**Exhibit 99.1**

** **

****

 

 

**ANNUAL INFORMATION FORM**

 

**(Except as otherwise noted the**

**information herein is given**

**as at December 31, 2007)**

 

**Dated:  March 30, 2008**

 

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**TABLE OF CONTENTS**

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

 

# ****

# ** **

# **ABBREVIATIONS**

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

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

 

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

Units (or metric units).

 
| **CONVERSIONS** |
|-----------------|

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

 

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

 

1

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# ** **

# **CERTAIN DEFINITIONS**

# ** **

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

 

**“ASC”** means the Alberta Securities Commission.

 

**“CanadaSouthern”** means Canada Southern Petroleum Ltd.

 

**“CanadianSuperior”** or the “Corporation” means CanadianSuperior Energy Inc.

 

**“CBM”** means coal bed methane.

 

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

 

**“CommonShares”** means the common shares in the capital ofthe Corporation.

 

**“GLJ”** means GLJ Petroleum Consultants Ltd.

 

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

 

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

 

**“NI51-101”** means National Instrument 51-101 – *Standards of Disclosure for Oiland Gas Activities*.

 

**“OSC”** means the Ontario Securities Commission.

 

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

 

**“PreferredShares”** means the first preferred shares in thecapital of the Corporation.

 

**“PSC”** means production sharing contract.

 

**“RightsPlan”** means the Corporation’s shareholder rightsplan.

 

**“RightsPlan Agreement”** means theshareholder’s rights plan agreement in respective of the Rights Plan datedeffective as of January 22, 2001 between the Corporation and Valiant TrustCompany of Canada, as amended from time to time.

 

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# ** **

# **GLOSSARY OF TECHNICAL TERMS**

# ** **

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

 

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

####  

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

#####  

##### (b)                                 if, and only to the extent that, there arefixed or presently determinable future prices or costs to which the Corporationis legally bound by a contractual or other obligation to supply a physicalproduct, including those for an extension period of a contract that is likelyto be extended, those prices or costs rather than the prices and costs referredto in paragraph (a).

#####  

For the purpose of paragraph (a), theCorporation’s prices will be the posted price for oil and the spot price forgas, after historical adjustments for transportation, gravity and otherfactors.

 

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

####  

#### 3.                                       “**development costs**”means costs incurred to obtain access to reserves and to provide facilities forextracting, treating, gathering and storing the oil and gas from the reserves.More specifically, development costs, including applicable operating costs ofsupport equipment and facilities and other costs of development activities, arecosts incurred to:

####  

##### (a)                                  gain access to and prepare well locations fordrilling, including surveying well locations for the purpose of determiningspecific development drilling sites, clearing ground, draining, road building,and relocating public roads, gas lines and power lines, to the extent necessaryin developing the reserves;

#####  

##### (b)                                 drill and equip development wells, developmenttype stratigraphic test wells and service wells, including the costs ofplatforms and of well equipment such as casing, tubing, pumping equipment andthe wellhead assembly;

#####  

##### (c)                                  acquire, construct and install productionfacilities such as flow lines, separators, treaters, heaters, manifolds,measuring devices and production storage tanks, natural gas cycling andprocessing plants, and central utility and waste disposal systems; and

#####  

##### (d)                                 provide improved recovery systems.

#####  

#### 4.                                       “**development well**”means a well drilled inside the established limits of an oil or gas reservoir,or in close proximity to the edge of the reservoir, to the depth of a stratigraphichorizon known to be productive.

####  

#### 5.                                       “**exploration costs**”means costs incurred in identifying areas that may warrant examination and inexamining specific areas that are considered to have prospects that may containoil and gas reserves, including costs of drilling exploratory wells andexploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the relatedproperty (sometimes referred to in part as “prospecting costs”) and afteracquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilitiesand other costs of exploration activities, are:

####  

#### 3

#### 

####  

##### (a)                                  costs of topographical, geochemical, geologicaland geophysical studies, rights of access to properties to conduct thosestudies, and salaries and other expenses of geologists, geophysical crews andothers conducting those studies (collectively sometimes referred to as “geologicaland geophysical costs”);

#####  

##### (b)                                 costs of carrying and retaining unprovedproperties, such as delay rentals, taxes (other than income and capital taxes)on properties, legal costs for title defence, and the maintenance of land andlease records;

#####  

##### (c)                                  dry hole contributions and bottom hole contributions;

#####  

##### (d)                                 costs of drilling and equipping exploratorywells; and

#####  

##### (e)                                  costs of drilling exploratory typestratigraphic test wells.

#####  

#### 6.                                       “**exploratory well**”means a well that is not a development well, a service well or a stratigraphictest well.

####  

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

####  

#### 8.                                       “**future prices and costs**”means future prices and costs that are:

####  

##### (a)                                  generally accepted as being a reasonableoutlook of the future;

#####  

##### (b)                                 if, and only to the extent that, there arefixed or presently determinable future prices or costs to which the Corporationis legally bound by a contractual or other obligation to supply a physicalproduct, including those for an extension period of a contract that is likelyto be extended, those prices or costs rather than the prices and costs referredto in paragraph (a).

#####  

#### 9.                                       “**future net revenue**”means the estimated net amount to be received with respect to the developmentand production of reserves (including synthetic oil, coal bed methane and othernon-conventional reserves) estimated using constant prices and costs orforecast prices and costs.

####  

#### 10.                                 “**gross**” means:

####  

##### (a)                                  in relation to the Corporation’s interest inproduction or reserves, its “company gross reserves”, which are its workinginterest (operating or non-operating) share before deduction of royalties andwithout including any royalty interests of the Corporation;

#####  

##### (b)                                 in relation to wells, the total number of wellsin which the Corporation has an interest; and

#####  

##### (c)                                  in relation to properties, the total area ofproperties in which the Corporation has an interest.

#####  

####  

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

####  

#### 4

#### 

####  

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

####  

#### 12.                            “**natural gas liquids**”means those hydrocarbon components that can be recovered from natural gas asliquids including, but not limited to, ethane, propane, butanes, pentanes plus,condensate and small quantities of non-hydrocarbons.

####  

#### 13.                                 “**net**” means:

####  

##### (a)                                  in relation to the Corporation’s interest inproduction or reserves its working interest (operating or non-operating) shareafter deduction of royalty obligations, plus its royalty interests inproduction or reserves;

#####  

##### (b)                                 in relation to the Corporation’s interest inwells, the number of wells obtained by aggregating the Corporation’s workinginterest in each of its gross wells; and

#####  

##### (c)                                  in relation to the Corporation’s interest in aproperty, the total area in which the Corporation has an interest multiplied bythe working interest owned by the Corporation.

#####  

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

####  

#### 15.                                 “**operating costs**”or “**production costs**” means costs incurredto operate and maintain wells and related equipment and facilities, includingapplicable operating costs of support equipment and facilities and other costsof operating and maintaining those wells and related equipment and facilities.

####  

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

####  

#### 17.                                 “**property**”includes;

####  

##### (a)                                  fee ownership or a lease, concession,agreement, permit, license or other interest representing the right to extractoil or gas subject to such terms as may be imposed by the conveyance of thatinterest;

#####  

##### (b)                                 royalty interests, production payments payablein oil or gas, and other non-operating interests in properties operated byothers; and

#####  

##### (c)                                  an agreement with a foreign government or authorityunder which the Corporation participates in the operation of properties orotherwise serves as “producer” of the underlying reserves (in contrast to beingan independent purchaser, broker, dealer or importer).

#####  

butdoes not include supply agreements, or contracts that represent a right topurchase, rather than extract, oil or gas.

 

#### 18.                                 “**proved property**”means a property or part of a property to which reserves have been specificallyattributed.

####  

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

####  

#### 5

#### 

####  

#### 20.                                 “**service well**”means a well drilled or completed for the purpose of supporting production inan existing field. Wells in this class are drilled for the following specificpurposes: gas injection (natural gas, propane, butane or flue gas), waterinjection, steam injection, air injection, salt-water disposal, water supplyfor injection, observation, or injection for combustion.

####  

#### 21.                                 “**unproved property**”means a property or part of a property to which no reserves have beenspecifically attributed.

####  

#### 22.                                 “**well abandonment costs**”means costs of abandoning a well (net of salvage value) and of disconnectingthe well from the surface gathering system. They do not include costs ofabandoning the gathering system or reclaiming the wellsite.

####  

# **CURRENCY OF INFORMATION**

# ** **

The information in this Annual Information Form is stated as at December 31,2007, unless otherwise indicated. For an explanation of the capitalized termsand expressions and certain defined terms, please refer to the “Glossary ofTechnical Terms” in this Annual Information Form. Except as otherwiseindicated, all dollar amounts in this Annual Information Form areexpressed 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 regardingestimates of reserves, estimates of future production as well as otherstatements about anticipated future events or results are forward lookingstatements. Forward looking statements often, but not always, are identified bythe 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 similarexpressions. Forward-looking statements in this document include, but are notlimited to, statements about:

 

#### ·                                          the future commercial success of the Corporation’s oil and natural gas exploration, development andproduction 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 thefuture;

 

#### ·                                          competition with and among other oil and gas companiesfor the acquisition, exploration, production and development of oil and naturalgas properties;

 

#### ·                                          the Corporation’s oil and natural gas reserves;

 

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

 

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

 

This Annual Information Form contains forward-looking informationon future production, project start-ups and future capital spending. Actualresults or estimated results could differ materially due to changes in projectschedules, operating performance, demand for oil and gas, commercialnegotiations or other technical and economic factors or revisions.

 

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

 

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

 

This Annual Information Form, the documents incorporated by referenceinto this Annual Information Form, and other reports and filings made with thesecurities regulatory authorities include forward-looking statements. Allforward looking statements are based on the Corporation’s beliefs andassumptions based on information available at the time the assumption was made.Forward-looking statements relate to, among other things, anticipated financialperformance, business prospects, strategies, regulatory developments, newservices, market forces, commitments and technological developments. Much ofthis information also appears in management’s discussion and analysis. By itsnature, such forward-looking information is subject to various risks anduncertainties, including those material risks discussed in this AnnualInformation Form under “Risk Factors”, which could cause the Corporation’sactual results and experience to differ materially from the anticipated resultsor other expectations expressed. Readers are cautioned not to place unduereliance on this forward-looking information, which is given as of the date itis expressed in this Annual Information Form or otherwise, and theCorporation undertakes no obligation to update publicly or revise anyforward-looking information, whether as a result of new information, future eventsor otherwise except as required by securities law.

 

# **THE CORPORATION**

# ** **

Canadian Superior was incorporated as 297272 Alberta Ltd. by Articles ofIncorporation 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 privatecompany restrictions in its articles; (ii) on November 16, 1993, tochange its name to “Prize-Energy Inc.” and to consolidate its issued andoutstanding Common Shares on a 1-for-5 basis; and (iii) on January 19,1999, to permit the appointment of additional directors between annual meetingsand to restate its articles in aconsolidatedform. On August 24, 2000, a further amendment changed the name of theCorporation to “Canadian Superior Energy Inc.” and consolidated its issued andoutstanding Common Shares on a l-for-2 basis.

 

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

 

7

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

 

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

 

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

 

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

 

# **GENERAL DEVELOPMENT OF THE BUSINESS**

# ** **

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

 

The most significant events in the development of the business ofCanadian Superior during the past three completed fiscal years are describedbelow.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

8

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On January, 23, 2007, the Corporation announced that its offshore NovaScotia exploration acreage holdings have increased to 2.59 million net acreswith the addition of the EL2412 and EL2413 deepwater blocks previously held bya U.S. company.

 

On December 29, 2006 the Corporation completed a private placementof 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 Shareson a “flow-through” basis at a price of $2.57 per Common Share for aggregateproceeds of $15.4 million.

 

On August 16, 2006, Neil Dore was appointed Vice President WesternCanada Operations and Roger Harman was appointed as Chief Financial Officer ofthe Corporation.

 

In June 2006, Canadian Superior offered to acquire all of theissued and outstanding shares of Canada Southern Petroleum Ltd. from existingshareholders. Canadian Superior offered 2.75 Common Shares plus $2.50 cash foreach 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 gasattributed to it’s interest in the Canadian Arctic Islands. The minimumcondition attached to the revised offer was not met. 171,495 Canada Southernshares were tendered to the original offer, for which Canadian Superior issued471,612 Common Shares and paid $0.4 million to take-up. The costs incurred inrelation to the offer, including the fair value of the Common Shares issuedupon 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’sfinancial statements. Canadian Superior subsequently received US$2.2 million asa result of the sale of the Canada Southern shares acquired.

 

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

 

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

 

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

 

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

 

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

 

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

 

9

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On September 6, 2005, the Corporation and its insurers reached anagreement to settle all securities class action litigation and other actionspending in Canada against the Corporation and certain of its officers anddirectors resulting from the drilling in 2004 of the Mariner 1-85 explorationwell drilled offshore Nova Scotia. The $2.15 million settlement, which wascovered by the Corporation’s insurance, was reached with no admission ofliability by any party.

 

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

 

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

 

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

 

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

 

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

 

# **DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES**

# ** **

Canadian Superior is engaged in the exploration for, and the developmentand production of, crude oil and natural gas primarily in Western Canada andoffshore Nova Scotia, Canada and Trinidad and Tobago. The Corporation alsoreviews potential acquisitions and new international exploration blocks tosupplement its exploration and development activities.

 

## **OIL AND GAS PROPERTIES**

 

A summary description of the Corporation’s major producing andexploration properties is set out below. References to gross volumes refer tototal production. References to net volumes refer to the Corporation’s workinginterest share before the deduction of royalties payable to others.

 

### ***Trinidad and Tobago***

 

On July 20, 2005, Canadian Superior signed a PSC for the 80,020acre “Intrepid” Block 5(c), offshore Trinidad and Tobago, with the Governmentof the Republic of Trinidad and Tobago. The PSC provides Canadian Superior theright to explore on “Intrepid” Block5(c).

 

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

 

10

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The three “Intrepid” Block wells will evaluate three large separatepotential hydrocarbon bearing structures that have been delineated by extensive3D seismic over the entire “Intrepid” Block 5(c) that Canadian Superiorhas evaluated and interpreted. The first well commenced drilling shortly afterthe Kan Tan IV had completed a scheduled refurbishment in Brownsville, Texas.On May 11, 2007 the Kan Tan IV was towed out of the port of Brownsville,Texas, en route to the port of Chaguarmas in Trinidad to load up supplies andfinalize drilling preparations and was then moved to the first drillinglocation on the “Victory” Prospect arriving on site June 19, 2007. Thefirst well on the “Intrepid” Block 5(c) was on the “Victory” Prospect, thesecond and third wells are planned for the “Bounty” and “Endeavour” prospects.

 

On June 25, 2007, the drilling of a pilot hole at the “Victory”well site commenced. Following that drilling and evaluation, the main well borewas spudded on June 29, 2007. On August 30, 2007, the “Victory” wellsite reached Total Depth of 16,621 feet (subsea).  In attempting to come out of the hole tocommence wireline logging and possible flow testing of the well, difficultieswere encountered which resulted in being unable to remove the full drillstringfrom the well. Accordingly the well was severed at a depth of approximately11,726 feet and the well plugged back to a depth of approximately 9,564 feet.The lower portion of the well was re-drilled to a total depth of 16,150 feet.  On December 17, 2007, the Corporationannounced that it had unanimously agreed with its partners to case and conductflow tests on the “Victory” well.

 

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

 

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

 

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

 

To assist Canadian Superior in going forward with its drilling inTrinidad, the Corporation had entered into a participation agreement with anon-competitive industry financial partner. The partner participates on apromoted basis paying 1/3 of Canadian Superior’s Block 5(c) explorationprogram costs to obtain 25% of Canadian Superior’s revenue share of theseprospects. In addition, in August, 2007, the Corporation announced that BG, a whollyowned subsidiary of BG Group PLC, had entered into a farm-in agreement andjoint operating agreement. BG will participate on a promoted basis payingapproximately 40% of Canadian Superior’s Block 5(c) exploration program coststo obtain a 30% working interest in the production sharing contract. BG alsopaid approximately US$39 million, addressing BG’s share of previous incurredcosts and a substantial entry bonus.

 

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

 

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various geological and geophysical analysis, evaluations andinterpretation, in 2006 and 2007, many other well construction preparatoryactivities were undertaken in the areas of engineering, procurement, health,safety and environmental management, community relations, regulatory approvalsand corporate oversight of the Kan Tan IV’s refurbishment project. Thisincluded the purchasing of pipe, wellheads and long lead items to facilitatethe timely drilling of the first two wells, in addition to making an advancepayment of US$20 million to the rig owners to be applied against drilling dayrate charges.

 

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

 

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

 

### ***Offshore Nova Scotia, Canada***

### *** ***

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

 

Canadian Superior’s “Mariner” shallow water block (EL2409) covers100,656 acres and is located approximately nine kilometres northeast of SableIsland, offshore Nova Scotia and directly offsets five significant discoveriesnear Sable Island, including the ExxonMobil Venture natural gas productionfield and other nearby Sable Offshore Energy Project existing productioninfrastructure. Three large Cretaceous structures have been identified fordrilling on the “Mariner” block based on an evaluation of seismic data. Thefirst exploration well, Canadian Superior El Paso “Mariner” I-85, was drilledon this block in November 2003 to March 2004 and encountered gas payin multiple zones. Two new prospective locations have been identified andfurther drilling is planned by Canadian Superior on the “Mariner” Block in 2009.Front end geological and geophysical analysis are complete and environmentalapprovals are in place.

 

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

 

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

 

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

 

### ***Western Canada***

### *** ***

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

 

Canadian Superior reported that due to ongoing drilling success in 2007,with new production brought on-stream throughout 2007, production averagedapproximately 3,025 boe/d raw (2,843 boe/d, average daily sales volume) for theyear, and although flat compared to 2006 on a yearly average, showed significantgrowth in the 4th quarter resulting in year end production of approximately3,520 boe/d raw (3,290 boe/d, average daily sales volume).

 

During 2007, the Corporation drilled or participated in 73 gross, 25operated and 48 non-operated (total of 25.0 net wells) with an overall successrate of 92%. In addition, the land picture for Canadian Superior continues toremain steady as the Corporation drills and makes strategic land saleacquisitions. At December 31, 2007, the Corporation held in Western Canada246,445 gross acres (164,968 net acres) of predominately Canadian Superioroperated lands with a high working interest of approximately 70%.

 

On January 16, 2008, the Corporation announced entering into anacquisition agreement whereby Canadian Superior will acquire subject to certainconditions, all of the issued and outstanding shares of Seeker Petroleum Ltd.,for total consideration of approximately $51.2 million, including theassumption of approximately $8.5 million of debt.  Canadian Superior will acquire approximately1,035 boe/d of Western Canadian production and 2,073 MBOE of proven plusprobable reserves.

 

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

 

*Drumheller Area*

 

Inthe Drumheller area of Central Alberta, Canada, located approximately 60 milesN.E. of the City of Calgary, the Corporation has major acreage and productionholdings in both conventional Cretaceous plays and in the Horseshoe Canyon andMannville Coal Bed Methane (“CBM”) plays; an area which has shallow low costprospects and year-round accessibility.

 

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TheDrumheller area offers a multitude of opportunities that include both oil andgas play types and these are contained in six distinct stratigraphiczones.  The shallow targets include theSecond White Specks, Medicine Hat, Belly River Group, and Edmonton Groups andrange 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 includethe Mannville group and the Banff formation. The Mannville group typically encounters several stacked reservoirs suchas the Colony, Glauconitic, Ostracod, Ellerslie, and Detrital with averageproduction rates for these horizons ranging from 250 to over 1000 mcf/d andreserves of 0.5 to 2 Bcf.  The Banffformation 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 withreserves ranging from 20 - 200 mbbl.

 

TheCorporation at the end of 2007 held 167,183 gross acres (107,126 net acres) ofland in this area, with 40% of this still to be developed.  This core area accounts for approximately 90%of Canadian Superior’s production.  In2007, 63 gross (17.9 net) wells were drilled in the Drumheller area consistingof 55 gross (15.5 net) conventional wells and 8 gross (2.4 net) HorseshoeCanyon CBM wells.

 

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

 

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

 

TheCorporation’s total acreage for CBM is 185 gross (108 net) sections of which 14gross (13.4 net) sections have both Horseshoe Canyon and Mannville CBMpotential.  Canadian Superior holds 157gross (81 net) sections of Horseshoe Canyon rights.  The Horseshoe Canyon Coal depths range from200 - 400 meters (650 - 1300 feet) and are typically found in 8 - 10 coal seamswith each seam averaging from 0.75 - 1.5 meters (2.5 - 5 feet).  These coals contain dry gas and producelittle or no water.

 

Anuntapped resource that exists in the Drumheller area is the Mannvillecoals.  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 theearly stages but Canadian Superior calculates it has over 1000 BCF (P50) of netsales reserves in this area.  Currentlythe Corporation has 42 gross (41 net) sections of land in the Mannville CBMfairway.  Drilling for these coals wouldinclude horizontal drilling techniques. Plans for development of Mannville CBM by Canadian Superior will bemeasured until the reserve and production parameters are better defined.

 

14

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*Windfall*

 

CanadianSuperior drilled 2 wells in 2007 and one of these wells is on production.  The Corporation continues to look at thishigher reward-medium risk area with a view towards further expansion, using itscurrent land base as a nucleus.  Innearby Rimbey the Corporation drilled and completed one gas well.  In this particular well, gas rates did notjustify a tie-in and it was subsequently abandoned.

 

*BoundaryLake/Cecil/Peroria/Parkland*

 

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

 

*The Foothills of Alberta, West ofthe 5th Meridian*

 

During2007 Canadian Superior also focused its exploration in Western Canada towardsthe foothills of Alberta, Canada to develop potentially high deliverabilitylarge reserve based drillable prospects in the Foothills.  This area represents an area of highrisk-high reward exploration and production with year-round access.  In this area, well reserves can range to over10 BCF/well with associated natural gas liquids and can produce at rates ofover 5-10 mmcf/d.  Land strategies forthis area include crown sales, leasing of freehold acreage and potentialfarm-ins or joint ventures.

 

# **STATEMENT OF RESERVES DATA ANDOTHER OIL AND GAS INFORMATION**

# ** **

## **GENERAL**

 

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

 

### ***Selected Reserves Information***

### *** ***

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

 

15

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

 

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

 

In accordance with the requirements of NI 51-101, the Report on ReservesData by Independent Qualified Reserves Evaluator in Form 51-101F2 and theReport of Management and Directors on Oil and Gas Disclosure in Form 51-101F3are attached as Appendices “A” and “B” hereto, respectively.

 

## **RESERVES DATA - CONSTANT PRICES AND COSTS**

 

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

 

### ***Summary of Oil and GasReserves: Effective December 31, 2007***

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

 

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Notes:

 

(1)           Sometotals may differ slightly due to rounding.

### *** ***

### ***Net Present Value of FutureNet Revenue of Oil and Gas Reserves***

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

 

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### ***Additional InformationConcerning Future Net Revenue (Undiscounted)***

 
| ** **                 | ** ** | **Revenue** | ** ** | **Royalties** | ** ** | **Operating  Costs** | ** ** | **Development  Costs** | ** ** | **Abandonment**

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

 

### ***Future Net Revenue ByProduction Group***

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

 

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Notes:

 

(1)          Including solution gasand other by-products.

(2)          Including by-productsbut excluding solution gas.

(3)          Other company revenueand cost not related to a specific production group have been allocatedproportionately to production groups.

 

## **RESERVES DATA – FORECAST PRICES AND COSTS**

 

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

 

### ***Summary of Oil and GasReserves: Effective December 31, 2007***

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

 

17

----

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

 

### ***Net Present Value of FutureNet Revenue of Oil and Gas Reserves***

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

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

### *** ***

### ***Additional InformationConcerning Future Net Revenue (Undiscounted)***

 
| ** **                      | ** ** | **Revenue** | ** ** | **Royalties** | ** ** | **Operating  Costs** | ** ** | **Development  Costs** | ** ** | **Abandonment**

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

 

18

----

### *** ***

### ***Future Net Revenue ByProduction Group***

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

 

----

Notes:

 

(1)        Including solution gasand other by-products.

(2)        Including by-productsbut excluding solution gas.

(3)        Other company revenueand cost not related to a specific production group have been allocatedproportionately to production groups.

 

## **PRICING ASSUMPTIONS - CONSTANT PRICES AND COSTS**

 

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

 

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

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

 

19

----

 

**NaturalGas and Sulphur Price Forecast**

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

 

Unless otherwise stated, the gas price reference pointis the receipt point on the applicable provincial gas transmission system knownas the plant gate.

 

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

 

Spot refers to weighted average one-month price.

 

----

Note:                   These prices areactual posted prices at the referenced date; other reference prices are derivedbased on historical price differentials.

 

(1)                                  Noon Rate for the Bankof Canada

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

(3)                                  Spot prices for datedBrent from Bloomberg

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

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

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

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

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

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

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

(11)                            Same day settlementprice from NGX

(12)                            Next day settlementprice from NGX

(13)                            Utilized current GLJforecast price

 

## **PRICING ASSUMPTIONS - FORECAST PRICES AND COSTS**

 

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

 

**Table 1**

GLJ Petroleum Consultants

**Crude Oil and Natural Gas Liquids**

**Price Forecast**

Effective January 1, 2008

 
| ** ** | ** ** | **Inflla-**

**tion  %** | ** ** | **Bank  of  Canada  Average  Noon  Exchange**

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

 

20

----

 
| ** **                                                                                                                          | ** ** | ** **          | ** ** | **Bank of  Canada  Average** | ** ** | **NYMEX WTI Near  Month Futures  Contract Crude Oil at  Cushing Oklahoma** | ** ** | **ICE BRENT Near  Month Futures  Contract Crude Oil  FOB North Sea** | ** ** | **Light Sweet Crude Oil  (40 API, 0.3%S) at  Edmonton** | ** ** | **Lloyd Blend  Stream Quality at  Hardisty** | ** ** | **Heavy Crude Oil  Proxy (12 API) at  Hardisty** | ** ** | **Medium Crude Oil  (29 API, 2.0%S) at  Cromer** | ** ** | ** **         | ** ** | **Alberta Natural Gas  Liquids (Then Current  Dollars)** | ** ** | ** **         | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------|------------|-----------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|--------------------|------------|------------------------------------------------------------------------------|------------|--------------------|------------|
| **Year**                                                                                                                            | ** ** | **Inflla-  tion %** | ** ** | **Noon  Exchange  Rate**          | ** ** | **Constant  2007**                                                                                            | ** ** | **Then  Current**                                                                                       | ** ** | **Constant  2007**                                                                    | ** ** | **Then  Current**                                           | ** ** | **Constant  2007**                                                        | ** ** | **Then  Current**                                                         | ** ** | **Constant  2007** | ** ** | **Then  Current**                                                            | ** ** | **Constant  2007** | ** ** | **Then  Current** | ** ** | **Constant  2007** | ** ** | **Then  Current** | ** ** | **Spec  Ethane** | ** ** | **Edmonton  Propane** | ** ** | **Edmonton  Butane** | ** ** | **Edmonton  Pentanes  Plus** | ** ** |
| ** **                                                                                                                          | ** ** | ** **          | ** ** | **$US/  $Cdn**                    | ** ** | **$US/  bbl**                                                                                                 | ** ** | **$US/  bbl**                                                                                           | ** ** | **$US/  bbl**                                                                         | ** ** | **$US/  bbl**                                               | ** ** | **$Cdn/  bbl**                                                            | ** ** | **$Cdn/  bbl**                                                            | ** ** | **$Cdn/  bbl**     | ** ** | **$Cdn/  bbl**                                                               | ** ** | **$Cdn/  bbl**     | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** | **$Cdn/  bbl** | ** ** |
| 1998                                                                                                                                |       | 1.0                 |       | 0.675                             |       | 17.80                                                                                                         |       | 14.44                                                                                                   |       | 16.45                                                                                 |       | 13.34                                                       |       | 25.10                                                                     |       | 20.36                                                                     |       | 18.44              |       | 14.95                                                                        |       | 11.66              |       | 9.45 |   | 20.91 |   | 16.96 |   | n/a |   | 11.74 |   | 12.69 |   | 21.87 |   |
| 1999                                                                                                                                |       | 1.7                 |       | 0.673                             |       | 23.53                                                                                                         |       | 19.25                                                                                                   |       | 21.99                                                                                 |       | 17.99                                                       |       | 33.78                                                                     |       | 27.63                                                                     |       | 27.07              |       | 22.14                                                                        |       | 23.83              |       | 19.49 |   | 31.01 |   | 25.37 |   | n/a |   | 15.86 |   | 18.65 |   | 27.64 |   |
| 2000                                                                                                                                |       | 2.7                 |       | 0.673                             |       | 36.30                                                                                                         |       | 30.23                                                                                                   |       | 34.10                                                                                 |       | 28.41                                                       |       | 53.51                                                                     |       | 44.57                                                                     |       | 39.16              |       | 32.61                                                                        |       | 33.03              |       | 27.49 |   | 47.93 |   | 39.92 |   | n/a |   | 32.15 |   | 35.59 |   | 46.31 |   |
| 2001                                                                                                                                |       | 2.5                 |       | 0.646                             |       | 30.41                                                                                                         |       | 26.00                                                                                                   |       | 29.09                                                                                 |       | 24.87                                                       |       | 46.13                                                                     |       | 39.44                                                                     |       | 27.46              |       | 23.47                                                                        |       | 19.62              |       | 16.77 |   | 36.95 |   | 31.58 |   | n/a |   | 31.92 |   | 31.25 |   | 42.48 |   |
| 2002                                                                                                                                |       | 2.2                 |       | 0.637                             |       | 29.73                                                                                                         |       | 26.08                                                                                                   |       | 28.52                                                                                 |       | 25.02                                                       |       | 45.98                                                                     |       | 40.33                                                                     |       | 34.89              |       | 30.60                                                                        |       | 30.29              |       | 26.57 |   | 40.45 |   | 35.48 |   | n/a |   | 21.39 |   | 27.08 |   | 40.73 |   |
| 2003                                                                                                                                |       | 2.8                 |       | 0.716                             |       | 34.64                                                                                                         |       | 31.07                                                                                                   |       | 31.74                                                                                 |       | 28.47                                                       |       | 48.70                                                                     |       | 43.66                                                                     |       | 34.79              |       | 31.18                                                                        |       | 29.31              |       | 26.26 |   | 41.88 |   | 37.55 |   | n/a |   | 32.14 |   | 34.36 |   | 44.23 |   |
| 2004                                                                                                                                |       | 1.8                 |       | 0.770                             |       | 44.90                                                                                                         |       | 41.38                                                                                                   |       | 41.26                                                                                 |       | 38.02                                                       |       | 57.46                                                                     |       | 52.96                                                                     |       | 39.39              |       | 36.31                                                                        |       | 31.59              |       | 29.11 |   | 49.52 |   | 45.64 |   | n/a |   | 34.70 |   | 39.97 |   | 53.94 |   |
| 2005                                                                                                                                |       | 2.2                 |       | 0.826                             |       | 60.27                                                                                                         |       | 56.58                                                                                                   |       | 58.74                                                                                 |       | 55.14                                                       |       | 73.52                                                                     |       | 69.02                                                                     |       | 45.84              |       | 43.03                                                                        |       | 36.29              |       | 34.07 |   | 60.47 |   | 56.77 |   | n/a |   | 43.04 |   | 51.80 |   | 69.57 |   |
| 2006                                                                                                                                |       | 2.0                 |       | 0.882                             |       | 69.01                                                                                                         |       | 66.22                                                                                                   |       | 68.95                                                                                 |       | 66.16                                                       |       | 76.30                                                                     |       | 73.21                                                                     |       | 52.49              |       | 50.36                                                                        |       | 43.62              |       | 41.84 |   | 64.88 |   | 62.26 |   | n/a |   | 43.85 |   | 60.18 |   | 75.41 |   |
| 2007  (e)                                                                                                                           |       | 2.1                 |       | 0.935                             |       | 73.82                                                                                                         |       | 72.24                                                                                                   |       | 74.04                                                                                 |       | 72.46                                                       |       | 78.69                                                                     |       | 77.02                                                                     |       | 54.30              |       | 53.15                                                                        |       | 45.33              |       | 44.37 |   | 67.74 |   | 66.30 |   | n/a |   | 46.85 |   | 58.35 |   | 77.33 |   |
| 2008  Q1                                                                                                                            |       | 2.0                 |       | 1.000                             |       | 92.00                                                                                                         |       | 92.00                                                                                                   |       | 90.50                                                                                 |       | 90.50                                                       |       | 91.10                                                                     |       | 91.10                                                                     |       | 61.95              |       | 61.95                                                                        |       | 51.66              |       | 51.66 |   | 79.26 |   | 79.26 |   | 22.73 |   | 58.30 |   | 72.88 |   | 92.92 |   |
| 2008  Q2                                                                                                                            |       | 2.0                 |       | 1.000                             |       | 92.00                                                                                                         |       | 92.00                                                                                                   |       | 90.50                                                                                 |       | 90.50                                                       |       | 91.10                                                                     |       | 91.10                                                                     |       | 65.59              |       | 65.59                                                                        |       | 56.39              |       | 56.39 |   | 79.26 |   | 79.26 |   | 22.73 |   | 58.30 |   | 72.88 |   | 92.92 |   |
| 2008  Q3                                                                                                                            |       | 2.0                 |       | 1.000                             |       | 92.00                                                                                                         |       | 92.00                                                                                                   |       | 90.50                                                                                 |       | 90.50                                                       |       | 91.10                                                                     |       | 91.10                                                                     |       | 65.59              |       | 65.59                                                                        |       | 56.39              |       | 56.39 |   | 79.26 |   | 79.26 |   | 21.01 |   | 58.30 |   | 72.88 |   | 92.92 |   |
| 2008  Q4                                                                                                                            |       | 2.0                 |       | 1.000                             |       | 92.00                                                                                                         |       | 92.00                                                                                                   |       | 90.50                                                                                 |       | 90.50                                                       |       | 91.10                                                                     |       | 91.10                                                                     |       | 61.95              |       | 61.95                                                                        |       | 51.66              |       | 51.66 |   | 79.26 |   | 79.26 |   | 24.46 |   | 58.30 |   | 72.88 |   | 92.92 |   |
| 2008  Full Year                                                                                                                     |       | 2.0                 |       | 1.000                             |       | 92.00                                                                                                         |       | 92.00                                                                                                   |       | 90.50                                                                                 |       | 90.50                                                       |       | 91.10                                                                     |       | 91.10                                                                     |       | 63.77              |       | 63.77                                                                        |       | 54.02              |       | 54.02 |   | 79.26 |   | 79.26 |   | 22.73 |   | 58.30 |   | 72.88 |   | 92.92 |   |
| 2009                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 86.28                                                                                                         |       | 88.00                                                                                                   |       | 84.80                                                                                 |       | 86.50                                                       |       | 85.39                                                                     |       | 87.10                                                                     |       | 59.78              |       | 60.97                                                                        |       | 50.60              |       | 51.61 |   | 74.29 |   | 75.78 |   | 25.49 |   | 55.74 |   | 69.68 |   | 88.84 |   |
| 2010                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 80.74                                                                                                         |       | 84.00                                                                                                   |       | 79.30                                                                                 |       | 82.50                                                       |       | 79.87                                                                     |       | 83.10                                                                     |       | 55.91              |       | 58.17                                                                        |       | 47.28              |       | 49.19 |   | 69.49 |   | 72.30 |   | 25.66 |   | 53.18 |   | 66.48 |   | 84.76 |   |
| 2011                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 77.27                                                                                                         |       | 82.00                                                                                                   |       | 75.86                                                                                 |       | 80.50                                                       |       | 76.42                                                                     |       | 81.10                                                                     |       | 53.50              |       | 56.77                                                                        |       | 45.22              |       | 47.98 |   | 66.49 |   | 70.56 |   | 25.66 |   | 51.90 |   | 64.88 |   | 82.72 |   |
| 2012                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 75.76                                                                                                         |       | 82.00                                                                                                   |       | 74.37                                                                                 |       | 80.50                                                       |       | 74.92                                                                     |       | 81.10                                                                     |       | 52.45              |       | 56.77                                                                        |       | 44.33              |       | 47.98 |   | 65.18 |   | 70.56 |   | 25.66 |   | 51.90 |   | 64.88 |   | 82.72 |   |
| 2013                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 74.27                                                                                                         |       | 82.00                                                                                                   |       | 72.91                                                                                 |       | 80.50                                                       |       | 73.46                                                                     |       | 81.10                                                                     |       | 52.15              |       | 57.58                                                                        |       | 44.42              |       | 49.04 |   | 63.91 |   | 70.56 |   | 25.66 |   | 51.90 |   | 64.88 |   | 82.72 |   |
| 2014                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 72.81                                                                                                         |       | 82.00                                                                                                   |       | 71.48                                                                                 |       | 80.50                                                       |       | 72.01                                                                     |       | 81.10                                                                     |       | 51.85              |       | 58.39                                                                        |       | 44.48              |       | 50.09 |   | 62.65 |   | 70.56 |   | 26.35 |   | 51.90 |   | 64.88 |   | 82.72 |   |
| 2015                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 71.39                                                                                                         |       | 82.00                                                                                                   |       | 70.08                                                                                 |       | 80.50                                                       |       | 70.60                                                                     |       | 81.10                                                                     |       | 51.54              |       | 59.20                                                                        |       | 44.53              |       | 51.15 |   | 61.42 |   | 70.56 |   | 26.94 |   | 51.90 |   | 64.88 |   | 82.72 |   |
| 2016                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 70.00                                                                                                         |       | 82.02                                                                                                   |       | 68.72                                                                                 |       | 80.52                                                       |       | 69.23                                                                     |       | 81.12                                                                     |       | 51.23              |       | 60.03                                                                        |       | 44.56              |       | 52.21 |   | 60.23 |   | 70.57 |   | 27.52 |   | 51.91 |   | 64.89 |   | 82.74 |   |
| 2017                                                                                                                                |       | 2.0                 |       | 1.000                             |       | 70.00                                                                                                         |       | 83.66                                                                                                   |       | 68.75                                                                                 |       | 82.16                                                       |       | 69.25                                                                     |       | 82.76                                                                     |       | 51.25              |       | 61.24                                                                        |       | 44.59              |       | 53.29 |   | 60.25 |   | 72.00 |   | 28.11 |   | 52.97 |   | 66.21 |   | 84.42 |   |
| 2018+                                                                                                                               |       | 2.0                 |       | 1.000                             |       | 70.00                                                                                                         |       | +2.0%/yr                                                                                                |       | 68.75                                                                                 |       | +2.0%/yr                                                    |       | 69.25                                                                     |       | +2.0%/yr                                                                  |       | 51.25              |       | +2.0%/yr                                                                     |       | 44.59              |       | +2.0%/yr |   | 60.25 |   | +2.0%/yr | ** ** | Escalate  at 2.0% per year |   |
| Historical  futures contract price is an average of the daily settlement price of the  near month contract over the calendar month. |       |

** **

**Table 2**GLJPetroleum Consultants**Natural Gas and Sulphur Price Forecast**Effective January 1, 2008

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

 

21

----

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

 

Unless otherwise stated, the gas price referencepoint is the receipt point on the applicable provincial gas transmission systemknown as the plant gate.

 

The plant gate pricerepresents the price before raw gas gathering and processing charges arededucted.

 

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

 

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

 

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

 

## **RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NETREVENUE**

 

### ***Reserves Reconciliation***

### *** ***

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

 

**RECONCILIATIONOF COMPANY GROSS RESERVES AT DECEMBER 31, 2007BY PRINCIPAL PRODUCT TYPE**

** **

**FORECASTPRICES AND COSTS**

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

 

22

----

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

 

## **UNDEVELOPED RESERVES**

 

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

 

## **SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVESDATA**

 

The process of estimating reserves is complex. It requires significantjudgments and decisions based on available geological, geophysical,engineering, and economic data. These estimates may change substantially asadditional data from ongoing development activities and production performancebecomes available and as economic conditions impacting oil and gas prices andcosts change. The reserve estimates contained herein are based on currentproduction forecasts, prices and economic conditions. The Corporation’sreserves are evaluated by GLJ, an independent engineering firm.

 

Although every reasonable effort is made to ensure that reserveestimates are accurate, reserve estimation is an inferential science. As aresult, the subjective decisions, new geological or production information anda changing environment may impact these estimates. Revisions to reserveestimates can arise from changes in year-end oil and gas prices, and reservoirperformance. Such revisions can be either positive or negative.

 

## **FUTURE DEVELOPMENT COSTS**

 

The table below sets out the development costs deducted in theestimation of future net revenue attributable to proved reserves (using bothconstant prices and costs and forecast prices and costs) and proved plusprobable reserves (using forecast prices and costs only).

 

23

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

 

The Corporation expects to fund its future development from internallygenerated cash flow from operations, debt (where deemed appropriate) and newequity issues (if available on favourable terms). In addition, the Corporationmay consider farm-out arrangements for certain projects. The Corporation doesnot expect that the cost of funding could make the development of a propertyuneconomic for the Corporation, nor is it expected that the cost of suchfunding 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 whichthe Corporation has a working interest as at December 31, 2007.

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

 

## **PROPERTIES WITH NO ATTRIBUTED RESERVES**

 

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

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

 

----

Note:

 

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

 

24

----

 

## **EXPIRATIONS AND WORK COMMITMENTS**

 

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

 

### ***Work Commitments Offshore NovaScotia (Marquis, Mariner, Mayflower, Marauder, Marconi)***

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

 

Note:                   In Trinidad and Tobago, for Block 5(c), thereis a confidential work commitment guarantee that is part of the confidentialPSC between the Government of the Republic of Trinidad and Tobago and CanadianSuperior. It is anticipated that this work commitment will be more than fullymet during the ongoing drilling program.

 

## **UNDEVELOPED LAND DUE TO EXPIRE**

 

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

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

 

----

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

 

## **FORWARD CONTRACTS AND FUTURE COMMITMENTS**

 

The Corporation periodically enters into commodity sales agreements andcertain derivative financial instruments to reduce its exposure to commodityprice volatility. These financial instruments are entered into solely forhedging purposes and are not used for trading or other speculative purposes. AtDecember 31, 2007, the Corporation had no contracts in place.

 

## **ADDITIONAL INFORMATION CONCERNING ABANDONMENT ANDRECLAMATION COSTS**

 

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

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

 

25

----

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

 

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

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

 

The Corporation estimates the costs to abandon and reclaim all its shutin and producing wells, facilities, gas plants and pipelines. The Corporation’smodel for estimating the amount and timing of future abandonment andreclamation expenditures was done on an operating area level. Estimatedexpenditures for each operating area are based on the Alberta Energy andUtilities Board methodology, which details the cost of abandonment andreclamation in each specific geographic region. Each region was assigned anaverage cost per well to abandon and reclaim the wells in that area. Facilityreclamation costs are scheduled to be incurred in the year following the end ofthe reserve life of its associated reserves. The Corporation will be liable forits share of ongoing environmental obligations and for the ultimate reclamationof the properties held by it upon abandonment. Ongoing environmentalobligations are expected to be funded out of cash flow. As at December 31,2007, the Corporation expected to incur reclamation and abandonment costs in respectof 549 gross (331.4 net) wells located on its properties and assets.

 

26

----

 

## **TAX HORIZON**

 

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

 

## **DRILLING ACTIVITY**

 

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

 

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

 

----

Note:

 

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

 

## **PRODUCTION ESTIMATES**

 

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

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

 

27

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

 

## **PRODUCTION HISTORY, PRICES RECEIVED AND CAPITALEXPENDITURES**

 

The following tables summarize certain information in respect ofproduction, product prices received, royalties paid, operating expenses andresulting netback for the periods indicated below:

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

 

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Notes:

 

(1)          Before deduction ofroyalties.

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

 

For the year ended December 31, 2007, net average daily productionfrom the Corporation’s Aerial/Michichi properties was 594 bbls/d light oil and13,496 mmcf/d natural gas, or 2,843 boe/d.

 

# **INDUSTRY CONDITIONS**

# ** **

The oil and natural gas industry is subject to extensive controls andregulations governing its operations (including land tenure, exploration,development, production, refining, transportation, and marketing) imposed bylegislation enacted by various levels of government and with respect to pricingand 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 gasindustry. It is not expected that any of these controls or regulations willaffect the Corporation’s operations in a manner materially different from howthey would affect other oil and gas 

 

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companies of similar size. All current legislation is a matter of publicrecord and the Corporation is unable to predict what additional legislation oramendments may be enacted. Outlined below are some of the principal aspects oflegislation, 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 directlywith oil purchasers, with the result that the market determines the price ofoil. Oil prices are primarily based on worldwide supply and demand. Thespecific 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 intoexport contracts with terms not exceeding one year in the case of light crude oiland two years in the case of heavy crude oil, provided that an order approvingsuch 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 amaximum of 25 years) requires an exporter to obtain an export licence from theNEB and the issuance of such licence requires the approval of the Governor inCouncil.

 

The price of natural gas is determined by negotiation between buyers andsellers. Natural gas exported from Canada is subject to regulation by the NEBand the Government of Canada. Exporters are free to negotiate prices and otherterms with purchasers, provided that the export contracts must continue to meetcertain 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 to20 years (in quantities of not more than 30,000 m3/day), must be made pursuantto an NEB order. Any natural gas export to be made pursuant to a contract oflonger duration (to a maximum of 25 years) or a larger quantity requires anexporter to obtain an export licence from the NEB and the issuance of suchlicence requires the approval of the Governor in Council.

 

The governments of Alberta, British Columbia, Saskatchewan and NovaScotia also regulate the volume of natural gas that may be removed from thoseprovinces for consumption elsewhere based on such factors as reserveavailability, transportation arrangements, and market considerations.

 

## **PIPELINE CAPACITY**

 

Although pipeline expansions are ongoing, the lack of firm pipelinecapacity continues to affect the oil and natural gas industry and limit theability to produce and to market natural gas production. In addition, thepro-rationing of capacity on the inter-provincial pipeline systems alsocontinues 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 governmentsof Canada, United States of America, and Mexico became effective on January 1,1994. NAFTA carries forward most of the material energy terms that arecontained in the Canada United States Free Trade Agreement. In the context ofenergy resources, Canada continues to remain free to determine whether exportsof energy resources to the United States or Mexico will be allowed, providedthat any export restrictions do not: (i) reduce the proportion of energyresources exported relative to domestic use (based upon the proportionprevailing in the most recent 36 month period); (ii) impose an exportprice higher than the domestic price subject to an exception with respect tocertain voluntary measures which only restrict the volume of exports; and (iii) disruptnormal channels of supply. All three countries are prohibited from imposingminimum or maximum export or import price requirements, provided, in the caseof export price requirements, prohibition in any circumstances in which anyother form of quantitative restriction is prohibited, and in the case ofimport-price requirements, such requirements do not apply with respect toenforcement of countervailing and anti-dumping orders and undertakings.

 

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

 

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disciplines on regulators to ensure fair implementation of anyregulatory changes and to minimize disruption of contractual arrangements andavoid 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 andregulations which govern land tenure, royalties, production rates,environmental protection, and other matters. The royalty regime is asignificant factor in the profitability of crude oil, natural gas liquids,sulphur, and natural gas production. Royalties payable on production from landsother than Crown lands are determined by negotiations between the mineral ownerand the lessee, although production from such lands is subject to certainprovincial taxes and royalties. Crown royalties are determined by governmentalregulation and are generally calculated as a percentage of the value of thegross production. The rate of royalties payable generally depends in part onprescribed reference prices, well productivity, geographical location, fielddiscovery date, method of recovery, and the type or quality of the petroleumproduct produced. Other royalties and royalty-like interests are, from time totime, carved out of the working interest owner’s interest through non-publictransactions. These are often referred to as overriding royalties, grossoverriding royalties, net profits interests, or net carried interests.

 

Occasionally the governments of the Western Canadian provinces createincentive programs for exploration and development. Such programs often providefor royalty rate reductions, royalty holidays, and tax credits, and aregenerally introduced when commodity prices are low. The programs are designedto encourage exploration and development activity by improving earnings and cashflow within the industry. Royalty holidays and reductions would reduce theamount of Crown royalties paid by oil and gas producers to the provincialgovernments and would increase the net income and funds from operations of suchproducers. However, the trend in recent years has been for provincialgovernments to eliminate, amend or allow such incentive programs to expirewithout renewal, and consequently few such incentive programs are currentlyoperative.

 

The Canadian federal corporate income tax rate levied on taxable incomeis 22.1% effective January 1, 2007 for active business income includingresource income. With the elimination of the corporate surtax effective January 1,2008 and other rate reductions introduced in the 2006 Federal Budget, and notwithdrawn in the 2007 Federal Budget, the federal corporate income tax ratewill decrease to 19% in three steps: 20.5% on January 1, 2008, 20% on January 1,2009 and 19% on January 1, 2010.

 

### ***Alberta***

### *** ***

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

 

The Alberta government introduced in 1992 a Third Tier Royalty with abase rate of 10% and a rate cap of 25% for oil pools discovered after September 1,1992. The new oil royalty reserved to the Crown has a base rate of 10% and arate cap of 30%. The old oil royalty reserved to the Crown has a base rate of10% and a rate cap of 35%.

 

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

 

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

 

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

 

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

 

On October 25, 2007,the Government of Alberta unveiled a new royalty regime. The new regime willintroduce new royalties for conventional oil, natural gas and bitumen effectiveJanuary 1, 2009 that are linked to price and production levels and willapply to both new and existing oil sands projects and conventional oil and gasactivities.

 

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

 

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

 

Under the new royaltyregime, natural gas royalties will be set by a sliding rate formula sensitiveto price and production volume. New natural gas royalty rates will range from5% to 50% with rate caps once the price of natural gas reaches $17.50/mmbtu.Royalties for natural gas liquids will be set at 40% for pentanes and 30% forbutanes and propane.

 

The implementation of theproposed changes to the royalty regime in Alberta is subject to certain risksand uncertainties. The significant changes to the royalty regime require newlegislation, changes to existing legislation and regulation and development ofproprietary software to support the calculation and collection of royalties.Additionally, certain proposed changes contemplate further public and/or industryconsultation. There may be modifications introduced to the proposed royaltystructure prior to the implementation thereof.

 

The Corporation expects theeconomics of production from its properties will be acceptable under the newroyalties. This is due, in part, to the potential decreased industry activityleading to reduced costs of services, which would offset the potential nominaldecline in rates of return due to a higher royalty.

 

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### *** ***

### ***British Columbia***

### *** ***

Producers of oil and natural gas in the Province of British Columbia arerequired to pay annual rental payments with respect to the Crown leases androyalties and freehold production taxes in respect of oil and gas produced fromCrown and freehold lands. The amount payable as a royalty in respect of oildepends on the type of oil, the value of the oil, the quantity of oil producedin a month, and the vintage of the oil. Generally, the vintage of oil is basedon the determination of whether the oil is produced from a pool discoveredbefore 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 ratesare 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 valueapplicable (exempt wells). Oil produced from newly discovered pools may beexempt from the payment of a royalty for the first 36 months of production or11,450m3 produced, whichever comes first; and the royalties for third-tier oilare the lowest reflecting the higher costs of exploration and extraction thatthe producers would incur. The royalty payable on natural gas is determined bya sliding scale based on a reference price, which is the greater of the priceobtained by the producer, and a prescribed minimum price. However, when thereference price is below the select price (a parameter used in the royalty rateformula), the royalty rate is fixed. As an incentive for the production andmarketing of natural gas, which may have been flared, natural gas produced inassociation with oil has a lower royalty then the royalty payable onnon-conservation gas.

 

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

 

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

 

Some of the financial incentives in the Strategy include:

 

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

 

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

 

On February 27, 2007 the Government of British Columbia unveiledthe Energy Plan outlining the Province’s strategy towards the environment andwhich includes targeting for zero net greenhouse gas emissions, promoting newinvestments in innovation, and becoming the world’s leader in sustainableenvironmental management. With regards to the oil and gas industry theobjective is to achieve clean energy through conservation and energy efficientpractices, whilst competitiveness is advocated in order to attract investmentfor the development of the oil and gas sector. Among the changes to beimplemented are: (i) a new Net Profit Royalty Program; (ii) thecreation of a Petroleum Registry; (iii) the establishing of aninfrastructure royalty program (combining roads and pipelines); (iv) theelimination of routine flaring at producing wells; (v) the creation ofpolicies and measures for the reduction of emissions; (vi) the developmentof unconventional resources such as tight gas and coal bed gas; and (vii) newthe Oil and Gas Technology Transfer Incentive Program that encourages theresearch, development and use of innovative technologies to increase recoveriesfrom existing reserves and promotes responsible development of new oil and gasreserves.

 

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### *** ***

### ***Saskatchewan***

### *** ***

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

 

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

 

The amount payable as a royalty in respect of natural gas is determinedby a sliding scale based on a reference price (which is the greater of theamount obtained by the producer and a prescribed minimum price), the quantityproduced in a given month, the type of natural gas, and the vintage of thenatural gas. As an incentive for the production and marketing of natural gaswhich may have been flared, the royalty rate on natural gas produced inassociation with oil is less than on non-associated natural gas. The royaltyand 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 andvaries between the base royalty rate of 5% for “fourth tier gas” and 20% for “oldgas”. 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 royaltyand tax regime in Saskatchewan:

 

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

 

A modified system of incentive volumes and maximum royalty/tax ratesapplicable to the initial production from oil wells and gas wells with afinished drilling date on or after October 1, 2002, was introduced. Theincentive volumes are applicable to various well types and are subject to amaximum 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 wellroyalty/tax categories. All horizontal oil wells with a finished drilling dateon or after October 1, 2002, will receive the “fourth tier” royalty/ taxrates and new incentive volumes.

 

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

 

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

 

## **LAND TENURE**

 

Crude oil and natural gas located in the western provinces is ownedpredominantly by the respective provincial governments. Provincial governmentsgrant 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 setforth in provincial legislation including requirements to perform specific workor make payments. Oil and natural gas located in such provinces can also beprivately owned and rights to explore for and produce such oil and natural gasare granted by lease on such terms and conditions as may be negotiated.

 

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## **ENVIRONMENTALREGULATION**

 

The oil and natural gas industry is currently subject to environmentalregulations pursuant to a variety of provincial and federal legislation. Suchlegislation provides for restrictions and prohibitions on the release oremission of various substances produced in association with certain oil and gasindustry operations. In addition, such legislation requires that well andfacility sites be abandoned and reclaimed to the satisfaction of provincialauthorities.

 

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

 

Environmental legislation in the Province of Alberta has beenconsolidated into the Environmental Protection and Enhancement Act (Alberta)(the “EPEA”), which came into force on September 1, 1993, and the Oil andGas Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose stricterenvironmental standards, require more stringent compliance, reporting and monitoringobligations, and significantly increased penalties. In 2006, the AlbertaGovernment enacted regulations pursuant to the EPEA to specifically targetsulphur oxide and nitrous oxide emissions from industrial operations includingthe oil and gas industry. No additional expenses are foreseen that areassociated with complying with the new regulations. The Corporation will becommitted to meeting its responsibilities to protect the environment whereverit operates and anticipates making increased expenditures of both a capital andan expense nature as a result of the increasingly stringent laws relating tothe protection of the environment, and will be taking such steps as required toensure compliance with the EPEA and similar legislation in other jurisdictionsin which it operates. We believe that we are in material compliance withapplicable environmental laws and regulations. We also believe that it isreasonably likely that the trend towards stricter standards in environmentallegislation 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 majorenergy projects into a single environmental assessment process with publicparticipation 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 gasemissions to 6% below 1990 “business-as-usual” levels between 2008 and 2012.Given revised estimates of Canada’s normal emissions levels, this targettranslates into an approximately 40% gross reduction in Canada’s currentemissions. It remains uncertain whether the Kyoto target of 6% below 1990emission levels will be enforced in Canada. The Federal Government hasintroduced legislation aimed at reducing greenhouse gas emissions using an “intensitybased” approach, the specifics of which have yet to be determined. Bill C-288,which is intended to ensure that Canada meets its global climate changeobligations 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 beenannounced, 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 andgas industry during the past several years that appear to be shaping the nearfuture of the business.

 

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

 

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

 

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

 

The impact on the oil and gas industry from commodity price volatilityis significant. During periods of high prices, producers generate sufficientcash flows to conduct active exploration programs without external capital.Increased commodity prices frequently translate into very busy periods forservice suppliers triggering premium costs for their services. Purchasing landand properties similarly increase in price during these periods. During lowcommodity price periods, acquisition costs drop, as do internally generatedfunds to spend on exploration and development activities. With decreaseddemand, the prices charged by the various service suppliers also decline.

 

A second trend within the Canadian oil and gas industry is the fairlyconsistent “renewal” of private and small junior oil and gas companies startingup business. These companies often have experienced management teams fromprevious industry organizations that have disappeared as a part of the ongoingindustry consolidation. Many are able to raise capital and recruit well qualifiedpersonnel. The Corporation will have to compete with these companies and othersto attract qualified personnel.

 

A third trend currently affecting the oil and gas industry is the impacton capital markets caused by investor uncertainty in the North Americaneconomy. The capital market volatility in Canada has also been affected byuncertainties surrounding the economic impact that the Protocol, and otherenvironmental initiatives, will have on the sector. On October 31, 2006the federal government imposed a distribution tax on distributions to investorsin income trusts and publicly traded partnerships (also known as “specifiedinvestment flow-through” entities, or “SIFTs”), and thereby effectivelyeliminated the tax efficacy of SIFTS as investment vehicles.  Existing SIFTs were generally grandfathereduntil 2011.  These business structureshad been attractive to investors primarily because distributions were not taxedprior to receipt by the investors, which enabled the investors to obtain agreater return on their invested funds. Under the October 31, 2006distribution tax, SIFTs will be liable for tax at a rate consistent with thetaxes 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 2011deadline. Although the October 31, 2006 distribution tax will not affectthe method in which the Corporation will be taxed, it may have an impact on theability of a SIFT to purchase producing assets from junior oil and gascompanies (as well as the price that a SIFT is willing to pay for such anacquisition) thereby affecting exploration and production companies’ ability tobe sold to a SIFT, a plan which has been a common “exit strategy” in recentyears for small to mid-sized oil and gas companies. This may be a benefit forthe Corporation as it will compete with SIFTs for the acquisition of oil andgas properties from junior producers. However, it may also limit theCorporation’s ability to sell producing properties or pursue an exit strategy.

 

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

 

# **RISK FACTORS**

# ** **

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

 

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## **EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS**

 

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

 

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

 

Management will evaluate exploration and development prospects on anongoing basis in a manner consistent with industry standards. The long-termcommercial success of the Corporation depends on its ability to find, acquire,develop and commercially produce oil and natural gas reserves. No assurance canbe given that the Corporation will be able to locate satisfactory propertiesfor acquisition or participation. Moreover, if such acquisitions orparticipations are identified, the Corporation may determine that currentmarkets, terms of acquisition and participation or pricing conditions make suchacquisitions or participations uneconomic.

 

Future oil and gas exploration may involve unprofitable efforts, notonly from dry wells, but from wells that are productive but do not produce sufficientnet 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 ofdrilling, completion and operating costs. In addition, drilling hazards orenvironmental damage could greatly increase the cost of operations, and variousfield operating conditions may adversely affect the production from successfulwells. These conditions include delays in obtaining governmental approvals orconsents, shut-ins of connected wells resulting from extreme weatherconditions, insufficient storage or transportation capacity or other geologicaland mechanical conditions. While close well supervision and effectivemaintenance operations can contribute to maximizing production rates over time,production delays and declines from normal field operating conditions cannot beeliminated and can be expected to adversely affect revenue and cash flow levelsto varying degrees.

 

In addition, oil and gas operations are subject to the risks of exploration,development and production of oil and natural gas properties, includingencountering unexpected formations or pressures, premature declines ofreservoirs, blow-outs, cratering, sour gas releases, fires and spills. Lossesresulting from the occurrence of any of these risks could have a materiallyadverse effect on future results of operations, liquidity and financialcondition.

 

## **SUBSTANTIAL CAPITAL REQUIREMENTS AND LIQUIDITY**

 

The Corporation anticipates that it will make substantial capitalexpenditures for the acquisition, exploration, development and production ofoil and natural gas reserves in the future. If the Corporation’s revenues orreserves decline, the Corporation may have limited ability to expend thecapital necessary to undertake or complete future drilling programs. There canbe no assurance that debt or equity financing, or cash generated by operationswill be available or sufficient to meet these requirements or for othercorporate purposes or, if debt or equity financing is available, that it willbe on terms acceptable to the Corporation. Moreover, future activities mayrequire the Corporation to alter its capitalization significantly. Theinability of the Corporation to access sufficient capital for its operationscould have a material adverse effect on the Corporation’s financial condition,results of operations or prospects.

 

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## **ADDITIONAL FUNDING REQUIREMENTS**

 

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

 

## **ISSUANCE OF DEBT**

 

From time to time the Corporation may enter into transactions to acquireassets or the shares of other corporations. These transactions may be financedpartially or wholly with debt, which may increase the Corporation’s debt levelsabove industry standards. Neither the Corporation’s articles nor its by-lawslimit the amount of indebtedness that the Corporation may incur. The level ofthe Corporation’s indebtedness from time to time could impair the Corporation’sability to obtain additional financing in the future on a timely basis to takeadvantage of business opportunities that may arise.

 

## **PRICES, MARKETS AND MARKETING OF CRUDE OIL AND NATURALGAS**

 

Oil and natural gas are commodities whose prices are determined based onworld demand, supply and other factors, all of which are beyond the control ofthe Corporation. World prices for oil and natural gas have fluctuated widely inrecent years. Any material decline in prices could result in a reduction of netproduction revenue. Certain wells or other projects may become uneconomic as aresult of a decline in world oil prices and natural gas prices, leading to areduction in the volume of the Corporation’s oil and gas reserves. TheCorporation 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’sfuture net production revenue, causing a reduction in its oil and gasacquisition and development activities. In addition, bank borrowings availableto the Corporation are in part determined by the borrowing base of theCorporation. A sustained material decline in prices from historical averageprices could limit the Corporation’s borrowing base, therefore reducing thebank credit available to the Corporation, and could require that a portion ofany then existing bank debt of the Corporation be repaid.

 

In addition to establishing markets for its oil and natural gas, theCorporation must also successfully market its oil and natural gas toprospective buyers. The marketability and price of oil and natural gas whichmay be acquired or discovered by the Corporation will be affected by numerousfactors beyond its control. The Corporation will be affected by thedifferential between the price paid by refiners for light quality oil and thegrades of oil produced by the Corporation. The ability of the Corporation tomarket its natural gas may depend upon its ability to acquire space onpipelines which deliver natural gas to commercial markets. The Corporation willalso likely be affected by deliverability uncertainties related to theproximity of its reserves to pipelines and processing facilities and related tooperational problems with such pipelines and facilities and extensivegovernment regulation relating to price, taxes, royalties, land tenure,allowable production, the export of oil and natural gas and other aspects ofthe oil and natural gas business.

 

## **INSURANCE**

 

The Corporation’s involvement in the exploration for and development ofoil and natural gas properties may result in the Corporation becoming subjectto liability for pollution, blow-outs, property damage, personal injury orother hazards. Although the Corporation has obtained insurance in accordancewith industry standards to address such risks, such insurance has limitationson liability that may not be sufficient to cover the full extent of suchliabilities. In addition, such risks may not, in all circumstances be 

 

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insurable or, in certain circumstances, the Corporation may elect not toobtain insurance to deal with specific risks due to the high premiumsassociated with such insurance or other reasons. The payment of such uninsuredliabilities would reduce the funds available to the Corporation. The occurrenceof a significant event that the Corporation is not fully insured against, orthe insolvency of the insurer of such event, could have a material adverseeffect on the Corporation’s financial position, results of operations orprospects.

 

## **LEGAL PROCEEDINGS**

 

Litigation may be time consuming, expensive, and distracting from theconduct of our business, and the outcome of litigation may be difficult topredict. The Corporation is unable to determine the ultimate aggregate amountof monetary liability or financial impact in these legal matters, which unlessotherwise specified, seek damages of indeterminate amounts. The Corporationcannot determine whether these matters will, individually or collectively, havea material adverse effect on our business, results or operations and financialcondition. To the extent expenses incurred in connection with litigation or anypotential regulatory proceeding or action (which may include substantial feesof attorneys and other professional advisors and potential obligations toindemnify officers and directors who may be parties to such actions) are notcovered by available insurance, such expenses could adversely affect our cashposition. The Corporation, and any of our named directors or officers, intendto vigorously defend these actions suits, claims, proceedings andinvestigations. The Corporation may in the future be subject to  other litigation arising in the normal courseof our business.

 

## **ENVIRONMENTAL RISKS**

 

All phases of the oil and natural gas business present environmentalrisks and hazards and are subject to environmental regulation pursuant to avariety of international conventions and national, provincial and municipallaws and regulations. Environmental legislation provides for, among otherthings, restrictions and prohibitions on spills, releases or emissions ofvarious substances produced in association with oil and gas operations. Thelegislation also requires that wells and facility sites be operated,maintained, abandoned and reclaimed to the satisfaction of applicableregulatory authorities. Compliance with such legislation can requiresignificant expenditures and a breach may result in the imposition of fines andpenalties, some of which may be material. The Corporation believes that it isin substantial compliance with existing legislation. Environmental legislationis evolving in a manner expected to result in stricter standards andenforcement, larger fines and liability and potentially increased capitalexpenditures and operating costs. The discharge of oil, natural gas or otherpollutants into the air, soil or water may give rise to liabilities togovernments and third parties and may require the Corporation to incur costs toremedy such discharge. No assurance can be given that environmental laws willnot result in a curtailment of production or a material increase in the costsof production, development or exploration activities or otherwise adverselyaffect the Corporation’s financial condition, results of operations orprospects.

 

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

 

## **CANADIAN TAX CONSIDERATIONS**

 

As the Corporation is engaged in the oil and natural gas business itsoperations are subject to certain unique provisions of the Income Tax Act(Canada) and applicable provincial income tax legislation relating tocharacterization of costs incurred in their businesses which effects whethersuch costs are 

 

38

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deductible and, if deductible, the rate at which they may be deductedfor the purposes of calculating taxable income. The Corporation has reviewedits historical income tax returns with respect to the characterization of thecosts incurred in the oil and natural gas business as well as other mattersgenerally applicable to all corporations including the ability to offset futureincome against prior year losses. The Corporation has filed or will file allrequired income tax returns and believes that it is full compliance with theprovisions of the Income Tax Act (Canada) and applicable provincial income taxlegislation, but such returns are subject to reassessment. In the event of asuccessful reassessment of the Corporation it may be subject to a higher thanexpected past or future income tax liability as well as potentially interestand penalties and such amount could be material.

 

## **EXCHANGE RATE RISKS**

 

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

 

## **COMPETITION**

 

The Corporation actively competes for reserve acquisitions, explorationleases, licences and concessions and skilled industry personnel with asubstantial number of other oil and gas companies, many of which havesignificantly greater financial resources than the Corporation. The Corporation’scompetitors include major integrated oil and natural gas companies and numerousother independent oil and natural gas companies and individual producers andoperators.

 

The oil and gas industry is highly competitive. The Corporation’scompetitors for the acquisition, exploration, production and development of oiland natural gas properties, and for capital to finance such activities, includecompanies that have greater financial and personnel resources available to themthan the Corporation.

 

Certain of the Corporation’s customers and potential customers arethemselves exploring for oil and gas, and the results of such explorationefforts could affect the Corporation’s ability to sell or supply oil or gas tothese customers in the future. The Corporation’s ability to successfully bid onand acquire additional property rights, to discover reserves, to participate indrilling opportunities and to identify and enter into commercial arrangementswith customers will be dependent upon developing and maintaining close workingrelationships with its future industry partners and joint operators and itsability to select and evaluate suitable properties and to consummatetransactions in a highly competitive environment.

 

## **RESERVE REPLACEMENT**

 

The Corporation’s future oil and natural gas reserves, production, andcash flows to be derived therefrom are highly dependent on the Corporationsuccessfully acquiring or discovering new reserves. Without the continualaddition of new reserves, any existing reserves the Corporation may have at anyparticular time and the production therefrom will decline overtime as suchexisting reserves are exploited. A future increase in the Corporation’sreserves will depend not only on the Corporation’s ability to develop anyproperties it may have from time to time, but also on its ability to select andacquire suitable producing properties or prospects. There can be no assurancethat the Corporation’s future exploration and development efforts will resultin the discovery and development of additional commercial accumulations of oiland natural gas.

 

## **RELIANCE ON OPERATORS AND KEY EMPLOYEES**

 

To the extent the Corporation is not the operator of its oil and naturalgas properties, the Corporation will be dependent on such operators for thetiming of activities related to such properties and will largely be unable todirect or control the activities of the operators. In addition, the success ofthe Corporation will be 

 

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

 

## **PERMITS AND LICENSES**

 

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

 

## **ROYALTIES, INCENTIVES AND PRODUCTION TAXES**

 

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

 

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

 

## **LAND TENURE**

 

Crude oil and natural gas located in the western provinces is ownedpredominantly by the respective provincial governments. Provincial governmentsgrant rights to explore for and produce oil and natural gas pursuant to leases,licences and permits for varying terms and on conditions set forth inprovincial legislation including requirements to perform specific work or makepayments. Oil and natural gas located in such provinces can also be privatelyowned and rights to explore for and produce such oil and natural gas are grantedby 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 itsfreehold properties and cannot guarantee or certify that a defect in the chainof title may not arise to defeat the Corporation’s interest in certain of suchproperties. Remediation of title problems could result in additional costs andlitigation. If title defects are unable to be remedied, the Corporation maylose some of its interest in the disputed properties resulting in reducedproduction.

 

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

 

## **MULTI-JURISDICTIONAL LEGAL RISKS**

 

The Corporation is incorporated under the laws of the Province ofAlberta, Canada, and all but one of the Corporation’s directors and all of itsofficers are residents of Canada. Consequently, it may be difficult for UnitedStates investors to effect service of process within the United States upon theCorporation or upon those directors or officers who are not residents of theUnited States, or to realize in the United States upon judgments of UnitedStates courts predicated upon civil liabilities under the Securities ExchangeAct of 1934, as amended (United States). Furthermore, it may be difficult forinvestors to enforce judgments 

 

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of the U.S. courts based on civil liability provisions of the U.S.federal securities laws in a Canadian court against the Corporation or any ofthe Corporation’s non-U.S. resident executive officers or directors. There issubstantial doubt whether an original lawsuit could be brought successfully inCanada against any of such persons or the Corporation predicated solely uponsuch civil liabilities.

 

## **RESERVE INFORMATION**

 

The reserve and recovery information contained in the GLJ Report areonly estimates and the actual production and ultimate reserves from theCorporation’s properties may be greater or less than the estimates prepared insuch report. The GLJ Report has been prepared using certain commodity priceassumptions which are described in the notes to the reserve tables. If lowerprices for crude oil, natural gas liquids and natural gas are realized by the Corporationand substituted for the price assumptions utilized in the report, the presentvalue of estimated future net cash flows for the Corporation’s reserves wouldbe reduced and the reduction could be significant, particularly based on theconstant price case assumptions. Exploration for oil and natural gas involvesmany risks, which even a combination of experience and careful evaluation maynot be able to overcome. There is no assurance that further commercialquantities 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 financingor other transactions involving the issuance of securities of Canadian Superiorwhich may be dilutive.

 

## **CORPORATE MATTERS**

 

To date, the Corporation has not declared any dividends payable on itsoutstanding common shares. The Board of Directors of the Corporation willconsider the Corporation’s dividend policy from time to time to assess whetherthe declaration of dividends payable on its outstanding common shares isappropriate. Certain of the directors and officers of the Corporation are alsodirectors and officers of other oil and gas companies involved in naturalresource exploration and development, and conflicts of interest may arisebetween their duties as officers and directors of the Corporation and asofficers and directors of such other companies. Such conflicts must bedisclosed in accordance with, and are subject to such other procedures and remediesas apply under the Business Corporations Act (Alberta).

 

# **DIVIDENDS**

# ** **

To date, the Corporation has not declared any dividends payable on itsoutstanding Common Shares. The Board of Directors of the Corporation willconsider the Corporation’s dividend policy from time to time to assess whetherthe declaration of dividends payable on its outstanding common shares isappropriate.

 

# **DESCRIPTION OF CAPITAL STRUCTURE**

# ** **

The Corporation’s authorized share capital consists of an unlimitednumber 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 atall meetings of shareholders (except meetings at which only holders of aspecified class or series of shares are entitled to vote) and are entitled toone vote per share. The holders of Common Shares are entitled to receive suchdividends as the Board of Directors may declare and, upon liquidation, toreceive such assets of Canadian Superior as are distributable to holders of CommonShares.

 

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## **PREFERRED SHARES**

 

The Preferred Shares may be issued in one or more series with eachseries to consist of such number of shares as may, before the issue of theseries, be fixed by the directors of the Corporation. The directors areauthorized, before the issue of the series, to determine the designation,rights, restrictions, conditions and limitations attaching to the PreferredShares of each series. The Preferred Shares of each series rank equally withrespect to the payment of dividends and the distribution of assets in the eventof liquidation, dissolution or winding-up and in priority to the Common Sharesand 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 payableon return of capital in respect of shares of a series of Preferred Shares isnot paid in full, the shares of the series are entitled to participate rateablywith the shares of any other series of the same class in respect of suchamounts.

 

## **SHAREHOLDER RIGHTS PLAN**

 

The Corporation has adopted a shareholder rights plan in accordance withthe 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 theCorporation at every third annual meeting of Shareholders. The Rights Plan waslast 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) provideShareholders adequate time to properly assess the merits of a take-over bid forthe common shares of the Corporation without undue pressure, (b) allowcompeting bids to emerge and (iii) give the board of directors of theCorporation time to consider alternatives to enable Shareholders to maximizethe value of their common shares. The Rights Plan is designed to encourage apotential acquirer to proceed either by way of a take-over bid specificallypermitted by the Rights Plan (a “Permitted Bid”) or with the approval of theboard of directors.

 

Under the Rights Plan, one right (a “Right”) is attached to each CommonShare in the capital of the Corporation. The Rights will separate from theCommon Shares and become exercisable eight trading days (the “Separation Time”)after a person acquires, or commences a take-over bid to acquire, 20% or moreof the voting shares or other securities convertible into voting shares of theCorporation, unless the Separation Time is deferred. The acquisition by anyperson (an “Acquiring Person”) of 20% or more of the Common Shares, other thanin a permitted manner, is called a “Flip-in Event”. Any Rights held by anAcquiring Person will become void upon the occurrence of a Flip-In Event.

 

After the Separation Time, each Right will permit the holder (other thanan 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 theholdings of the Acquiring Person. The Corporation anticipates that no AcquiringPerson will be willing to risk such dilution and so will instead either make atake-over bid that is permitted by the Rights Plan, negotiate with the Board ofDirectors for a waiver of the Rights Plan, or apply to regulatory authoritiesfor an order rendering the Rights Plan ineffective.

 

A person will not become an Acquiring Person, and will not trigger theseparation and ability to exercise the Rights, by becoming the beneficial ownerof 20% or more of the Common Shares pursuant to a Permitted Bid or in othercircumstances provided for under the Rights Plan. Investment advisors (forfully managed accounts), trust companies (acting in their capacities as trusteesand administrators) and statutory bodies acquiring 20% of the Common Shares areexempted 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 aFlip-In Event occurring and the Rights separating from the Common Shares,reported earnings per share on a fully diluted or non-diluted basis may beaffected. 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 willsuffer substantial dilution.

 

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This summary is qualified in its entirety by reference to the RightsPlan Agreement. Shareholders may obtain a copy of the Rights Plan Agreement onwritten 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 tradingon 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 andvolume of trading of the Common Shares as reported by the Toronto StockExchange for the periods indicated.

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

 

# **DIRECTORS AND OFFICERS**

# ** **

## **NAMES, OCCUPATIONS AND SECURITY HOLDERS**

 

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

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

 

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

 

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Notes:

 

(1)   Member ofthe Corporation’s Audit Committee.

(2)   Member ofthe Corporation’s Compensation Committee.

(3)   Member ofthe Corporation’s Disclosure Committee

(4)   Member ofthe Corporation’s Special Projects Committee.

(5)   Member ofthe Corporation’s Reserves Committee.

 

As at December 31, 2007, the number of Common Shares beneficiallyowned, directly or indirectly, or controlled by the directors and executiveofficers of the Corporation, as a group, was 2,583,387 Common Shares, being1.9% of the outstanding Common Shares of the Corporation.

 

## **CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES ORSANCTIONS**

 

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

 

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

####  

##### (a)                                  was the subject of a cease trade or similarorder, or an order that denied the issuer access to any exemption undersecurities legislation, for a period of more than 30 consecutive days;

#####  

##### 44

##### 

#####  

##### (b)           was subject to an event that resulted, afterthe director or officer ceased to be a director or officer, in the issuer beingsubject of a cease trade order or similar order or an order that denied theissuer access to any exemption under securities legislation, for a period ofmore than 30 consecutive days;

#####  

##### (c)           or, within a year of that person ceasing to actin that capacity, became bankrupt, made a proposal under any legislationrelating to bankruptcy or insolvency or was subject to or instituted anyproceedings, arrangement or compromise with creditors or had a receiver,receiver manager or trustee appointed to hold its assets.

#####  

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

####  

Further, other than as described below, to the knowledge of managementof the Corporation, no director or officer of the Corporation, or anyshareholder holding a sufficient number of securities of the Corporation toaffect materially the control of the Corporation, has been subject to:

 

#### 1.                                       any penalties or sanctions imposed by a courtrelating to securities legislation or by a securities regulatory authority orhas entered into a settlement agreement with the securities regulatoryauthority; or

####  

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

####  

On October 15, 1997, the ASC and OSC issued orders relating to asettlement agreement entered into by Canadian 88, Mr. Noval and two otherparties (the “Respondents”) in respect of their involvement in a take-over bidmade in early 1997 by Canadian 88 for the common shares of Morrison PetroleumsLtd., a corporation whose common shares were listed on the TSX and the MontrealStock Exchange. In a joint submission with the ASC and the OSC, the Respondentsagreed that their actions and the public statements of Mr. Noval on behalfof Canadian 88 were contrary to the public interest. Under the terms of thesettlement agreement, Canadian 88 was required to make a $200,000 payment tothe ASC and was reprimanded by the OSC. Mr. Noval was prohibited fromtrading securities and from relying on most exemptions available under thesecurities legislation of Alberta and Ontario for a period of 12 months.

 

## **CONFLICTS OF INTEREST**

 

Certain of the directors and officers of the Corporation are directorsand/or officers of other private and public companies. Some of these privateand public companies may, from time to time, be involved in businesstransactions or banking relationships which may create situations in whichconflicts might arise. Any such conflicts shall be resolved in accordance withthe procedures and requirements of the relevant provisions of the BusinessCorporations Act (Alberta), including the duty of such directors and officersto act honestly and in good faith with a view to the best interests of theCorporation.

 

# **LEGAL PROCEEDINGS**

 

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

 

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# **INTERESTS OF MANAGEMENT AND OTHERS IN MATERIALTRANSACTIONS**

 

Within the last three financial years or the current financial year ofthe Corporation, other than as disclosed herein, none of the directors orofficers of the Corporation or any person that beneficially owns, directly orindirectly, or who exercises control or direction over, more than 10% of theoutstanding securities of the Corporation, and no associate or affiliate of anysuch persons, has or has had any material interest in any transaction or anyproposed transaction which materially affects Corporation or any of itsaffiliates.

 

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

 

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

 

In November 2004, the Corporation entered into participationagreements in respect of the Corporation’s offshore Nova Scotia and offshoreTrinidad and Tobago prospects with a company controlled by Mr. Noval atthe time. Pursuant to the participation agreements, the Corporation has theright to participate on a promoted basis for 16 2/3% of Canadian Superior’scosts of the offshore Nova Scotia wells (this was subsequently increased to 331/3%) and the company controlled by Mr. Noval has the right to participateon a promoted basis for 33 1/3% of Canadian Superior’s costs of certain earningwells in Trinidad and Tobago.

 

The transactions described in this section were in the normal course ofoperations and agreed to by the related company and the Corporation based onextensive negotiations and Board approval and approval by the Corporation.

 

# **TRANSFER AGENT AND REGISTRAR**

 

Valiant Trust Company at 310, 606 - 4th Street SW Calgary, Alberta, T2P1T1, is the transfer agent and registrar for the Common Shares.

 

# **INTERESTS OF EXPERTS**

 

There is no person or company whose profession or business givesauthority to a statement made by such person or company and who is named ashaving prepared or certified a statement, report or valuation described orincluded in a filing, or referred to in a filing, made under NationalInstrument 51-102 by the Corporation during, or related to, the Corporation’smost recently completed financial year other than GLJ, the Corporation’sindependent engineering evaluator and Meyers Norris Penny LLP, the Corporation’sauditors. Neither GLJ nor any of directors, officers or employees had anyregistered or beneficial interests, direct or indirect, in any securities orother property of the Corporation or of the Corporation’s associates oraffiliates either at the time they prepared the statement, report or valuationprepared by it nor at any time thereafter, nor are any securities or otherproperty 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 ofprofessional conduct in a jurisdiction of Canada.

 

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In addition, none of the aforementioned persons or companies, nor anydirector, officer or employee of any of the aforementioned persons orcompanies, is or is expected to be elected, appointed or employed as adirector, officer or employee of the Corporation or of any associate oraffiliate of the Corporation.

 

# **AUDIT COMMITTEE**

 

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

 

## **MANDATE OF THE AUDIT COMMITTEE**

 

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

 

#### 1.                                       the integrity of the Corporation’s financialstatements;

####  

#### 2.                                       the integrity of the financial reportingprocess;

####  

#### 3.                                       the system of internal control and managementof financial risks;

####  

#### 4.                                       the external auditors’ qualifications andindependence; and

####  

#### 5.                                       the external audit process and the Corporation’sprocesses for monitoring compliance with laws and regulations.

####  

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

 

## **RELEVANT EDUCATION AND EXPERIENCE OF AUDIT COMMITTEEMEMBERS**

 

The following is a brief summary of the education or experience of eachmember of the Audit Committee that is relevant to the performance of hisresponsibilities as a member of the Audit Committee, including any education orexperience that has provided the member with an understanding of the accountingprinciples used by the Corporation.

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

 

## **AUDIT COMMITTEE OVERSIGHT**

 

At no time since the commencement of the Corporation’s most recentlycompleted financial year has a recommendation of the Audit Committee tonominate or compensate an external auditor not been adopted by the Board ofDirectors of the Corporation.

 

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## **EXTERNAL AUDITOR FEES**

 

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

 

## **AUDIT FEES**

 

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

 

## **AUDIT-RELATED FEES**

 

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

 

## **TAX FEES**

 

Tax fees include fees relating to tax compliance, tax planning, taxadvice and various taxation matters. The aggregate tax fees billed by theCorporation’s external in each of the last two financial years were $7,420 in2007 and $6,400 in 2006.

 

## **ALL OTHER FEES**

 

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

 

# **ADDITIONAL INFORMATION**

# ** **

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

 

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**APPENDIX “A”**

 

**FORM 51-101F2**

**REPORT ON RESERVES DATA**

**BY**

**INDEPENDENT QUALIFIED RESERVES**

**EVALUATOR OR AUDITOR**

 

 

 

**This is the form referredto 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 whichmeaning is ascribed in *NI 51-101* havethe same meaning in this form 1.

 

2.                             Thereport on *reserves data*referred to in item 2 ofsection 2.1 of *NI 51-101*, to be executed by oneor more *qualified reserves evaluator**or auditors independent* of the*reportingissuer,* must in all material respects be as follows:

 

**Report on Reserves Data**

 

 

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

 

1.                             We haveprepared an evaluation of the Company’s reserves data as at December 31, 2007.The reserves data are estimates of proved reserves and probable reserves andrelated future net revenue as at December 31, 2007, estimated using forecastprices and costs.

 

2.                             Thereserves data are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on the reserves data based on ourevaluation.

 

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

 

3.                             Thosestandards require that we plan and perform an evaluation to obtain reasonableassurance as to whether the reserves data are free of material misstatement. Anevaluation also includes assessing whether the reserves data are in accordancewith principles and definitions presented in the COGE Handbook.

 

4.                             Thefollowing table sets forth the estimated future net revenue (before deductionof income taxes) attributed to proved plus probable reserves, estimated usingforecast 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 endedDecember 31, 2007, and identifies the respective portions thereof that we haveaudited, evaluated, and reviewed and reported on to the Company’s board ofdirectors:

 

 

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

 

 

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

 

6.                             We haveno responsibility to update our reports referred to in paragraph 4 for eventsand circumstances occurring after their respective preparation dates.

 

7.                             Becausethe reserves data are based on judgments regarding future events, actualresults will vary and the variations may be material. However, any variationsshould be consistent with the fact that reserves are categorized according tothe probability of their recovery.

 

 

EXECUTED as to our report referred to above:

 

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

 
| (Signed)  “Dana B. Laustsen, P. Eng.” |   |
|-------------------------------------------------|--------|
| Executive  Vice President                       |   |

 

 

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**APPENDIX “B”**

 

**Report of Management and Directorson Reserves Data and Other Information**

 

Management of Canadian Superior Energy Inc.(the “Corporation”) are responsible for the preparation and disclosure ofinformation with respect to the Corporation’s oil and gas activities inaccordance with securities regulatory requirements. This information includesreserves data which are estimates of proved reserves and probable reserves andrelated future net revenue as at [last day of the reporting issuer’s mostrecently completed financial year], estimated using forecast prices and costs.

 

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

 

The Reserves Committee of the board ofdirectors of the Corporation has

 

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

 

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

 

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

 

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

 

(a)                                 the content and filing with securitiesregulatory authorities of Form 51-101F1 containing reserves data and otheroil and gas information;

 

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

 

(c)                                 the content and filing of this report.

 

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

 

DATED   March 30, 2008.

 

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

 

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

 

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**APPENDIX “C”**

 

**CHARTER OF THE AUDIT COMMITTEE OF THEBOARD OF DIRECTORS OF CANADIAN SUPERIOR ENERGY INC.**

 

**Purpose/Objectives**

 

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

 

#### 1.                                      the integrity of the Corporation’s financialstatements;

####  

#### 2.                                      the integrity of the financial reportingprocess;

####  

#### 3.                                      the system of internal control and managementof financial risks the external auditors’ qualifications and independence; and

####  

#### 4.                                      the external audit process and the Corporation’sprocess for monitoring compliance with laws and regulations.

####  

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

 

**Authority**

 

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

 

#### 1.                                      seek any information it requires from anyemployee of the Corporation (whose employees are directed to cooperate with anyrequest made by the Committee);

####  

#### 2.                                      seek any information it requires directly fromexternal parties including the external auditors and independent reservoirengineering firm; and

####  

#### 3.                                      obtain outside legal or professional advicewithout seeking Board approval (however providing  notice to the Chair of the Board).

####  

**Organization**

 

The following provisions and regulationsshall apply to the composition of the Committee:

 

#### 1.                                      the Committee shall consist of three members ofthe Board of the Corporation;

####  

#### 2.                                      the members of the Committee shall beindependent members of the Board as defined in section 1.4 of MultilateralInstrument 52-110 Audit Committees, as well as Part 1, section 121(A) ofthe AMEX Company manual;

####  

#### 3.                                      the Chairman of the Committee shall bedetermined by the Board;

####  

#### 4.                                      two members of the Committee shall constitute aquorum thereof;

 

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#### 5.                                      no business shall be transacted by theCommittee except at a meeting of its members at which a quorum is present inperson or by telephone or by a resolution in writing signed by all members ofthe Committee;

####  

#### 6.                                      the meetings and proceedings of the Corporationthat 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 theindependent reservoir engineering firm as it may see fit, to attend itsmeetings and take part in the discussion and consideration of the affairs ofthe Committee; and

####  

#### 8.                                      meetings shall be held not less than four timesper year, generally coinciding with the release of interim or year-endfinancial information including consecutive sessions with Management and theExternal Auditors.

####  

Special meetings may be convened as requiredupon the request of the Committee. The external auditors and independentreservoir engineering firm may convene a meeting if they consider that it isdesirable or necessary; and the proceedings of all meetings will be minuted.

 

**Duties and Responsibilities**

 

The Board hereby delegates and authorizesthe Committee to carry out the following duties and responsibilities to theextent 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 quarterlyand annual financial statements, MD&A and annual reports of theCorporation;

####  

#### 2.                                      review of internal control systems maintainedby the Corporation;

####  

#### 3.                                      review of significant accounting and taxcompliance issues where there is choice among various alternatives or whereapplication of a policy has a significant effect on the financial results ofthe Corporation;

####  

#### 4.                                      review of significant proposed non-recurringevents such as mergers, acquisitions or divestitures; and

####  

#### 5.                                      review of press releases or other publiclycirculated documents containing financial information.

####  

***External Auditors***

 

#### 1.                                      retain and/or terminate the external auditors(subject to regulatory and shareholder notification) who, in turn, will reportdirectly to the Audit Committee;

####  

#### 2.                                      review the terms of the external auditors’engagement and the appropriateness and reasonableness of the proposedengagement fees;

####  

#### 3.                                      annually, obtain and review a certificateattesting to the external auditors’ independence, identifying all relationshipsbetween the external auditors and the Corporation;

####  

#### 4.                                      annually, evaluate the external auditors’qualifications, performance and independence;

####  

#### 5.                                      annually, to assure continuing auditors’ independence,consider the rotation of the lead audit partner or the external audit firm;

 

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#### 6.                                      pre-approve engagements for non-audit servicesprovided by the external auditors or their affiliates together with estimatedfees and potential issues of independence; and

####  

#### 7.                                      review hiring policies for employees or formeremployees of the external auditors.

####  

***Audit***

 

#### 1.                                      review the audit plan for the coming year withthe external auditors and with management;

####  

#### 2.                                      review with management and the externalauditors any proposed changes in major accounting policies, the presentationand impact of significant risks and uncertainties, and key estimates andjudgments of management that may be material to financial reporting;

####  

#### 3.                                      query management and the external auditorsregarding significant financial reporting issues during the fiscal period andthe method of resolution;

####  

#### 4.                                      review any problems experienced by the externalauditors in performing the audit, including any restrictions imposed bymanagement of significant accounting issues in which there was a disagreementwith management;

####  

#### 5.                                      review audited annual financial statements andquarterly financial statements with management and the external auditors(including disclosures under “Management Discussion and Analysis”), in

####  

#### 6.                                      conjunction with the report of the externalauditors and obtain explanation from management of all significant variancesbetween comparative reporting periods; and

####  

#### 7.                                      review the auditors’ report to management,containing recommendations of the external auditors, and management’s responseand subsequent remedy of any identified weaknesses.

####  

**Other Duties and Responsibilities**

 

#### 1.                                      The responsibilities, practices and duties ofthe Committee outlined herein are not intended to be comprehensive. The Boardmay, from time to time charge the Committee with the responsibility ofreviewing items of a financial or control, risk management or reserves nature.

####  

#### 2.                                      The Committee shall periodically report to theBoard 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 regardingaccounting, internal accounting controls, or auditing matters.

####  

#### 4.                                      The Committee shall monitor the confidential,anonymous submissions by employees of concerns regarding questionableaccounting or auditing matters.

 

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