operating agreement.

On December 31, 2008, the Corporation entered into a settlement agreement with Sinopec Star Petroleum Co. Ltd. for disputed drilling and related costs incurred in 2008 for the net amounts of USD $3.3 million inclusive of VAT and UK £288,513 exclusive of VAT.

On December 8, 2008, the Corporation closed an underwritten private placement consisting of 10,322,581 Common Shares issued on a "flow-through" basis at a price of $1.55 per share for gross proceeds of $16.0 million.

On December 4, 2008, the Corporation announced the resignation of Mr. Craig McKenzie as CEO and as a Director, and the appointment of Mr. M.E. Coolen as CEO, in addition to his ongoing positions as President, COO and a Director.

On September 23, 2008 the Corporation entered into a $14,000,000 bridge financing agreement with Challenger Energy Corp. ("Challenger"), to allow Challenger to close a $30,000,000 prospectus financing. The principal amount of this loan is currently in default.

On September 3, 2008, the Corporation announced the execution of an Exploration and Production Sharing Agreement with Joint Exploration, Production, and Petroleum Services Company, which is owned jointly by the Tunisian and Libyan governments, for the exploration and development of the offshore "7th of November Block" that straddles the territorial waters of both Tunisia and Libya.

On August 26, 2008, the Corporation announced that it entered into an agreement for a non-brokered private placement of $35 million USD, by the issuance of 8,750,000 $4.00 USD units. Each unit is comprised of one Common Share and one-half of one Common Share purchase warrant, with each whole warrant exercisable for a period of one year at a price of $4.75 USD. This private placement successfully closed on September 4, 2008.

On August 13, 2008, the Corporation announced the successful flow testing of the "Bounty" well, the second well drilled by the Corporation offshore Trinidad, and the discovery of significant quantities of natural gas.

On May 20, 2008, the Corporation announced that it will participate in the a 50/50 joint venture for the proposed development of a USD $550 million LNG regasification project, entitled "Liberty Natural Gas", to be located in US federal waters offshore New Jersey.

On February 5, 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 $51.8 million, including the assumption of approximately $8.5 million of net debt. This transaction was successfully completed on March 26, 2009, with the issuance of approximately 7,651,866 Common Shares at $3.72 and the payment of $14.2 million cash to the shareholders of Seeker Petroleum Ltd.

On January 14, 2008, the Corporation announced the successful flow testing of the first zone of the "Victory" well, the first well drilled by the Corporation offshore Trinidad, and the discovery of significant quantities of natural gas. On January 28, 2008, the Corporation announced the successful flow testing of the second zone of the "Victory" well, and the discovery of significant quantities of natural gas in the second zone as well.

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 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, and on November 15, 2007, Mr. McKenzie, was named to the board of directors 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.

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.

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 its 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.

SIGNIFICANT ACQUISITIONS

On March 26, 2008 the Corporation completed a plan of arrangement (the "Arrangement") with Seeker Petroleum Ltd. ("Seeker"), the result of which was the acquisition by the Corporation of all the issued and outstanding shares of Seeker for $51.2 million, by the issuance of approximately 7,651,866 Common Shares at $3.72 a piece and the payment of $14.2 million cash. Seeker is a wholly-owned subsidiary of the Corporation. A NI 51-102F4 Business Acquisition Report regarding this acquisition was filed with Canadian securities regulators via SEDAR on June 4, 2008.

Seeker was a privately held corporation incorporated under the laws of Canada, engaged in petroleum and natural gas exploration, development and production in Western Canada. Pursuant to the Arrangement the shareholders of Seeker received, for each outstanding common share of Seeker held by them, $0.85 cash or 0.2285 Canadian Superior Common Shares issued from treasury, subject to a maximum cash component of $14.2 million and maximum share component of 7,651,866 Canadian Superior common shares. In addition, Canadian Superior paid approximately $8.5 million to settle the outstanding amount of Seekers revolving credit facility.

With the closing of the Seeker acquisition the Corporation acquired approximately 1,035 BOE/d (72.5% natural gas, 27.5% oil & liquids), approximately 2,073 MBOE of proven plus probable reserves and approximately 1,297 MBOE additional possible reserves, 55,385 net acres of undeveloped land, and 102 sq. km of proprietary 3D seismic.

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

Canadian Superior is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas, and LNG projects with operations in Western Canada, offshore Nova Scotia, Canada, offshore Trinidad and Tobago, the United States and North Africa. 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 Production Sharing Control ("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), which 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). During 2005 and 2006, the Corporation actively pursued various rig options for the “Intrepid” drilling and entered into a firm drilling contract for the Kan Tan IV Semi-Submersible Drilling Rig to drill the first three exploration wells. These were planned to evaluate three large separate potential hydrocarbon bearing structures, “Victory”, “Bounty” and “Endeavour”. These had been delineated by Canadian Superior following evaluation and interpretation of extensive 3D seismic over the “Intrepid” Block 5(c).

Following a scheduled refurbishment in Brownsville, Texas, the Kan Tan IV was moved to the port of Chaguarmas in Trinidad and then to the first drilling location on the "Victory" Prospect . The rig arrived on site June 19, 2007 and commenced operations on June 25, 2007 when the drilling of a pilot hole at the "Victory-1" well site commenced. On August 30, 2007, the "Victory" well site reached Total Depth of 16,621 feet (subsea). While 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 plugged back to a depth of approximately 9,564 feet and 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. The first test was conducted at rates of between 40 and 45 MMscf/d, and the second test was conducted at rates of over 30 MMscf/d. Both tests were conducted on a restricted basis and had high flowing pressures. The well was subsequently suspended with a number of cement plugs for future re-entry.

On February 20, 2008, the Kan Tan IV spudded the "Bounty-1" well after moving approximately 2.2 miles from the "Victory-1" well location. Drilling was temporarily suspended on June 26, 2008 to allow open-hole logging of a zone of interest, after which drilling resumed. On July 9, 2008, the Corporation announced that the "Bounty" well reached Total Depth of 17,360 feet (subsea) and that it had unanimously agreed with its partners to case and conduct flow tests on the "Bounty-1" well.

The "Bounty-1" well successfully tested natural gas in the main targeted formation. The results from the "Bounty" well and interpretations of extensive 3-D seismic data and other data indicate a natural gas resource potential of up to 2.6 TCF of natural gas from the tested structure. During the testing of the "Bounty" well, production testing equipment capacity was maximized resulting in flow testing being restricted to a stabilized rate of 60 mmcf/d of natural gas with a flowing bottomhole pressure of 7186 psi. The well was subsequently suspended with a number of cement plugs for future re-entry.

On August 28, 2008, the Kan Tan IV spudded the "Endeavour-1" well, the third and final well of the initial exploration program, approximately 5.2 miles north from the "Bounty-1" well location. On December 29, 2008 the Corporation announced that, having reached 17,063 feet (subsea), the Corporation and its partners had decided to re-drill the final section of the well with a mechanical sidetrack due to well bore damage that had occurred during well control operations. On January 23, 2009, the Corporation announced that the "Endeavour" well had reached Total Depth of 17,426 feet (subsea) and that it had unanimously agreed with its partners to case and conduct flow tests on the "Endeavour" well.

The "Endeavour-1" well successfully tested natural gas in the main targeted formation. During testing, production testing equipment capacity was maximized resulting in flow testing being restricted to a peak flow rate of 60.1 MMscf/d of natural gas with a flowing wellhead pressure of 4122 psi. The well was subsequently suspended with a number of cement plugs for future re-entry. The Kan Tan IV rig was subsequently released from location and from contract.

To assist Canadian Superior in going forward with the “Intrepid” project in Trinidad, the Corporation had entered into a participation agreement with a non-competitive industry financial partner, Challenger Energy Inc. 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 International Ltd (BGIL), a wholly owned subsidiary of BG Group PLC, had entered into a farm-in agreement and joint operating agreement. BGIL participated 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. BGIL also paid approximately US$39 million, addressing BG's share of previous incurred costs and a substantial entry bonus. The partners are currently in dispute as detailed in the General Developments of the Business section.

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. Utilising the existing 2D seismic date set, the Corporation has identified four initial drilling prospects, two of which have been selected for the first phase exploration drilling. Acquisition of 3D seismic may now be deferred in favour of a more selective programme after the initial drilling results are in hand. The Corporation has made application for the environmental permits required for drilling to proceed and an Environmental Impact Assessment is in progress. During 2009, the Corporation will conduct a shallow hazard survey, including detailed investigation of the proposed well sites. Drilling is expected to commence in the first half of 2010.

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.

North Africa - Tunisia and Libya

On September 3, 2008, Canadian Superior announced its "Oasis" Project, referring to the Corporation's entry into North Africa. Oasis commenced with the formal signing ceremonies for the offshore "7th of November Block" Exploration and Production Sharing Agreement ("EPSA") that was conducted on Wednesday, August 27, 2008, in Tunis, Tunisia. Canadian Superior Energy Inc. and the Tunisian/Libyan company 'Joint Exploration, Production, and Petroleum Services Company' ("Joint Oil") also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil, in Canadian Superior's "Mariner" Block, offshore, Nova Scotia, Canada. This represents the first such agreement for either Tunisia or Libya. Joint Oil is owned equally by the Tunisian government via Entreprise Tunisienne d'Activites Petrolieres ("ETAP") and the Libyan government via Libya Oil Holdings. Under the terms of the EPSA, Canadian Superior has been named Operator for the "7th of November Block" which comprises an area of approximately 1200 square miles (768,000 acres), located some 75 miles offshore the Mediterranean Gulf of Gabes, in water depths ranging from 250-375 feet.

The exploration work commitment for the first phase (4 years) of the 7 year Exploration Period will include three exploration wells, 300 square miles of 3D seismic, and one appraisal well. This appraisal well is intended to be the first well in a fast-track drilling program and will be a direct offset to two significant oil

and gas discoveries drilled in the 1990's on a feature known as "Zarat" in the adjacent contract area. Based on 3D seismic acquired subsequent to the discoveries, a substantial portion of the undeveloped "Zarat discovery area" is interpreted to extend north, into the "7th of November Block.

Tunisia is a stable democratic republic with a well developed economy and an active oil and gas sector. It has close ties with the European Union with which it has an Association Agreement that came in to force in 1998. A number of international oil and gas companies are active in the country. International relations with Libya have been normalized over the past decade and full diplomatic relations with the US were re-established in 2006. Major international exploration and production companies such as Shell, ENI and Total have re-entered the country and have active projects. The Corporation enjoys good relationships with key stakeholders in both countries.

The Corporation was awarded the EPSA following success in a competitive process with other bidders for the concession. Early production from Zarat will be liquids only which will find ready access to nearby, well traded markets. There are alternative potential export routes for gas from the block and an existing gas transportation network with both domestic consumers and international connections to European markets.

Offshore Nova Scotia, Canada

The Corporation is one of the few operators involved in all three main play types in the offshore Nova Scotia basin and currently holds the following exploration licenses: "Mayflower" (EL2406); "Marauder" (EL2415); "Mariner" (EL2409). Two of these licences, “Mariner” and Marauder”, 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. The Corporation relinquished EL2412 and EL2413 at the end of 2007. "Marconi" (EL2416), "Marquis" (EL2402) and 50% of EL 2406 were relinquished at the end of 2008.

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 2010. Front end geological and geophysical analysis are complete and environmental approvals are in place. Under the "Swap Agreement" entered into between the Corporation and Joint Oil in connection with the "Oasis" project, an overriding royalty interest and optional participating interest was awarded to Joint Oil in the "Mariner" Block.

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.

Canadian Superior has identified other Cretaceous and Jurassic prospects on its 100% "Marauder" 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.

Development of discoveries on Mariner and Marauder will be facilitated by access to the nearby Sable Offshore Energy facilities. The Corporation has approached the Sable operator, ExxonMobil, to determine whether this would be feasible. The operator reverted in March 2009 indicating that Sable facilities would likely be able to accommodate the proposed level of production subject to suitable flow conditions.

Western Canada

The Corporation continued its successful Western Canada exploration and development program in 2008. Currently, the Corporation derives all of its production and cash flow from Western Canada. Approximately 64% of the Corporation's production comes from the Drumheller area of Alberta. The Corporation completed the acquisition of a private company called Seeker Petroleum Ltd in March of 2008. This gave the Corporation exposure to the Cabin/Petitot area of NEBC and Kaybob and Sheldon areas of Alberta. It also provided additional exposure to the Parkland area of NEBC and the Windfall area of Alberta. Production for the Corporation averaged approximately 3,442 boe/d, average daily sales volume. During 2008, the Corporation drilled or participated in 33 gross, 30 operated and 3 non-operated (total of 27.5 net wells) with an overall success rate of 87%. In addition, the land picture for Canadian Superior continues to remain steady as the Corporation makes strategic farmins and land sale acquisitions. At December 31, 2008, the Corporation held in Western Canada 465,879 gross acres (326,626 net acres) of predominately Canadian Superior operated lands with an average working interest of approximately 70%. Net undeveloped land is 178,713 acres.

The Corporation spent most of the drilling budget in the second half of the year. While drilling results were positive a significant portion of the new found reserves were not tied in December 31, 2008. This resulted in an exit production rate of 3,165 boe/d. Approximately 800 boe/d was behind pipe at year end. A significant portion of these recently completed wells will enjoy new reduced royalty incentives.

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.

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 2008 held 161,103 gross acres (100,146 net acres) of land in Drumheller. Included in this number is 42,684 gross undeveloped acres (34,548 net undeveloped acres). This core area accounts for approximately 64% of the Corporation's production. In 2008, 12 gross (11.5 net) wells were drilled in the Drumheller area.

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 the Corporation 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 fairways.

Due to lower gas prices in 2008, the Corporation temporarily delayed some planned drilling of Horseshoe Canyon CBM wells. 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 the Corporation and its partners on a small portion of the Corporation'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 area.

The Corporation's total acreage for CBM is 126,372 gross acres (75,258 net) for both Horseshoe Canyon and Mannville CBM potential. The Corporation holds 105,732 gross acres (55,546 net) 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.

Windfall

Canadian Superior drilled 4 wells in 2008. One of these wells is on now production. The Seeker acquisition added production and undeveloped land in this area. The Banff, Nordegg and Mannville are the main drilling targets. 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.

Boundary Lake/Cecil/

The Boundary Lake/Cecil area is a high reward-medium risk that continues to gain momentum for exploration activity for Canadian Superior. It has multi-zone potential and year-round access. Following up successful wells in the area, the Corporation drilled 2 wells in 2008 in Boundary Lake

Kaybob

During 2008 Canadian Superior drilled 2 wells in the Kaybob area of Alberta. These wells have yet to be tied-in but do provide the Corporation with future drilling locations. This area continues to be of interest due to it’s muti-zone potential.

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: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. 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, 2008. 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, 2008. 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 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 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 – 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, 2008

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas
Proved	Mbbls	Mbbls	Mmcf	Mbbls	Mbbls	Mmcf
Developed Producing	933	201	21,013	845	133	18,177
Developed Non-Producing	116	74	5,808	103	46	4,711
Undeveloped	13	3	4,287	8	44	5,600
Total Proved	1,062	278	31,109	955	224	28,488
Total Probable	892	155	18,080	744	128	16,398
Total Proved Plus Probable(1)	1,954	433	49,189	1,699	352	44,885

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	157,559	128,628	109,699	96,236	86,121
Developed Non-Producing	31,464	26,531	22,849	20,011	17,768
Undeveloped	32,383	23,578	17,762	13,733	10,829
Total Proved	221,406	178,737	150,310	129,980	114,717
Total Probable	158,788	99,507	69,442	51,858	40,557
Total Proved Plus Probable	380,194	278,244	219,752	181,838	155,274

	After Future Income Tax Expenses and Discounted at
	0%	5%	10%	15%	20%
	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	157,559	128,628	109,699	96,236	86,121
Developed Non-Producing	31,464	26,531	22,849	20,011	17,768
Undeveloped	32,383	23,578	17,762	13,733	10,829
Total Proved	221,406	178,737	150,310	129,980	114,717
Total Probable	123,499	76,917	53,798	40,456	31,939
Total Proved Plus Probable	344,905	255,654	204,108	170,436	146,656

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	402,498	49,269	109,950	13,679	8,195	221,406	-	221,406
Total Proved Plus Probable	708,885	95,406	199,203	23,978	10,103	380,194	35,289	344,905

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)	39,793
Natural Gas(2)	100,742
Non-Conventional Oil and Gas Activities (CBM)	9,774
Total	150,310

Proved Plus Probable
Light and Medium Crude Oil(1)	59,119
Natural Gas(2)	142,281
Non-Conventional Oil and Gas Activities (CBM)	18,353
Total	219,752

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 - Forecast Prices and Costs

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2008 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, 2009
		Bank of Canada Average Noon Ex-change Rate	NYMEX WTI Near Month Futures Contract Crude Oil at Cushing Oklahoma		ICE BRENT Near Month Futures Contract Crude Oil FOB North Sea	Light Sweet Crude Oil (40 API, 0.3%S) at Edmonton	Bow River Crude Oil Stream Quality at Hardisty	Lloyd Blend Crude Oil Stream Quality at Hardisty	WCS Crude Oil Stream Quality at Hardisty	Heavy Crude Oil Proxy (12 API) at Hardisty	Light Crude Oil (35 API, 1.2 %S) at Cromer	Medium Crude Oil (29 API, 2.0%S) at Cromer	Alberta Natural Gas Liquids (Then Current Dollars)
Year	Inflla- tion %	Bank of Canada Average Noon Ex-change Rate	Constant 2009	Then Current	Then Current	Then Current	Then Current	Then Current	Then Current	Then Current	Then Current	Then Current	Spec Ethane	Edmonton Propane	Edmonton Butane	Edmonton Pentanes Plus
		$US/$Cdn	$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
1996	1.6	0.733	28.67	21.98	20.31	29.38	25.12	21.55	n/a	20.06	28.41	26.08	n/a	23.13	17.83	30.05
1997	1.6	0.722	26.46	20.62	19.32	27.85	21.18	20.55	n/a	14.41	26.52	23.72	n/a	19.41	19.76	30.91
1998	1.0	0.675	18.23	14.44	13.34	20.36	14.53	15.38	n/a	9.45	19.31	16.96	n/a	11.74	12.69	21.87
1999	1.7	0.673	24.13	19.25	17.99	27.63	22.78	22.14	n/a	19.49	26.97	25.37	n/a	15.86	18.65	27.64
2000	2.7	0.673	37.19	30.23	28.41	44.57	35.28	32.61	n/a	27.49	43.28	39.92	n/a	32.15	35.59	46.31
2001	2.5	0.646	31.15	26.00	24.87	39.44	27.69	23.47	n/a	16.77	35.22	31.58	n/a	31.92	31.25	42.48
2002	2.3	0.637	30.47	26.08	25.02	40.33	31.83	30.60	n/a	26.57	37.43	35.48	n/a	21.39	27.08	40.73
2003	2.8	0.716	35.48	31.07	28.47	43.66	32.11	31.18	n/a	26.26	40.09	37.55	n/a	32.14	34.36	44.23
2004	1.8	0.770	46.02	41.38	38.02	52.96	37.43	36.31	n/a	29.11	49.14	45.64	n/a	34.70	39.97	53.94
2005	2.2	0.826	61.78	56.58	55.14	69.02	44.73	43.03	43.74	34.07	62.18	56.77	n/a	43.04	51.80	69.57
2006	2.0	0.882	70.72	66.22	66.16	73.21	51.82	50.36	50.66	41.84	66.38	62.26	n/a	43.85	60.17	75.41
2007	2.2	0.935	75.80	72.39	72.71	77.06	53.64	52.03	52.38	43.42	71.13	65.71	n/a	49.56	61.78	77.38
2008 (e)	2.4	0.943	101.99	99.48	97.96	103.44	84.70	83.06	85.34	75.54	96.73	93.74	n/a	57.82	76.91	104.46
2009 Q1	2.0	0.825	50.00	50.00	48.50	59.52	43.15	41.96	42.36	35.33	54.16	51.18	22.62	37.49	45.23	60.71
2009 Q2	2.0	0.825	55.00	55.00	53.50	65.58	49.18	47.87	48.27	41.17	59.67	56.40	25.75	41.31	49.84	66.89
2009 Q3	2.0	0.825	60.00	60.00	58.50	71.64	55.16	53.73	54.13	46.92	65.19	61.61	23.46	45.13	54.44	73.07
2009 Q4	2.0	0.825	65.00	65.00	63.50	77.70	58.27	56.72	57.12	48.96	70.70	66.82	30.35	48.95	59.05	79.25
2009 Full Year	2.0	0.825	57.50	57.50	56.00	68.61	51.44	50.07	50.47	43.10	62.43	59.00	25.55	43.22	52.14	69.98
2010	2.0	0.850	66.67	68.00	66.50	78.94	59.21	57.63	58.03	49.76	72.63	68.68	26.80	49.73	61.57	80.52
2011	2.0	0.850	71.13	74.00	72.50	85.54	63.49	62.24	62.64	54.35	77.69	73.52	28.19	52.63	65.16	85.21
2012	2.0	0.875	80.10	85.00	83.50	90.92	69.10	67.73	68.13	59.23	84.55	80.01	29.43	57.28	70.92	92.74
2013	2.0	0.925	85.00	92.01	90.51	95.91	72.89	71.45	71.85	62.54	89.19	84.40	30.27	60.42	74.81	97.82
2014	2.0	0.950	85.00	93.85	92.35	97.84	74.36	72.89	73.29	63.82	90.99	86.10	30.94	61.64	76.32	99.80

Table 1

GLJ Petroleum Consultants

Crude Oil and Natural Gas Liquids

Price Forecast

Effective January 1, 2009

Bank of Canada Average Noon Ex-change Rate

NYMEX WTI Near Month Futures Contract Crude Oil at Cushing Oklahoma

ICE BRENT Near Month Futures Contract Crude Oil FOB North Sea

Light Sweet Crude Oil (40 API, 0.3%S) at Edmonton

Bow River Crude Oil Stream Quality at Hardisty

Lloyd Blend Crude Oil Stream Quality at Hardisty

WCS Crude Oil Stream Quality at Hardisty

Heavy Crude Oil Proxy (12 API) at Hardisty

Light Crude Oil (35 API, 1.2 %S) at Cromer

Medium Crude Oil (29 API, 2.0%S) at Cromer

Alberta Natural Gas Liquids

(Then Current Dollars)

Year

Inflla-

tion

Constant 2009

Then Current

Spec Ethane

Edmonton Propane

Edmonton Butane

Edmonton Pentanes Plus

$US/$Cdn

$US/bbl

$Cdn/bbl

2015	2.0	0.950	85.00	95.73	94.23	99.82	75.86	74.36	74.76	65.13	92.83	87.84	31.62	62.89	77.86	101.81
2016	2.0	0.950	85.00	97.64	96.14	101.83	77.39	75.87	76.27	66.46	94.70	89.61	32.31	64.15	79.43	103.87
2017	2.0	0.950	85.00	99.59	98.09	103.89	78.96	77.40	77.80	67.83	96.62	91.42	33.02	65.45	81.03	105.97
2018	2.0	0.950	85.00	101.59	100.09	105.99	80.55	78.96	79.36	69.22	98.57	93.27	33.74	66.77	82.67	108.10
2019+	2.0	0.950	85.00	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr
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, 2009
Year	Henry Hub NYMEX		Midwest	AECO/NIT Spot	Alberta Plant Gate					Saskatchewan Plant Gate			British Columbia		Sulphur FOB Vancouver	Alberta Sulphur at Plant Gate
	Near Month Contract		Price @ Chicago	AECO/NIT Spot	Spot		ARP	Aggre- gator	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot Plant Gate
	Constant 2009 $	Then Current	Then Current	Then Current	Constant 2009 $	Then Current	ARP	Aggre- gator	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot 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	3.27	2.51	2.73	1.39	1.64	1.26	1.63	N/A	N/A	1.52	1.28	1.32	1.49	1.47	36.28	6.48
1997	3.18	2.47	2.75	1.85	2.18	1.70	1.97	N/A	N/A	1.85	1.75	1.71	1.90	1.98	34.75	5.12
1998	2.73	2.16	2.20	2.03	2.37	1.87	1.94	N/A	N/A	2.05	2.13	1.60	2.15	2.00	24.59	(6.51)
1999	2.90	2.31	2.33	2.92	3.45	2.75	2.48	N/A	N/A	2.82	2.97	2.15	2.93	2.78	33.74	6.93
2000	5.31	4.32	3.96	5.08	6.06	4.93	4.50	4.44	N/A	4.79	5.16	4.15	5.06	4.88	38.14	13.59
2001	4.83	4.03	4.45	6.23	7.27	6.07	5.41	4.97	5.29	5.72	6.20	4.57	6.32	6.29	18.29	(14.67)
2002	3.92	3.36	3.25	4.04	4.53	3.88	3.88	3.64	3.66	4.04	4.08	2.68	4.18	3.93	29.38	3.04
2003	6.25	5.47	5.46	6.66	7.42	6.49	6.13	5.87	6.15	6.41	6.68	4.66	6.45	6.32	59.81	39.83
2004	6.87	6.18	6.13	6.88	7.45	6.70	6.31	6.16	6.39	6.48	6.85	5.26	6.56	6.45	62.99	38.61
2005	9.82	9.00	8.24	8.58	9.18	8.42	8.30	8.27	8.29	8.36	8.31	7.13	8.22	8.12	63.50	33.77
2006	7.46	6.99	6.93	7.16	7.42	6.96	6.57	6.36	6.34	6.67	6.97	6.27	6.58	6.45	55.07	19.27
2007	7.45	7.12	6.83	6.65	6.73	6.43	6.20	6.13	5.86	6.18	6.40	6.52	6.40	6.25	81.66	42.03
2008 (e)	9.14	8.92	8.91	8.16	8.12	7.92	7.78	7.82	7.83	8.03	7.84	8.33	8.11	7.97	464.73	448.28
2009 Q1	6.30	6.30	6.30	6.73	6.50	6.50	6.43	6.20	5.96	6.56	6.64	5.75	6.53	6.33	50.00	17.61
2009 Q2	7.05	7.05	7.05	7.64	7.40	7.40	7.32	7.06	6.83	7.45	7.55	6.50	7.44	7.23	50.00	17.61
2009 Q3	6.50	6.50	6.50	6.97	6.74	6.74	6.66	6.43	6.19	6.79	6.88	5.95	6.77	6.57	50.00	17.61
2009 Q4	8.15	8.15	8.15	8.97	8.72	8.72	8.62	8.32	8.10	8.75	8.88	7.60	8.77	8.56	50.00	17.61
2009 Full Year	7.00	7.00	7.00	7.58	7.34	7.34	7.26	7.00	6.77	7.39	7.49	6.45	7.38	7.17	50.00	17.61
2010	7.35	7.50	7.50	7.94	7.55	7.70	7.63	7.43	7.13	7.76	7.85	6.95	7.74	7.54	65.00	33.47
2011	7.69	8.00	8.10	8.34	7.78	8.10	8.03	7.81	7.58	8.16	8.25	7.45	8.14	7.94	75.00	42.71
2012	8.25	8.75	8.85	8.70	7.97	8.46	8.38	8.16	7.95	8.51	8.61	8.20	8.50	8.29	75.00	38.08
2013	8.50	9.20	9.30	8.95	8.04	8.70	8.62	8.39	8.19	8.75	8.86	8.65	8.75	8.54	75.00	35.95
2014	8.50	9.38	9.48	9.14	8.05	8.89	8.81	8.57	8.37	8.94	9.05	8.83	8.94	8.73	75.00	35.95
2015	8.50	9.57	9.67	9.34	8.07	9.09	9.00	8.76	8.56	9.13	9.25	9.02	9.14	8.92	75.00	35.95
2016	8.50	9.76	9.86	9.54	8.08	9.28	9.20	8.96	8.75	9.33	9.45	9.21	9.34	9.12	75.00	35.95
2017	8.50	9.96	10.06	9.75	8.10	9.49	9.40	9.15	8.95	9.53	9.66	9.41	9.55	9.33	75.00	35.95
2018	8.50	10.16	10.26	9.95	8.11	9.70	9.61	9.35	9.15	9.74	9.86	9.61	9.75	9.54	75.00	35.95
2019+	8.50	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+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.

The weighted average realized sales prices by the Corporation for the year ended December 31, 2008 was $8.58/Mcf for natural gas, $91.32/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, 2008 against such reserves as at December 31, 2007 based on forecast price and cost assumptions.

RECONCILIATION OF COMPANY GROSS RESERVES AT DECEMBER 31, 2008 BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS
Factors	Light and Medium Oil			Unconventional Gas (CBM)			Conventional Natural Gas			Natural Gas Liquids			BOE
	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable	Proved	Probable	Proved Plus Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mbbl)	(Mboe)	(Mboe)	(Mboe)
Dec. 31, 2007	817	848	1,665	4,685	5,197	9,882	20,648	8,693	29,341	192	87	279	5,231	3,250	8,481
Extensions	26	12	38	-	-	-	3,734	3,212	6,946	50	50	100	698	597	1,296
Improved Recovery*	131	44	175	78	15	93	2,539	885	3,424	34	12	46	601	206	807
Technical Revisions	108	(67)	41	341	(424)	(83)	590	(1,077)	(487)	(18)	(20)	(37)	246	(337)	(91)
Discoveries	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Acquisitions	152	44	196	-	-	-	4,382	1,496	5,878	74	25	99	956	318	1,275
Dispositions	-	-	-	-	-	-	-	-	-	-	-	-	-	-	-
Economic Factors	11	11	22	28	31	59	124	52	176	1	1	2	37	25	63
Production	(183)	-	(183)	(260)	-	(260)	5,780	-	(5,780)	(55)	-	(55)	(1,245)	-	(1,245)
Dec. 31, 2008	1,062	892	1,954	4,872	4,819	9,691	26,237	13,261	39,498	278	155	433	6,525	4,060	10,585
*includes folloing infill drilling:
	131	44	175	-	-	-	2034	664	2698	24	8	32	494	163	657

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).

	Forecast Prices and Costs
	Total Proved Reserves	Total Proved Plus Probable Reserves
	(M$)	(M$)
2009	8,951	11,479
2010	3,921	9,913
2011	546	1,672
Remaining Years	261	914
Total Undiscounted	13,679	23,978
Total Discounted 10% Per Year	12,510	21,404

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, 2008.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	84	61.6	41	28.7	286	133.25	164	102.4
British Columbia	-	-	-	-	6	2.15	-	-
Saskatchewan	-	-	1	1	-	-	6	6
Total	84	61.6	42	29.7	292	135.4	170	108.4

Properties With No Attributed Reserves

The following table sets out the Corporation's undeveloped land holdings as at December 31, 2008.

	Undeveloped Acres
	Gross	Net
British Columbia	34,760	12,256
Alberta	170,527	129,995
Saskatchewan	36,462	36,462
Offshore Nova Scotia(1)	1,197,070	1,197,070
Offshore Trinidad and Tobago	102,292	71,604
Total	1,541,111	1,447,387

Note:

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

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, 2008:

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

Gross Acres	1,197,070
Net Acres	1,197,070
Work Expenditure Commitment	$55,069,046
Deposits Tendered	$15,166,700

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 2009:

	Gross Undeveloped Acres	Net Undeveloped Acres
Alberta	16,600	14,658
British Columbia	3,575	1,642
Offshore Nova Scotia*	726,721	726,721
Total	746,896	743,021

* 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, 2008, 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 existing and future reserve wells, in thousands of dollars, using forecast prices:

	Annual Abandonment Costs
	Proved Producing	Total Proved	Total Proved Plus Probable
2009	165	165	165
2010	151	151	119
2011	321	352	254
2012	394	463	291
2013	429	532	150
2014	753	923	504
2015	412	607	600
2016	456	503	818
2017	266	349	542
2018	780	880	428
2019	200	441	368
2020	192	213	238
Subtotal	4,518	5,579	4,478
Remainder	1,776	2,617	5,626
Total	6,295	8,195	10,103
10% Discounted	2,929	3,634	3,305

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, 2008, the Corporation expected to incur reclamation and abandonment costs in respect of 623 gross (381.6 net) wells located on its properties and assets.

Tax Horizon

The Corporation does not expect to be cash taxable in 2009 or 2010 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, 2008.

	2008
	Gross	Net
Oil	6	5.1

Natural Gas (1)	21	16.7
Coal Bed Methane	-	-
Dry and Abandoned	6	5.7
Total	33	27.5

Note:

(1)	Natural Gas wells includes 2 gross wells drilled to earn a 10% 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, 2008, which is reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".

	2009 Estimated Daily Production
Entity Description	Light and Medium Oil		Natural Gas		Natural Gas Liquids		Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	bbl/d	bbl/d	mcf/d	mcf/d	bbl/d	bbl/d	bbl/d	bbl/d
Proved Producing
Aerial-Michichi	82	65	3.494	2,885	41	26	705	572
Other Properties	390	356	9.920	7,699	102	69	2,146	1,708
Total: Conventional	472	421	13,414	10,583	143	96	2,851	2,281
Non-Conventional Others	0	0	599	531	0	0	100	89
Total: Proved Producing	472	421	14,012	11,115	143	96	2,951	2,369
Proved Developed Non-Producing
Aerial-Michichi	25	21	729	495	9	6	156	110
Other Properties	36	28	2,663	1,756	24	15	504	335
Total: Conventional	62	49	3,392	2,251	33	21	660	445
Non-Conventional Others	0	0	23	20	0	0	4	3
Total: Proved Developed Non-Producing	62	49	3,415	2,271	33	21	664	448
Proved Undeveloped
Aerial-Michichi	0	0	0	0	0	0	0	0
Other Properties	21	12	152	419	1	8	47	89
Total: Conventional	21	12	152	419	1	8	47	89
Non-Conventional Others	0	0	201	174	0	0	33	29
Total: Proved Undeveloped	21	12	352	592	1	8	81	118
Total Proved
Aerial-Michichi	107	87	4,222	3,380	50	32	860	682
Other Properties	448	395	12,735	9,873	128	92	2,698	2,133
Total: Conventional	555	482	16.958	13,253	177	124	3,558	2,815
Non-Conventional Others	0	0	822	725	0	0	137	121
Total: Total Proved	555	482	17,780	13,978	177	124	3,695	2,936
Total Probable
Aerial-Michichi	3	2	190	113	2	1	37	22
Other Properties	20	13	2,807	1,815	23	16	511	332
Total: Conventional	23	15	2,997	1,928	26	18	548	354
Non-Conventional Others	0	0	17	15	0	0	3	3

	2009 Estimated Daily Production
Entity Description	Light and Medium Oil		Natural Gas		Natural Gas Liquids		Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
	bbl/d	bbl/d	mcf/d	mcf/d	bbl/d	bbl/d	bbl/d	bbl/d
Total: Total Probable	23	15	3,014	1,943	26	18	551	357
Total Proved Plus Probable
Aerial-Michichi	110	89	4,412	3,493	52	33	897	704
Other Properties	468	409	15,542	11,688	151	108	3,209	2,456
Total: Conventional	578	497	19,955	15,181	203	141	4,106	3,169
Non-Conventional Others	0	0	840	740	0	0	140	123
Total: Total Proved Plus Probable	578	497	20,794	15,921	203	141	4,246	3,292

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 2008

	Dec. 31	Sept. 30	June 30	Mar. 31
Average Daily Production(1)
Light Medium Crude Oil & NGL's (Bbls/d)	599	689	766	590
Gas (Mcf/d)	15,726	17,268	18,626	15,123
Combined (BOE/d)	3,220	3,567	3,871	3,110
Average Price Received
Light Medium Crude Oil & NGL's/Bbl	$50.25	$108.99	$110.23	$88.02
Gas ($/Mcf) After Hedging	$7.22	$8.55	$10.11	$8.14
Combined ($/BOE) After Hedging	$44.48	$62.45	$70.47	$56.29
Royalties Paid ($/BOE)	$11.04	$10.24	$12.63	$11.74
Operating Expenses ($/BOE)	$10.07	$14.44	$12.45	$7.39
Netback Received ($/BOE)(2)	$23.51	$37.77	$45.39	$37.16

Notes:

(1)	Before deduction of royalties.

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

For the year ended December 31, 2008, net average daily production for the Corporation's was 661 bbls/d light oil and 16,685 mmcf/d natural gas, or 3,442 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 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 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 freehold owner and the lessee, although production from such lands may be subject to certain provincial taxes. 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, depth of well, 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 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 revise existing incentive programs and royalty structures, which have generally resulted in increases to the amounts of royalties ultimately payable.

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 October 2007 Economic Statement, the federal corporate income tax rate will decrease to 15% in five steps: 19.5% on January 1, 2008, 19% on January 1, 2009, 18% on January 1, 2010, 16.5% on January 1, 2011 and 15% on January 2012.

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. On October 25, 2007, the Alberta government released a report entitled "The New Royalty Framework" containing the government's proposals for Alberta's new royalty regime, and was followed by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was given Royal Assent on December 2, 2008. The New Royalty Framework and the applicable new legislation became effective on January 1, 2009. Prior to the New Royalty Framework, the amount of conventional oil royalties that were payable was influenced by the oil production, density of the oil, and the vintage of the oil (the "Generic Regime"). Originally, the vintage classified oil was "new oil" and "old oil" depending on when the oil pools were discovered. If the pool was discovered prior to March 31, 1974 it was considered "old oil", and if it was discovered after March 31, 1974 and before September 1, 1992, it was 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 had a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a rate cap of

35%. The New Royalty Framework eliminates this classification and establishes new royalty rates for conventional oil, natural gas and oil sands. At that time, the new royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and increases the old royalty from 30%-35% applied to the old and new tiers, to up to 50% and with rate caps once the price of conventional oil reaches Cdn$120 per barrel.

The sliding rate formula includes in its calculation the price of oil and well production. With respect to natural gas, and similar to the conventional oil framework, the royalties outlined in the New Royalty Framework are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas reaches Cdn$16.59/Gigajoule. The New Royalty Framework determined rate is based on well depth, production rate, gas price and gas quality.

Prior to the New Royalty Framework, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, was up to 30% in the case of new natural gas, and up to 35% in the case of old natural gas, depending upon a prescribed or corporate average reference price. In response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced on November 19, 2008, the introduction of a five year program of transitional royalty rates with the intent of promoting new drilling, which program became effective January 1, 2009. Under this new program companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 metres) will be given a one-time option, on a well by well basis, to adopt either the new transitional royalty rates or those outlined in the New Royalty Framework. In order to qualify for this program wells must be drilled during the period starting on January 1, 2009 and ending in December 31, 2013.

Following this period all new wells drilled will automatically be subject to the New Royalty Framework. Oil sands projects are now subject to the New Royalty Framework, and regulated by, among others, the Oil Sands Royalty Regulation, 2009 approved by the Government of Alberta on December 10, 2008. Royalties on our current Firebag In-Situ project were under the 1997 Generic Regime until the end of 2008, and assessed based on bitumen value. In December 2008, the Government of Alberta enacted the New Royalty Framework, which increased royalty rates from the 1997 Generic Regime to a sliding-scale royalty of 25% to 40% of R – C, subject to minimum royalty of 1% to 9% of R, depending on oil price. In both cases, a sliding-scale royalty moves with increases in WTI prices from Cdn$55\bbl to the maximum rate at a WTI price of Cdn$120\bbl.

On April 10, 2008, the Government of Alberta introduced two new royalty programs to encourage the development of deep oil and gas reserves, and these are:

(a) a five-year oil program for exploration wells over 2,000 metres that will provide royalty adjustments to offset higher drilling costs and provide a greater incentive for producers to continue to pursue new, deeper oil plays (these oil wells will qualify for up to a $1 million or 12 months of royalty offsets, whichever comes first); and

(b) a five-year natural gas deep drilling program that will replace the existing program in order to encourage continued deep gas exploration for wells deeper than 2,500 metres (the program will create a sliding scale of royalty credit according to depth, of up to $3,750 per metre). These new programs are to be implemented along with the New Royalty Framework.

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 was to be eliminated, effective January 1, 2007. The programs affected by this announcement were:

(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 introduced was the Innovative Energy Technologies Program (the "IETP") which has a stated objective of promoting 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 decides which projects qualify and the level of support that will be provided. The deadline for the IETP's final round of applications was September 20, 2008. The successful applicants for the first two rounds have been announced, and those for the third round selection are scheduled to be announced in the first half of 2009. The technical information gathered from this program is to be made public once a two-year confidentiality period expires.

The New Royalty Framework includes a policy of "shallow rights reversion". The Government of Alberta stated that it will implement this policy in order to maximize the development of currently undeveloped resources that is consistent with the Government of Alberta's objective of maximizing recovery of known gas resources, while increasing royalty revenues. The policy's stated objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the government and be made available for resale, and in the event of non-productive shallow wells, to sever the rights from shallow zones and encourage increased production from up-hole zones. In December 2008, the Government of Alberta proclaimed an amendment to the Mines and Minerals Act (Alberta) with respect to shallow rights reversion. This amendment affects leases issued after January 1, 2009, with phased-in application for leases entered into prior to January 1, 2009.

British Columbia

Producers of oil and natural gas in 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 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 than the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines for 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 is intended to result in economic and employment opportunities for communities in British Columbia's heartlands.

Some of the financial incentives in the Strategy include:

Royalty credits 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. This program has evolved over past years as a result of the Province's stated objective to increase competitiveness. On March 2, 2009, the Government of British Columbia announced the 2009 Infrastructure Royalty Credit Program ("Program"), which allocates $120 million in royalty credits for oil and gas companies. The Program provides access to royalty credits to oil and gas companies with respect to certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas. Companies must apply to the Ministry of Energy and Mines for British Columbia prior to 2:00 p.m. on April 30, 2009 to be considered for approval under the program

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.

The British Columbia Energy Plan announced on February 27, 2007 outlines the requirements for the development of goals for conservation, energy efficiency and clean energy. In addition, its stated goals include to promote competitiveness through the implementation of a Net Profit Royalty Program ("NPRP") and facilitate the development of the oil and gas industry.

The NPRP's objective is to share the capital risk of successful developments. Pursuant to the Net Profit Royalty Regulation, the holder of a lease can apply to pay monthly net profit royalties on production of oil and for natural gas wells within a proposed project. The amount paid is calculated on the producer's interest in the project, and it ranges from 2% to 5% of the gross revenue and 15% to 35% of the net revenues received. In addition, it depends on which stage the well is at, which may be either pre-payout, after-payout or already producing marketable gas.

The Government of British Columbia has introduced a few more royalty programs, in addition to the ones previously mentioned, including a royalty program for deep discovery wells, royalty programs with a stated goal of attracting investment to less productive shallow gas wells (Ultra-Marginal Royalty Program), and the implementation of royalty credits to assist the development of the coal-bed gas reserves found in the Province of British Columbia.

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 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 and is produced from:

(a) oil wells with a finished drilling date on or after October 1, 2002; and

(b) oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 cubic metres of gas for every cubic metre of oil.

The royalty/tax is payable on associated natural gas produced from an oil well that exceeds approximately 65,000 cubic metres in a month. The associated natural gas royalty/tax regime will apply to gas produced from oil wells affected by concurrent production approvals after October 1, 2002 if the oil wells meet the criteria in paragraphs (a) or (b) above.

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 percent.

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.

A horizontal oil well with a finished drilling date on or after October 1, 2002 that is a non-deep oil well qualifies for a 6,000 cubic metre incentive volume.

A horizontal oil well with a finished drilling date on or after October 1, 2002 that is a deep oil well qualifies for a 16,000 cubic metre incentive volume.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the Government of Canada 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 seven years since the Government of Canada's initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income. Saskatchewan's RTR will be wound down as a result of the Government of Canada's plan to reintroduce full deductibility of provincial resource royalties for corporate income tax purposes.

On June 19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility Liability Management Program pursuant to the amendment of the Oil and Gas Conservation Act and the Oil and Gas Conservation Regulations, 1985. The program includes a security deposit, which has two purposes:

(i)

preventing any person with insufficient financial capability from acquiring oil and gas wells or facilities; and

(ii)

in the case of a bankrupt company, the funds cover the decommissioning and reclaiming of orphan properties. An additional change introduced is the mandatory licensing of all upstream oil and gas facilities in Saskatchewan.

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.

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. Until July 2008,crude oil prices had increased as a result of political events causing disruptions in the supply of oil, and increasing demand from countries like China and India that had been experiencing rapid industrial growth , and these upward price pressures may have been amplified by investment activities by commodity speculators. Since July 2008 the market price for crude oil has fallen drastically, as a result of a developing global recession that has reduced the consumption of crude oil and also reduced expectations for future crude oil consumption. The global recession is generally expected to last for an extended period of time, so barring unexpected political developments that could affect the supply or delivery of crude oil its price is not expected to increase significantly in the near term.

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 US recession, the market-wide declines in the share values of publicly traded companies, 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.

As a result of the above factors, access to investment capital for oil and gas exploration and for acquisitions will likely be more difficult than in recent years. The Corporation will have to compete with existing companies and with numerous new companies and their new management teams and

development plans to successfully access new investment 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.

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. Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility in commodity prices

and the rates at which the Corporation is able to borrow funds for its capital programs. These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in the broader Canadian, U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions, including higher borrowing rates. Despite the various actions taken by governments around the world, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward.

As a result of this weakened global economic situation, the Corporation along with all other oil and gas entities will have restricted access to capital and increased borrowing costs. Although our business and asset base have not changed, the lending capacity of all financial institutions has diminished and risk premiums have increased. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Corporation's ability to do so is dependent on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry generally and our securities in particular.

To the extent that external sources of capital become limited or unavailable or available on onerous terms, the Corporation's ability to make capital investments and maintain existing properties may be impaired, and the Corporation's business, financial condition, results of operations and cash flow may be materially adversely affected as a result. If cash flow from operations is lower than expected or 2009 capital expenditures exceed current estimates, or if the Corporation incurs major unanticipated expenses related to development or maintenance of its existing properties, the Corporation may be required to seek additional capital to maintain our capital expenditures at planned levels and the Corporation's debt ratings may be adversely affected.

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 for oil and natural gas companies of similar size. Depending on future development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the company’s articles nor its by-laws limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively effect our debt ratings. This in turn, could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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 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 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 recently stabilized at about CDN$1:USD$0.80, however this rate will certainly fluctuate as the various effects of the global recession play out in the Canadian and U.S. economies. Crude oil and natural gas prices are generally U.S. dollar based, so exchange rate fluctuations will affect the Corporation's sales revenue. The Corporation's exposure to currency exchange rate risks are reduced to the extent that its Canadian capital expenditures, Canadian operating costs and the majority of the Corporation's general and administrative expenses 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 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 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.

The holders of the First Preferred Shares, Series A, which are the only Preferred Shares issued and outstanding as of the date of the AIF, are entitled to receive, as and when declared by the Board of Directors of the Corporation, the payment of cumulative preferential cash dividends in an amount per share equal to $100 (One Hundred Dollars) multiplied by the applicable dividend rate, which will be 1.25% until December 30, 2010 and shall, for and restricted to the 150 day period after December 30, 2010, increase by 1/30 of 1% per day, resulting in a maximum applicable dividend rate of 6.25%.

Since March 31, 2006, dividends have been paid in this manner on the last day of March, June, September and December of each year. Dividends will continue to be paid in this manner on the last day of March, June, September and December of each year as long as all or any of the First Preferred Shares, Series A remain issued and outstanding.

The Corporation may elect to satisfy its dividend payment obligation entirely or in part by delivering Common Shares to the holders First Preferred Shares, Series A. When the Corporation so elects, the number of Common Shares issuable shall be equal to 115% of the applicable dividend rate multiplied by $100 (One Hundred Dollars) divided by the current market price of the Common Shares

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.

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.

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
2008	January	4.05	2.88	3.49	4,715,900
	February	3.74	3.18	3.22	3,446,700
	March	3.36	3.02	3.15	1,241,200
	April	3.45	2.96	3.07	2,700,100
	May	4.32	3.05	4.10	4,971,300
	June	4.99	4.03	4.70	4,721,700
	July	4.86	3.70	3.95	2,441,700
	August	5.01	3.86	4.07	7,141,100
	September	4.26	2.38	2.64	3,838,000
	October	2.81	1.27	1.87	4,086,200
	November	2.30	1.27	1.72	1,473,800
	December	1.73	1.00	1.20	1,938,800
2009	January	1.46	1.15	1.18	1,019,400
	February	1.25	0.35	0.46	6,257,200
	March	0.66	0.23	0.59	11,673,500

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(6)	Present and Principal Occupation During the Last Five Years
Leigh Bilton Calgary, Alberta, Canada	Non-Executive Vice Chairman	Not Applicable	Manager of all Canadian Superior Western Canadian operations from 2001 to February 2009.

Name and Municipality of Residence	Office or Position	Director Since(6)	Present and Principal Occupation During the Last Five Years
Charles Dallas (1),(4),(6) Innisfail, Alberta, Canada	Director	2000	Rancher and independent businessman.
Thomas J. Harp(2),(5), (6) Calgary, Alberta, Canada	Director	2000	Interim Chairman of the Corporation from April 24, 2009 to the current date. President of Harp Resources Ltd., a private resources company.
Gregory S. Noval Turner Valley, Alberta, Canada	Executive Chairman of the Board	1996	Executive Chairman of the Corporation from June 26, 2007 to April 24, 2009. Prior thereto, he was Chairman and Chief Executive Officer of Canadian Superior.
Michael E. Coolen Halifax, Nova Scotia, Canada	President, Chief Executive Officer, Chief Operating Officer and a Director	2006	President and Chief Operating Officer of the Corporation from April 10, 2006 to April 24, 2009, and CEO from December, 2008 to April 24, 2009. 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), (6) Toronto, Ontario, Canada	Director	2004	Managing Partner and Director of Brant Securities Ltd., an independent full service securities firm.
Robb D. Thompson Calgary, Alberta, Canada	Chief Financial Officer	Not applicable	Chief Financial Officer of the Corporation from February 5, 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), (6) Red Deer, Alberta, Canada	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), (6) Houston, Texas, US	Director	2006	Managing Director, Energy Advisors LLC, an energy consulting firm.
Leif Snethun Calgary, Alberta, Canada	Chief Operating Officer	Not applicable	Appointed Chief Operating Officer of the Corporation on April 29, 2009. Prior thereto was the Vice President of Western Canada for the Corporation from February 5, 2008 to April 29, 2009. Prior thereto founder, President and CEO of Seeker Petroleum.

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.

(6) Member of the Committee of Independent Directors

(7) All of the Director's terms are for one year and expire at the Corporation's next annual meeting of shareholders.

As at December 31, 2008, the number and percentage of Common Shares beneficially owned, or controlled or directed, directly or indirectly, by all directors and executive officers of the Corporation, as a group, was 2,019,958 Common Shares, being 1.2% of the outstanding Common Shares of the Corporation.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

No director or executive officer of the Corporation is, as at the date hereof, or was within 10 years before the date of hereof, a director, chief executive officer or chief financial officer of any issuer that:

(a)	was subject to an order that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer, or

(b)

was subject to an order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

For the purposes of subsection (a) above, “order” means a cease trade order, an order similar to a cease trade order, or an order that denied the relevant issuer access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days.

Other than the CCAA proceeding described above, no director or executive officer of the Corporation, or a shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation:

(c)

is, as at the date of hereof, or has been within the 10 years before the date hereof, a director or executive officer of any issuer that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or

(d)

has, within the 10 years before the date hereof, 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, executive officer or shareholder.

No director or executive officer of the Corporation, or a shareholder holding a sufficient number of securities of the Corporation to affect materially the control of the Corporation, has been subject to

(e)	any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or

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

Conflicts of Interest

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

For the year ended December 31, 2008 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.

In the period subsequent to the December 31, 2008 year end the Corporation became involved in two related and material legal proceedings, specifically the CCAA orders which have been granted to the Corporation and the interim receivership order affecting the Corporation's interest in Block 5(c). The details of these material legal proceedings are set out in the foregoing sections.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Within the last three completed financial years or the current financial year of the Corporation, other than as disclosed herein, none of the directors or executive officers of the Corporation or any person that beneficially owns, or controls or directs, directly or indirectly, more than 10% of the Common Shares of the Corporation, and no associate or affiliate of any such persons, has or has had any material interest, direct or indirect, in any transaction that has materially affected or is reasonably expected to materially affect the Corporation or any of its affiliates.

During the year ended December 31, 2008, Canadian Superior paid $ 2.3 million (2007 - $1.9 million) for equipment rentals to a related party company controlled by Mr. Gregory Noval, an officer and director of Canadian Superior. Also, during 2008, the Corporation invoiced $ 1.1 million (2007 - $0.7 million to this company for payroll services).

At December 31, 2008, Canadian Superior was carrying a receivable in the amount of US$29.1 million (2007 - US$19.7 million) 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.

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. This is also the location of the register.

MATERIAL CONTRACTS

There are no "material contracts", as defined under applicable securities regulations, that were entered into either within the last financial year, or before the before the last financial year that are still in effect.

A "material contract" in this context does not include otherwise material contracts that are entered into in the ordinary course of business unless that material contract is:

(a)

a contract to which directors, officers, or promoters are parties other than a contract of employment;

(b)

a continuing contract to sell the majority of the reporting issuer’s products or services or to purchase the majority of the reporting issuer’s requirements of goods, services, or raw materials;

(c)

a franchise or licence or other agreement to use a patent, formula, trade secret, process or trade name;

(d)

a financing or credit agreement with terms that have a direct correlation with anticipated cash distributions;

(e)

an external management or external administration agreement; or

(f)

a contract on which the reporting issuer’s business is substantially dependent.

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.

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 National 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., an independent full service securities firm.
Richard Watkins	Mr. 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.

External Auditor Fees

For the year ended December 31, 2008 and 2007, Meyers Norris Penny LLP and its affiliates were paid approximately $394,247 and $311,365, 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 $216,725 in 2008 and $201,798 in 2007.

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 $65,850 in 2008 and $52,115 in 2007

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 $15,330 in 2008 and $7,420 in 2007.

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 $96,342 in 2008 and $50,032 in 2007.

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 3200, 500 – 4th Avenue SW T2P 2V6 or by phone at (403) 294-1411 or fax at (403) 216-2374.

APPENDIX "A"

FORM 51-101F2

REPORT ON RESERVES DATA

INDEPENDENT QUALIFIED RESERVES

EVALUATOR OR AUDITOR

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, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

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

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

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

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, 2008, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors:

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate - $M)
Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	Corporate Summary March 25, 2009	Canada	-	219,752	-	219,752

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 27, 2009

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

Vice President

APPENDIX "B"

Report of Management and Directors

on Reserves Data and Other Information

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 a meaning is ascribed in NI 51-101 have the same meaning in this form.

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

Per NI 51-101F3]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 27, 2009.

The Reserves Committee of the board of directors of the Corporation has

(a)	reviewed the Corporation’s procedures for providing information to the independent qualified reserves evaluator;

(b)	met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.

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

(a)	the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)	the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c)	the content and filing of this report.

Because the reserves data are based on 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 April 29, 2009.







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

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;

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;

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.

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

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

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

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

SIGNIFICANT ACQUISITIONS	12

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	13

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	18

INDUSTRY CONDITIONS	28

RISK FACTORS	36

DIVIDENDS	42

DESCRIPTION OF CAPITAL STRUCTURE	43

MARKET FOR SECURITIES	44

DIRECTORS AND OFFICERS	45

LEGAL PROCEEDINGS	47

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	47

TRANSFER AGENT AND REGISTRAR	48

MATERIAL CONTRACTS	48

INTERESTS OF EXPERTS	48

AUDIT COMMITTEE	49

ADDITIONAL INFORMATION	50